2015 General Rate Case Rebuttal Testimony Public ... - sce.com...1 SCE’s accounting for capital costs (installation and removal) complies with GAAP and 2 FERC’s Uniform System

Application No.: A.13-11-003 Exhibit No.: SCE-26, Vol. 02 Witnesses: J. Carrillo

R. Fisher P. Hunt P. Wong

(U 338-E)

2015 General Rate Case

Rebuttal Testimony

Public Version

Results of Operations (R/O) Volume 2 – Plant, Taxes, Depreciation Expense and Reserve, and Rate Base

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaSeptember 2014

SCE-26: Results of Operations (R/O) Volume 2 – Plant, Taxes, Depreciation Expense and Reserve, and Rate

Base Table Of Contents

Section Page Witness

-i-

I. DEPRECIATION ..............................................................................................1 R. Fisher

A. Depreciation and Intergenerational Equity ............................................3

B. TURN and ORA’s Proposals Fail to Accomplish the Purpose of Depreciation .........................................................................4

1. SCE’s Proposed Depreciation Rates Are Built on a Solid Foundation ........................................................................6

2. SCE’s Proposals Achieve the Objectives of Gradualism .................................................................................7

3. Gradualism Should Be Based On an Informed Decision Fully Understanding the Impacts to Future Customers ..................................................................................8

C. SCE is Compliant With the Commission’s 2012 Decision .................10

1. Depreciation Compliance Items ...............................................10

2. ORA and TURN’s Position .....................................................10

3. SCE Provided More Information on Cost of Removal ...................................................................................11

4. SCE’s Proposals Are Not Outliers ...........................................12

5. TURN Makes Inappropriate Industry Comparison’s ...............14

6. Additional Studies or Reviews are Unnecessary and Not Value-Added .....................................................................16

7. Cost of Removal Ratios are Based on Utility Specific Costs ...........................................................................16

8. Studies and Analyses Are a Cost of Service ............................17

9. SCE’s Accounting for Cost of Removal is Appropriate ..............................................................................18


Base

Table Of Contents (Continued) Section Page Witness

-ii-

a) Regulatory Requirements for Accounting for Cost of Removal ..........................................................18

b) SCE’s Capital Accounting Methods have been Audited and Found Reasonable ...........................19

c) TURN’s History of Rejected Accounting Proposals ......................................................................20

D. SCE’S Decommissioning Estimates are Appropriate ..........................22

1. TURN’s and ORA’s Decommissioning Proposals ..................22

2. TURN’s No-Inflation Method Has Been Repeatedly Rejected by the Commission ...................................................23

a) Pebbly Beach ...............................................................24

E. Production Lives are Appropriate ........................................................26

1. Peakers .....................................................................................26

2. Mountainview ..........................................................................27

3. Solar Photovoltaic ....................................................................28

4. Mohave Generating Station .....................................................28

F. Conclusion ...........................................................................................29

II. TAXES .............................................................................................................30 P. Wong

A. Summary of Rebuttal to TURN ...........................................................30

B. Federal Repair Deductions ...................................................................30

1. SCE Has the Responsibility to Comply with Changing Tax Authority to Legally Minimize its Tax Burden...............................................................................31


Base


-iii-

2. Adjustments Can Cut Both Ways And The Commission Has Previously Held That Absent A Memorandum Account, A Utility Cannot “True Up” A Prior Year’s Ratemaking To Match A Subsequent Adjustment ...........................................................32

3. TURN’s Proposed Adjustments Are Retroactive Ratemaking ..............................................................................32

a) The Commission Has Previously Rejected An After-The-Fact Attempt To Match Ratemaking Taxes With Paid Taxes ............................32

b) The Commission Similarly Restricts A Utility From Recovering Tax Obligations Paid In Prior Years .......................................................33

c) Rates May Only Be Set Prospectively .........................35

4. The Commission’s Longstanding Ratemaking Policy Has Been To Flow-Through All Income Tax Deductions Except Where Otherwise Required By Law ..........................................................................................35

5. SCE’s Tax Filing Actions and Regulatory Treatment were Proper and Appropriate ..................................36

a) SCE’s Repair Deductions Were Prudent and Appropriate ..................................................................36

b) The Repair Deduction Landscape Was Evolving .......................................................................38

c) SCE’s 2012 GRC Application .....................................38

d) The “Safe-Harbor” Provision of Revenue Procedure 2011-43 .......................................................39

e) SCE’s Analysis Of The Impact Of Electing The Safe-Harbor Provision ..........................................40


Base


-iv-

f) SCE Could Not Have Reflected The Safe Harbor Election In Its 2012 GRC ................................41

g) SCE Adopted The Safe Harbor As Soon As It Determined The Tax Benefits Of Doing So .................................................................................41

6. The Commission Has The Discretion To Switch To A Policy Of Normalizing All Deductions But Should Only Do So Prospectively And Consistently ..............43

C. State Tax Depreciable Lives For Advanced Meters ............................44

1. TURN Proposes “to Disgorge” SCE’s 2013 and 2014 Rates Established and Approved in D. 12-11-051............................................................................................44

2. TURN’s Proposal On Advanced Meters Is Also Retroactive Ratemaking ...........................................................44

III. RATE BASE ....................................................................................................46 J. Carrillo

A. Customer Advances .............................................................................46

1. SCE Position ............................................................................46

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

a) Electric Construction ...................................................46

3. TURN Position ........................................................................46

a) Electric Construction ...................................................46

b) Temporary Services .....................................................46

4. SCE’s Rebuttal .........................................................................46

1. SCE’s Rebuttal .........................................................................48

a) SCE’s Forecast Methods utilizing Five-Year Averages are Reasonable .............................................48


Base


-v-

B. Materials And Supplies ........................................................................51

1. ORA Position ...........................................................................51

Transmission and Distribution M&S .......................................51

2. SCE’s Rebuttal .........................................................................52

a) ORA’s Proposed Reduction Calculation Is Arbitrary, Contradictory, Has No Basis and Results in an Insufficient T&D M&S Balance .........................................................................52

b) SCE’s Regression Analysis Is Reasonable ..................53

c) M&S-Related Rate Base Adjustments .........................54

C. Working Cash – Operational Cash ......................................................55

1. ORA Position ...........................................................................55

2. TURN Position ........................................................................56

a) Prepayments .................................................................56

b) Other Accounts Receivable ..........................................56

(1) Other Accounts Receivable for Non-Tariffed Products and Services and Reserves for Uncollectibles .............................56

(2) Accounts Receivable from PBOPs Trust .................................................................56

c) Long-Term Incentives ..................................................57

3. SCE’s Rebuttal .........................................................................57

a) SCE’s Minimum Cash Balance Should Be Included in Working Cash ...........................................57

b) Prepayments .................................................................58


Base


-vi-

c) Other Accounts Receivable ..........................................58

(1) Other Accounts Receivable for Non-Tariffed Products and Services and Reserves for Uncollectibles .............................58

(2) Accounts Receivable from PBOPs Trust .................................................................58

d) Long-Term Incentives ..................................................59

D. Lead Lag Study ....................................................................................59

1. ORA Position ...........................................................................59

a) ORA’s Adjustment to Income Tax Lags .....................59

(1) Federal Income Tax (FIT) Lag Days ...............59

(2) California Corporate Franchise Tax (CCFT) Lag Days ............................................59

2. TURN Position ........................................................................60

a) Revenue Lag ................................................................60

b) Purchased Power Lag Days .........................................60

c) Labor Lag Days ............................................................60

d) Income Tax Lag Days ..................................................61

3. SCE’s Rebuttal .........................................................................61

a) ORA’s and TURN’s Income Tax Lag Proposals are Arbitrary and Unsupported. ...................61

b) Revenue Lag Days .......................................................62

c) Purchased Power Lag Days .........................................64

d) Labor Lag Days ............................................................65


Base


-vii-

IV. CUSTOMER DEPOSITS ................................................................................66 P. Hunt

A. Introduction ..........................................................................................66

1. TURN Presents an Inaccurate View of Short-term Interest Rates ............................................................................66

2. Customer Deposits Are Debts, and Are Not Like Accruals or Other Working Cash Adjustments .......................67

3. TURN’s Assertions about Financial Risk are Conjecture ................................................................................68

4. Customer Deposits Are Debt, Not Equity ................................69

5. Differences between PG&E and SCE Do Not Invalidate SCE’s Position that Customer Deposits Should Be Excluded from Rate Base .......................................69

6. Conclusion: SCE’s Customer Deposits Should Not Be Excluded from Rate Base ...................................................70

Appendix A Accounting Literature

Appendix B Supplemental Studies on the Impact of Depreciation on Revenue Requirement

Appendix C Supporting Calculations

Appendix D Data Requests

Appendix E Testimony from Other Rate Cases

Appendix F Rate Base


Base

List Of Figures Figure Page

-viii-

Figure II-1 The Straight-Line Remaining-Life Accrual Calculation ...........................................................3

Figure II-2 Incremental T&D Capital Cost Allocation Deferral Maintaining Authorized

Rates, TURN’s or ORA’s Proposals ......................................................................................................5

Figure II-3 Recorded Composite Net Salvage Ratios With SCE & TURN Proposals ................................6

Figure II-4 Composite Depreciation Rates for T&D (non-land) Assets ......................................................8

Figure II-5 Simplified Depreciation Expense Calculation ...........................................................................9

Figure III-6 Quartile Ranking of SCE’s T&D Net Salvage Proposals Compared to

Industry Experience By Account .........................................................................................................13

Figure III-7 Cost of Removal Ratio Calculation........................................................................................17

Figure VIII-8 Original Application Study* ...............................................................................................49

Figure VIII-9 Recorded Customer Advance Receipts/Meter Sets .............................................................50


Base

List Of Tables Table Page

-ix-

Table V-1 Life Proposals by Generating Facility ......................................................................................26

Table V-2 Comparison of SCE and FPL Solar Technology ......................................................................28

Table VIII-3 2013 Customer Advances – Electric Construction EOY Balance Actual to

Forecast Comparison (Nominal $000) ................................................................................................47

Table VIII-4 Comparison – Actual to Recent GRC Forecasts of Construction Customer

Advance Balances ($000 Nominal Average Balances) ......................................................................48

Table VIII-5 Average Customer Advances 2013 Forecast Compared to Actual (Nominal

Average Balances - $ Million) .............................................................................................................49

Table VIII-6 Recorded T&D M&S Growth (Nominal Weighted Average Balances,

$000) ....................................................................................................................................................53

Table VIII-7 2013 Recorded vs. Forecast T&D M&S (Nominal Weighted Average

Balances, $000) ....................................................................................................................................53

Table VIII-8 M&S Accounting Adjustments (ORA’s Recommendation, $000) ......................................55

Table VIII-9 GHG Revenue Billing Lag Weighting Factors Recalculated (Nominal

Average Balances, $000) .....................................................................................................................63

Table VIII-10 SmartConnectTM Offset Equivalent Revenue Lag Impact ('000s - Nominal) ....................64

Table VIII-11 Composite Revenue Lag Days Recalculated ......................................................................64

1

I. 1

DEPRECIATION 2

SCE retained Dane Watson from Alliance Consulting Group to conduct a Depreciation Study 3

that determines service lives and net salvage for all other SCE assets.1 Mr. Watson’s rebuttal 4

testimony responds to the specific ORA and TURN proposals about the Depreciation Study and the 5

compliance items resulting from the 2012 GRC.2 This testimony rebuts ORA’s and TURN’s 6

alternative depreciation parameters and rate proposals made in response to my direct testimony.3 7

The following summarizes SCE’s rebuttal in this volume: 8

� Depreciation rates set the allocation period for capital costs, not the level of costs. ORA 9

and TURN frame SCE’s depreciation rates as “excessive,” which is inaccurate since the 10

Commission’s depreciation method ensures the allocation of actual capital cost incurred, 11

no more, no less. 12

� The lower depreciation rates proposed by the parties do not allocate costs appropriately 13

and thus defer costs to future customers and yield a higher total cost of service (through 14

higher rate base and its associated return). ORA and TURN offer no good reason to defer 15

costs to future customers. 16

� SCE is the only party in this proceeding that conducted a depreciation study. ORA’s and 17

TURN’s proposals are based on a review of our depreciation study. Mr. Watson’s direct 18

and rebuttal testimonies provide a thorough narrative of the steps he took to understand 19

SCE’s data, assets, and operations. 20

� SCE complied with all Commission depreciation directives in D.12-11-051. ORA and 21

TURN interpret additional requirements not specified in D.12-11-051 and claim SCE did 22

not comply with these unspecified requirements. In addition, ORA and TURN 23

recommend additional reviews at shareholder cost, which is unfounded. 24

1 SCE-10, Vol. 2, p. 24. 2 SCE-26, Vol. 3. 3 CAL-SLA supports ORA’s net salvage proposal for Account 373. To the extent SCE’s rebuttal testimony

addresses ORA’s proposals for Account 373 that discussion also applies to CAL-SLA. Mr. Fisher’s direct testimony is in SCE-10, Vol. 2, Chapter 3.

2

� SCE’s accounting for capital costs (installation and removal) complies with GAAP and 1

FERC’s Uniform System of Accounts. The primary basis for TURN’s net salvage 2

recommendations is its opinion that SCE allocates too much of the cost of replacement to 3

the cost of removal. TURN’s support for this assertion is an irrelevant comparison of 4

SCE to an electric utility in rural Texas. 5

� TURN’s and ORA’s net salvage proposals disregard SCE’s recorded data and experience. 6

TURN and ORA attempt to cast doubt on SCE’s recorded data to rationalize their 7

proposals for lower current depreciation rates. 8

� TURN’s “no-inflation” proposal for decommissioning is inappropriate and has been 9

previously rejected by this Commission multiple times.10

3

A. Depreciation and Intergenerational Equity 1

The purpose of depreciation expense is to allocate the capital costs of a long-term asset in a 2

systematic and rational manner.4 Depreciation does not set the level of costs incurred, only the 3

period in which these costs are recovered.5 In this way, depreciation is a “process of allocation, not 4

valuation.”6 As shown in Figure I-1, the Commission’s prescribed depreciation system of straight-5

line, remaining life accrual ensures SCE will not recover capital costs exceeding total cost incurred.7 6

Figure I-1 The Straight-Line Remaining-Life Accrual Calculation

�� !��"�� #�$�

The depreciation system prescribed by the Commission is self-adjusting for any over- or 7

under-allocation of capital costs in the depreciation rates. This adjustment is accomplished by 8

flowing through the variance between depreciation rates used for allocation purposes and realized 9

depreciation rates over the remaining life of the asset accounts. 10

Two primary factors prevent the over-allocation of costs. First, the Accumulated 11

Depreciation (second factor in the numerator) reflects costs that have been allocated to-date. This 12

ensures that costs that have been previously allocated are removed from depreciation expense in 13

future periods. Second, the Commission’s triennial review of depreciation rates in the General Rate 14

4 Accounting Standards Codification (ASC) 360-10-35-4. “The cost of a productive facility is one of the

costs of the services it renders during its useful economic life. Generally accepted accounting principles (GAAP) require that this cost be spread over the expected useful life of the facility in such a way as to allocate it as equitably as possible to the periods during which services are obtained from the use of the facility. This procedure is known as depreciation accounting, a system of accounting which aims to distribute the cost or other basic value of tangible capital assets, less salvage (if any), over the estimated useful life of the unit (which may be a group of assets) in a systematic and rational manner. It is a process of allocation, not valuation.”

5 See SCE-10, Vol. 2, Table I-2 for the directory of testimony for the various areas of capital spending. 6 Id., p. 5. 7 See Exhibit A, CPUC Standard Practice (SP) U-4-W, Determination of Straight-Line Remaining Life

Depreciation Accruals.

4

Case (GRC) ensures that the formula components are updated on a regular basis and new rates are 1

applied based on the current conditions of the asset accounts. In this way, only the capital costs 2

incurred will be allocated to customers and nothing more. 3

B. TURN and ORA’s Proposals Fail to Accomplish the Purpose of Depreciation 4

Underpinning TURN’s and ORA’s proposals is the notion that SCE’s depreciation rates are 5

excessive.8 Such arguments ignore the fact that depreciation rates will not result in depreciation 6

expense exceeding total capital cost. TURN’s and ORA’s use of the word “excessive” could only 7

mean that TURN and ORA believe SCE’s proposed rates result in allocation of capital costs before 8

the end of the life of the underlying assets. Both TURN and ORA, however, offer no evidence that 9

this has occurred or will occur in the future. In fact, SCE’s experience over the past decade 10

demonstrates the opposite–SCE’s current authorized rates allocate costs after assets have been 11

removed from service.9 Additionally, the total deficit in SCE’s accumulated depreciation indicates 12

that the cumulative allocation of capital costs is not where it should be given SCE’s proposed lives 13

and net salvage. Capital costs have been under-allocated by over $800 million as of year-end 14

2012.10 The cost deferral will continue until SCE’s depreciation rates reflect the actual economics. 15

If the Commission does not adopt SCE’s proposed rates, the deferral will grow faster. 16

Figure I-2 below illustrates the additional impacts that would result from retaining SCE’s 17

authorized net salvage parameters or adopting the other parties’ proposals relative to SCE’s 18

proposed rates over 2015-2017. 19

8 TURN-10, p. 6; ORA-23, p. 9. 9 Such as Mohave Generating Station and SCE’s legacy meters. 10 See Appendix C.

5

Figure I-2 Incremental T&D Capital Cost Allocation Deferral

Maintaining Authorized Rates, TURN’s or ORA’s Proposals

$347

$628$692

$0

$200

$400

$600

$800

Authorized TURN ORA

Millions

Costs�that�will�be�deferred�to�future�customers

What is clear is that TURN and ORA, for SCE’s past four General Rate Cases, have 1

attempted to keep current rates below the underlying economics of the asset while ignoring the 2

impact that cost deferral has on future generations of ratepayers. SCE’s actual costs subsequent to 3

those SCE’s past four General Rate Cases have demonstrated the reasonableness of SCE’s proposed 4

net salvage rates, not only in those cases, but also in this current one. 5

Figure I-3 below shows the upward trend of average recorded net salvage rates from 2003 6

through 2012. 7

6

Figure I-3 Recorded Composite Net Salvage Ratios With SCE & TURN Proposals

SCE Proposed TURN ProposeAuthorized @ 48ORA Proposed-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%-66.74% -42.46% -48.17% -49.52%

SCE�Proposed

SCE�Proposed

SCE�ProposedSCE�Proposed

SCE�Proposed

TURN� Proposed

TURN� Proposed

TURN� Proposed

�120%

�100%

�80%

�60%

�40%

�20%

0%

Recorded�5�Year�Average�Net�Salvage�Ratios

TURN�proposeddifferent�allocation�methods�in�SCE's�2006�&�2009�GRCs

SCE has demonstrated in prior GRC filings that lower depreciation rates ultimately result in 1

higher costs to the customer due to the impact on rate base.11 That is, for a given level of capital 2

expenditures, the lower the depreciation rate the higher the rate base. TURN and ORA have neither 3

performed nor reported on the impact cost deferrals will have on customers over the life of assets. 4

1. SCE’s Proposed Depreciation Rates Are Built on a Solid Foundation 5

SCE’s recommended depreciation rates in this GRC are based on the proposed 6

service life and net salvage rates presented in SCE-10, Volume 3. These determinations are the 7

result of informed judgment and multiple depreciation studies, including the litigation of those 8

studies, over the last decade and more. SCE employed Alliance Consulting to perform an 9

independent depreciation study to support of life and net salvage proposals in this case. The results 10

of Mr. Watson’s study are presented in his testimony. His recommendations represent the life and 11

salvage expectations of SCE’s utility property.12 Mr. Watson has worked in the field of capital 12

11 See Appendix B. 12 SCE-10, Vol. 3.

7

accounting and depreciation for nearly 30 years. The expertise that Alliance Consulting has in 1

conducting depreciation studies in various jurisdictions provides additional context, information, and 2

independent perspective. Mr. Watson’s proposals start with the assumption that incurred costs are 3

reasonable and representative of the costs SCE expects to incur in the future, refined with expert 4

judgment, numerous site visits to SCE assets, witnessing capital replacement activities in person, and 5

many hours in discussion with SCE field personnel and engineers. 6

By using the information described above to develop unbiased proposals, Mr. 7

Watson’s recommendations in this rate case achieve the objective of depreciation and move SCE’s 8

depreciation rates closer to intergenerational equity. 9

2. SCE’s Proposals Achieve the Objectives of Gradualism 10

As ORA correctly points out,13 the Commission introduced the principle of 11

gradualism in PG&E’s 2014 GRC decision as a way to address “balanc[ing] the equities of current 12

and future ratepayers” by limiting the approved increases that would otherwise be warranted in order 13

to mitigate the short-term impact of large changes in depreciation parameters.14 SCE also recognizes 14

the importance of gradualism—SCE’s overall increase to negative net salvage rates for transmission 15

and distribution accounts is approximately 18%.15 16

ORA attempts to extend the Commission’s gradualism principle in this proceeding 17

but recommends a more stringent cap of a 10% increase from current net salvage rates, and only to a 18

small subset of the accounts.16 ORA asserts that the cap is appropriate because “SCE has done a 19

generally insufficient job of showing the reasonableness of its recommended rate increases.”17 20

Additionally, TURN suggests that its proposals are consistent with the concept of gradualism in its 21

discussion on net salvage rates for account 364.18 However, both TURN and ORA proposals would 22

13 ORA-23, p. 23. 14 Id. 15 See Appendix C. 16 ORA-23, pp. 23-45. 17 ORA-23, p. 24. 18 TURN-10, p. 75.

8

result in depreciation rates lower than currently authorized, a direct contradiction of the 1

Commission’s notion of gradualism.19 2

As shown in Figure I-4 below, SCE’s composite T&D depreciation rate is based on 3

authorized parameters is 3.64%, whereas TURN’s proposals result in a rate of 3.22% and ORA’s, 4

3.23%. 5

Figure I-4 Composite Depreciation Rates for T&D (non-land) Assets

3.64%

3.23% 3.22%

3.00%

3.10%

3.20%

3.30%

3.40%

3.50%

3.60%

3.70%

Authorized ORA TURN

11%�decrease�to�authorized

These differences in the overall rate may seem small, in the order of 40 basis points, 6

but when applied to a plant balance of some $23 billion the differences are quite significant. 7

3. Gradualism Should Be Based On an Informed Decision Fully Understanding the 8

Impacts to Future Customers 9

SCE does not dispute the value of gradually increasing depreciation rates to levels 10

that will properly allocate costs, particularly if there is concern that setting depreciation rates to 11

reflect actual asset characteristics may result in an unacceptable rate increase for the Commission. 12

However, a decision implementing a gradual increase should be made fully understanding that: 13

19 D.14-08-032.

9

� Future customers will be burdened with the cost differential resulting from the 1

difference between authorized rates and actual experience; 2

� Future customers will be burdened with additional return due to a larger rate base. 3

As discussed at the beginning of this testimony, depreciation rates only determine the 4

timing of which costs are allocated, not the ultimate amount. The Straight-Line Remaining Life 5

calculation prescribed by the Commission’s Standard Practice (SP) U-4 ensures that all capital 6

investment (whether removal or installation) be recovered through depreciation expense over the 7

remaining life of a group of assets. 8

Figure I-5 Simplified Depreciation Expense Calculation

The depreciable balance reflects the unallocated portion of capital costs. This means 9

that when capital allocation is lower than the actual cost, future depreciation expense will increase in 10

order to recover the depreciable balance (what still remains unallocated). SCE has extensively 11

analyzed on the impact that deferring cost of removal allocation to future periods has on rate base 12

and revenue requirements and presented that analysis in prior rate filings—the full report is attached 13

as Appendix B to this testimony. 14

10

C. SCE is Compliant With the Commission’s 2012 Decision 1

1. Depreciation Compliance Items 2

In SCE’s 2012 GRC decision the Commission ordered the following: 3

� “SCE shall provide testimony in its next GRC to provide more information 4

about COR [Cost of Removal] in asset accounts where SCE’s proposed NSR 5

[Net Salvage Rate] is at least 25% more than comparable industry averages.”20 6

� “SCE should review its allocation practices to be sure that all installation-7

related costs are booked to Plant-in-Service, instead of COR.” 21 8

As discussed in Mr. Fisher’s and Mr. Watson’s direct and rebuttal testimonies, SCE 9

complied with the Commission’s directives. 10

2. ORA and TURN’s Position 11

ORA asserts that SCE did not comply with either of the Commission orders. ORA 12

offers a word count metric as “empirical evidence” that SCE did not provide more information for its 13

net salvage proposals.22 ORA then proceeds to discount nearly 30 years of experience of Mr. 14

Watson as evidence that SCE’s allocation practices have not been appropriately reviewed.23 15

TURN likewise asserts that SCE did not comply with Commission directives. TURN 16

has historically requested more information that is simply not necessary.24 TURN again suggests not 17

enough information about cost of removal was provided.25 Similar to past GRCs, TURN makes 18

unsubstantiated claims that SCE is not accounting for its costs correctly.26 TURN’s allegations are, 19

in some cases, in direct conflict with GAAP and FERC accounting requirements, and in other cases, 20

unproven and rejected by this Commission.27 21

20 D.12-11-051, p. 686. 21 Id. at 683. 22 ORA-23, p. 7. 23 Id. at 10. 24 D.12-11-051, p. 684. 25 TURN-10, p. 28. 26 See Section III.C.4.c of this testimony. 27 Id.

11

3. SCE Provided More Information on Cost of Removal 1

SCE has provided more information about the cost of removal for all asset accounts, 2

thus it necessarily met the Commission’s directive to provide more information in asset accounts 3

where its net salvage rate was 25% more than comparable industry averages (See also, Mr. Watson’s 4

Rebuttal Testimony in SCE-26, Volume 3). ORA’s contention of non-compliance is premised on its 5

belief that the Commission asked SCE to perform a study to identify comparable industry net 6

salvage percentages. 7

Upon receipt of the 2012 GRC decision late in 2012, SCE was already in the midst of 8

its internal depreciation study for the 2015 General Rate Case. At that time, SCE was unaware of 9

any existing comparable industry averages for net salvage.28 In fact, SCE testified in its 2012 GRC 10

that net salvage rates are not comparable between companies due to inherent differences between 11

utilities on a myriad of factors such as: 12

� classification and composition of retirement units; 13

� accounting statistics and methods; 14

� per unit costs (i.e., labor wage rates, fuel costs, material cost, etc.); 15

� technology, types of equipment, and suppliers; 16

� climate, geography, and urban density; 17

� age of assets; and 18

� government requirements, etc. 19

To this day SCE has not found a data set that can fully account for differences such as 20

those described above.29 These differences not only apply to the cost of removal, but also the cost of 21

the original asset that was incurred decades ago (assuming the age of retirements are aligned 22

between companies, which could also be a difference). Unable to identify comparable industry 23

averages, and with little time to conduct the depreciation study for the 2015 GRC Application, SCE 24

instead elected to provide more information for all of its accounts. SCE retained a third party, Mr. 25

28 SCE is still unaware of any industry net salvage information that would appropriately consider the factors

of analysis that makes a net salvage comparison possible. That is, the unique operating circumstances and accounting for each utility, not only currently, but over the life of the assets, makes it difficult, if not impossible to get an “apples-to-apples” comparison. As such, SCE does not expect to be able to produce a set of “comparable” utility average net salvage ratios.

29 Neither ORA nor TURN have produced comparable statistics either.

12

Watson of Alliance Consulting, to perform the depreciation study for its 2015 GRC and directed Mr. 1

Watson to perform the necessary work to meet the Commission’s directives. By doing so, SCE 2

brought in outside expertise to enrich and build upon its internal depreciation analysis that 3

culminated in support of SCE’s 2003, 2006, 2009, and 2012 GRC filings. Alliance Consulting 4

further adds value by providing independent perspective and insight enhanced by the nearly 30 years 5

of depreciation and property accounting experience of the expert witness, Mr. Watson, as well as the 6

numerous years of experience within the Alliance Consulting staff. As a result, SCE provided 7

additional information and outside expert insight for all of its net salvage proposals. 8

Subsequent to submitting the 2015 GRC NOI, SCE received a data request from ORA 9

that requested “all asset accounts where proposed NSR [Net Salvage Rates] is at least 25% more 10

than comparable industry averages.”30 As discussed above and noted in its NOI testimony, SCE is 11

not aware of comparable industry statistics. After internal discussions to determine the most 12

meaningful way to respond to this request, SCE contracted Alliance Consulting to perform a study 13

that collected recorded net salvage rates that other utilities had submitted in each of their respective 14

rate filings.31 While other utilities’ net salvage rates are not comparable due to reasons stated above, 15

this data does provide an industry average based on actual recorded data, and not the authorized 16

ratios that would typically be found in FERC Form 1 submissions. However, the compliance 17

directive to provide more information was already met in SCE’s 2015 GRC Application. 18

4. SCE’s Proposals Are Not Outliers 19

The industry recorded net salvage rates (i.e., actual experienced costs) clearly show 20

that SCE net salvage proposals are not outliers, as TURN and ORA would have the Commission 21

believe.32 Figure I-6 below shows that Mr. Watson’s proposals are within the range of other utility 22

average net salvage ratios. 23

30 See response to data request DRA-00-MK3, Q. 1. 31 See Appendix D. 32 Id.

13

Figure I-6 Quartile Ranking of SCE’s T&D Net Salvage Proposals

Compared to Industry Experience By Account

0%

25%

50%

75%

100%

352 353 354 355 356 362 364 365 366 367 368 369 373

SCE�Proposed

SCE reports the industry comparisons in Appendix D to this testimony. It is clear that 1

the net salvage proposals developed by Mr. Watson, which reflect SCE’s specific circumstances and 2

experience, are not outliers. TURN’s and ORA’s efforts to dismiss or selectively adjust the data is 3

incorrect at best. TURN claims that SCE should have relied upon the net salvage rates utilities 4

proposed in the rate filings but provides no reason why that would be superior to SCE’s approach 5

other than stating “I cannot comprehend how one could construe the Commission’s directive in the 6

manner SCE has chosen.”33 Relying on other utilities proposed net salvage rates is fraught with 7

peril. For example, SCE’s proposed rates are based on a measured increase towards actual 8

economics, recognizing the need to mitigate rate impact. Other utility proposals could have similar 9

adjustments embedded. Furthermore, the proposed rates of the other utilities could be adjusted for 10

company-specific circumstance entirely irrelevant to SCE. Authorized net salvage ratios presents 11

33 TURN-10, p. 50.

14

even more problems. Use of comparisons often result in skewed statistics due to factors such as the 1

timing of when the net salvage ratios were adopted (not all utilities have a three-year rate case 2

cycle), the economic and operating environment of the region (economics may have resulted in 3

utilities or regulatory agencies adopting lower rates),34 and some adopted net salvage ratios may be 4

the outcome of settlement negotiations (which might not reflect the economics of the asset at all). 5

ORA does not dispute the source of SCE’s data, but adjusts for what it deems 6

“outliers.” The outliers that ORA removes are often the net salvage rates for PG&E and SDG&E, 7

probably the most comparable companies provided in the study results.35 In fact, the Commission 8

recognized the trend of increasing costs for net salvage for PG&E, but tempered PG&E’s 9

depreciation rate increase to mitigate customer impact.36 ORA offers no statistical support for this 10

analysis other than to state that the data are “outliers,” but it selectively adjusts only the most 11

negative outliers out of the population without consideration of “outliers” at the other end of the 12

range.37 13

5. TURN Makes Inappropriate Industry Comparison’s 14

TURN compares SCE per unit costs with those of Southwestern Public Service 15

Company (SPS).38 TURN reaches the conclusion “that SCE’s allocation of cost of removal reflects 16

an unusual position in the industry.”39 17

If comparable simply means “an electric utility owning and operating electric 18

generation and distribution facilities subject to the Uniform System of Accounts,” as TURN defines 19

it,40 then comparing SCE to SPS may seem reasonable. Indeed, both SCE and SPS are electric 20

utilities, operate generation and electric assets, and both are subject to the FERC USoA. In addition, 21

34 Commission Decisions in SCE’s 2009 and 2012 rate case did just that. 35 See Appendix D. 36 D.14-08-032, p. 11. 37 This is particularly relevant for account 352, where only a single company experiences a positive net

salvage ratio and the ratio was not removed from the analysis. If ORA’s approach treated “outliers” equitably the removal of the value would result in SCE being, once again, within 25% of the industry mean.

38 TURN-10, p. 57. 39 Id. 40 SCE-TURN-005, Q. 7b.

15

both have service territories encompassing approximately 50,000 square miles. Those 1

characteristics (none of which directly relate to the cost installing and removing assets) is where the 2

similarity ends. 3

Comparing SCE to SPS is not reasonable because the two territories are not 4

comparable. SPS’s service territory is located in the Panhandle and the South Plains of Texas, as 5

well as eastern and southern New Mexico.41 SPS’s service territory is primarily agricultural, with 6

large areas of oil and gas production.42 In contrast, SCE’s service territory is quite diverse, 7

stretching from the cooler coast areas bordering the Pacific Ocean to the hot and dry inland deserts; 8

from the agricultural areas of California’s central valley to the densely populated urban areas of Los 9

Angeles and Orange counties.43 SCE serves approximately 5 million customers, a customer density 10

of 100 customers per square mile,44 whereas, SPS serves approximately 381,000 customers, a 11

customer density of 7.62 customers per square mile.45 SCE serves 45 cities46 with populations larger 12

than 50,000 in Los Angeles and Orange Counties alone.47 The largest city that SPS serves in the 13

state of New Mexico is Roswell with a population of 48,47748. In Texas, SPS serves only one city 14

larger than 50,000, that being Amarillo with a population of 195,250.49 15

In addition, in response to a data request in a recent SPS Texas filing, SPS indicated 16

that it had not “performed internal studies identifying the appropriate allocation or treatment of costs 17

between the cost of removal and the installation of new investment when a retirement occurs.”50 18

This is the same company TURN uses to claim that SCE’s removal cost accounting is incorrect. 19

41 Texas P.U.C., Docket No. 42004, Schedule 1, p. 307. 42 Id. 43 SCE-03, Vol. 1, p. 1. 44 SCE-03, Vol. 1, p. 1. 45 Texas P.U.C., Docket No. 42004, Schedule 1 p. 307. 46 This does not account for County unincorporated areas. 47 Based on 2010 Census Data. 48 Id. 49 Id. 50 SCE-TURN-005, Q. 7e.

16

6. Additional Studies or Reviews are Unnecessary and Not Value-Added 1

Both ORA and TURN recommend that SCE perform additional studies or analysis, at 2

shareholder expense. TURN recommends that “the Commission order SCE to undertake a thorough 3

and detailed analysis of the variables contained in its allocation process at shareholder’s cost” and 4

further suggests that “the analyses should be made with advanced and ongoing coordination with and 5

input from both ORA and TURN, as parties with a longstanding interest in depreciation issues in 6

GRC’s.”51 ORA recommends that “SCE should be required to undertake a formal, independent, and 7

shareholder funded comparative study of allocation practices”52 and that “SCE be ordered to 8

undertake a formal and independent study of comparative net salvage rates at shareholder 9

expense.”53 10

TURN and ORA offer no explanation of how these studies would add value to the 11

customer. Even if the Commission were to order the recommended studies, ORA and TURN have 12

not demonstrated any reason to depart from cost-of-service ratemaking principles by shifting the 13

costs of doing so to shareholders. 14

7. Cost of Removal Ratios are Based on Utility Specific Costs 15

The basis for TURN’s and ORA’s demands for additional information and analysis 16

appears to be a belief that SCE’s net salvage rates should be lower than the industry average.54 But 17

knowing “why” the net salvage rates are different does not change the underlying cost, which is a 18

function of the capital spend addressed in other volumes of this GRC.55 As discussed above in 19

Section II, depreciation is a process of allocation; depreciation rates do not set the level of cost 20

incurred. Indeed, the cost of removal rate is simply an arithmetic function of capital costs incurred. 21

51 TURN-10, p. 57. 52 ORA-23, pp. 1-2. 53 Id. at 9. 54 SCE’s proposed net salvage rates are in the third quartile of net salvage rates across industry (Figure-I),

and yet, TURN and ORA continue to tout SCE’s proposals as “excessive.” 55 SCE-10, Vol. 2, Table I-2, p. 11 provides a directory of the various direct testimonies.

17

Figure I-7 Cost of Removal Ratio Calculation

The cost of removal dollars that SCE has incurred over the last decade are the result 1

of capital programs and projects proposed and authorized in SCE’s 2003, 2006, 2009, and 2012 2

GRCs. TURN and ORA assert that SCE’s allocation of those capital costs is incorrect, but SCE has 3

clearly demonstrated that its accounting is correct.56 The question is whether or not these historical 4

ratios are indicative of what SCE will experience in the future. Mr. Watson employed the same 5

forecasting methods that SCE has in past depreciation studies which this Commission has concluded 6

is reasonable.57 7

8. Studies and Analyses Are a Cost of Service 8

As discussed above in Section II, depreciation is a system of allocation, not valuation. 9

The level of cost of removal included in depreciation does not change the amount of capital costs 10

ultimately allocated—only the timing. This is the same for the accounting of replacement costs—11

regardless of whether cost is allocated to installation or removal, the total remains the same.58 12

Any notion that shareholders unduly benefit from higher depreciation rates is wrong. 13

In fact, lower depreciation rates will result in higher rate base over time, all else equal. It is 14

appropriate to set depreciation rates at the level that reflects the underlying economics of the asset. 15

That is, that the capital costs (installation and removal) are fully allocated over the useful life of the 16

56 See Section III. 57 D.09-03-025, p.180. 58 See Appendix B.

18

asset. This is proper cost-of-service ratemaking and ensures that customers are allocated their share 1

of costs for the service of the asset and that costs are fully recovered by the utility. Thus, any study 2

performed to ensure this objective is met is a proper cost of service. 3

9. SCE’s Accounting for Cost of Removal is Appropriate 4

As part of capital cost accounting it is necessary to book cost of removal to 5

accumulated depreciation account.59 SCE achieves this directive for its mass property accounts 6

through an allocation process that identifies total capital costs as being related to either the new 7

construction or the removal of the existing asset. In this proceeding these processes were reviewed 8

in detail by Mr. Watson which provided an unbiased and independent perspective. Additionally, the 9

capital accounting system and processes have been audited and reviewed by multiple parties, 10

including the ORA, and has been found to be appropriate with no material misstatements. 11

a) Regulatory Requirements for Accounting for Cost of Removal 12

FERC’s USoA requires a segregation of removal costs and construction 13

costs.60 SCE’s accounting practice is to charge capital costs related to the retirement of an asset to 14

cost of removal and costs related to the installation of a new asset to construction. This achieves the 15

requirement set by FERC USoA. In addition, this accounting treatment matches the description of 16

FERC Account 108, Accumulated Provision for Depreciation of Electric Plant, Paragraph B.61 17

Furthermore, FERC requires a utility to keep separate subsidiary records for the amounts related to 18

cost of removal accrued in Account 108.62 19

59 “At the time of retirement of depreciable electric plant, this account [108 – depreciation reserve] shall be

charged with the book cost of the property retired and the cost of removal…” (emphasis added) – FERC USoA in the description of account 108, paragraph B. and “The cost of removal and salvage shall be charged or credited, as appropriate to such depreciation account” - Electric Plant Instruction 10(B)(2).

60 CFR18, Part 101, Electric Plant Instruction 11(A), “all items relating to the retirements shall be kept separate from those relating to the construction…”

61 CFR 18, Part 101, “At the time of retirement of depreciable electric utility plant, this account shall be charged with the book cost of the property retired and the cost of removal…”

62 CFR 18, Part 101, FERC Account 108 Paragraph C. Separate subsidiary records shall be maintained for the amount of accrued cost of removal other than legal obligations for the retirement of plant recorded in Account 108, Accumulated provision for depreciation of electric utility plant.

19

b) SCE’s Capital Accounting Methods have been Audited and Found 1

Reasonable 2

SCE’s accounting systems and financial records are audited on a regular basis 3

for compliance with SEC requirements, Generally Accepted Accounting Principles (GAAP), and 4

regulatory accounting (FERC USoA). These audits are performed by internal auditors and various 5

external independent auditors, including ORA auditors who submit a Report on Results of 6

Examination in GRCs. 7

PricewaterhouseCoopers, LLP (PwC) performs the independent audit over 8

SCE’s accounting practices, systems, procedures and controls. This audit is conducted by 9

independently examining on a test basis, examining evidence supporting the amounts and 10

disclosures in the financial statements, assessing the accounting principles used and significant 11

estimates made by management, and evaluating the overall financial statement presentation. In 12

PwC’s opinion, the consolidated financial statements are presented fairly, in all material respects, in 13

conformity with GAAP.63 Furthermore, SCE’s FERC Form 1 is independently audited by PwC; and 14

in PwC’s opinion, the FERC Form 1 financial statements were presented fairly, in all material 15

respects, in accordance with the accounting requirements of the Federal Regulatory Commission as 16

set forth in its applicable USoA and published accounting releases.64 17

ORA Examiner Lee’s results of examination in this GRC states: “ORA’s 18

examination will address SCE’s recorded financial data that SCE used in connection with 19

forecasting its proposed revenue requirement in this application”65 and that “ORA detected no issues 20

relative to the recording of financial data to the various general ledger accounts used to compile the 21

data contained within the Federal Energy Regulatory Commission (FERC) Form 1.”66 Furthermore, 22

Examiner Lee examined SCE’s Utility Plant and had no recommended adjustments to Capital or any 23

exceptions regarding SCE’s accounting system for recorded capital transactions.67 24

63 Edison International. 2013. United States Securities and Exchange Commission form 10-K. Rosemead,

CA. 64 S.C.E. 2013. FERC Form 1. 65 ORA-26, p. 1. 66 Id. at 5. 67 Id. at 13.

20

c) TURN’s History of Rejected Accounting Proposals 1

TURN questions SCE’s accounting for cost of removal, particularly as it 2

relates to replacement costs. TURN’s accusations regarding accounting for replacement costs are 3

not new. TURN is again proposing that SCE is not recording enough of the costs associated with 4

replacement activity to plant-in-service.68 5

In SCE’s 2003 GRC, Mr. Pous, representing TURN, asserted that all 6

replacement cost be capitalized and recorded as plant-in-service, an argument contradictory with 7

FERC regulations.69 The Commission’s Decision did not even mention TURN’s assertion.70 8

TURN made the same proposal in SCE’s 2006 GRC. Mr. Majoros, 9

representing TURN, suggested the Commission consider “capitalizing the entire cost of 10

replacements to plant in service, rather than “allocating a portion to cost of removal” arguing that it 11

would have the “same effect on rate base as the company’s current accounting and would eliminate 12

the problems created by the allocation.”71 Again, this consideration was not addressed in the 13

Commission’s Decision.72 14

While TURN is not proposing these particular incorrect accounting practices 15

in this GRC, consideration of TURN’s proposals as it relates to proper accounting should be 16

considered with the proper facts. Indeed, in SCE’s 2009 GRC, Mr. Majoros, representing TURN, 17

suggested that the Commission’s Standard Practice U-4 was not accrual accounting under GAAP 18

due to the fact that it didn’t match inflation costs to periods incurred.73 The Commission rejected 19

TURN’s proposals and continued use of its Standard Practice U-4 depreciation method.74 In SCE’s 20

2012 GRC, both TURN and ORA claimed SCE’s third-party reimbursements should be booked to 21

68 TURN-10, p. 50. 69 A.02-05-004, Direct Testimony of Jacob Pous on behalf of TURN, p. 60. 70 D.04-07-022. 71 A.04-12-014, Direct Testimony of Michael J. Majoros, Jr. on behalf of TURN. 72 D.06-05-016. 73 A.07-11-011, Direct Testimony of Michael J. Majoros, Jr. on behalf of TURN, p. 18. 74 D.09-03-025, p. 178.

21

gross salvage (decreasing negative net salvage). The Commission found that SCE’s practice was 1

consistent with FERC rules, rejecting TURN’s and ORA’s proposals.75 2

SCE’s accounting for the allocation of capital costs between installation and 3

removal is appropriate and consistent with GAAP and FERC accounting rules. Any notion that 4

TURN should provide input into a review of SCE’s accounting practices should be rejected. SCE’s 5

accounting practices are already reviewed by external auditors, including the ORA. 6

75 D.12-11-051.

22

D. SCE’S Decommissioning Estimates are Appropriate 1

Decommissioning costs represent the cost to permanently retire a generating station at the 2

end of its depreciable life. These estimates are usually site specific and based on decommissioning 3

studies. SCE is proposing increases in its estimates for decommissioning its Solar Photovoltaic 4

Facilities and Pebbly Beach Diesel Generating Station. Additionally, SCE’s decommissioning 5

proposals include a refund of costs associated with decommissioning Mountain View Units 1 and 2 6

and its Solar 2 facilities. 7

1. TURN’s and ORA’s Decommissioning Proposals 8

ORA rejects SCE’s proposed decommissioning estimates for Mountainview Units 3 9

and 4, makes no recommendation for decommissioning estimates for Solar PV facilities and 10

recommends spreading the amortization of remaining Mohave costs over three years, rather than in 11

2015.76 TURN, revisiting methods already rejected by this Commission numerous times,77 proposes 12

to remove all escalation from SCE’s decommissioning estimates.78 13

ORA’s recommendations stem from its belief that “SCE appears to exhibit a pattern 14

of over-collection.”79 TURN similarly claims that SCE has “a history of significantly overestimating 15

decommissioning costs.”80 The “pattern” and “history” ORA and TURN refer to is related to the 16

recent decommissioning of SCE’s Solar 2 facility and Mountainview Units 1 and 2. As discussed 17

above, TURN and ORA do not take account of the thousands of transactions that demonstrate an 18

increasing trend in net salvage rates for transmission and distribution, but readily claim that the 19

decommissioning experience of two small projects represents a meaningful pattern. 20

76 ORA-23, pp. 2-3. 77 D.06-05-016, D.09-03-025, and D.07-03-044. Finally, in D.08-07-046 the Commission further stated

“We would therefore have denied with prejudice the recommendations of DRA, TURN, and UCAN on depreciation and net salvage in a litigated decision. The purpose of this discussion of our likely denial is to avoid an unnecessary repetition in subsequent proceedings. Any party that raises these issues again should have new analysis and new arguments which may persuade us, unlike the arguments raised here or in other recent rate proceedings.”

78 TURN-10, p. 21. 79 ORA-23, p. 45. 80 TURN-10, p. 16.

23

2. TURN’s No-Inflation Method Has Been Repeatedly Rejected by the Commission 1

TURN proposes that SCE not include inflation in its decommissioning estimates, 2

claiming that it is not supported by this Commission’s Standard Practice U-4 and that it creates 3

intergenerational inequity.81 TURN’s proposals in this regard have been repeatedly rejected by this 4

Commission in various GRCs. 5

In SCE’s 2006 GRC, TURN’s depreciation witness introduced a net present value 6

methodology as a means to defer net salvage costs into the future through a complicated discount 7

methodology. The Commission rejected the proposals and went on to say: 8

Also, if TURN wishes to reintroduce its net present value recommendation, it 9 should make a full and more detailed showing on how it would be implemented 10 and calculated for all the different classes of plant and what the long-term 11 difference is when compared to the methods used by DRA and SCE. Detailed 12 cost of removal showings in the next GRC, which address our concerns expressed 13 in today’s decision, will provide the principal guidance as to whether future net 14 salvage should be increased, be decreased, or remain the same.82 15

In the 2009 GRC, TURN introduced the discount method again and met a similar 16

conclusion from the Commission: 17

On balance, the record does not demonstrate TURN’s proposal is superior to the 18 Commission’s longstanding depreciation rate methodology and it is not adopted.83 19

With this history in mind it is surprising that TURN presents no new evidence or 20

changes in circumstance to warrant a change in longstanding Commission policies.84 TURN does 21

attempt to address Commission precedent with a footnote stating: 22

In past GRC’s TURN has proposed inflation adjustments for mass property 23 accounts for depreciation purposes. The proposal here is limited to 24 decommissioning forecasts for production plant accounts in order to address 25 SCE’s different approach in establishing production net salvage compared to its 26 approach used for mass property accounts.85 27

81 TURN-10, pp.16-23. 82 D.06-05-016 pp. 210-211. 83 D.09-03-025, p. 178. 84 Id. at 37. 85 TURN-10, p. 19, footnote 30.

24

However, TURN’s “no-inflation” proposals in those prior GRC’s was not limited to 1

mass property accounts, but included production plant.86 Additionally, SCE’s approach for both 2

mass property and production accounts follows the Commission’s Standard Practice (SP) U-4. 3

TURN references a single sentence from SP U-4 to support its proposal.87 That single sentence, 4

however, is taken out of context of the entirety of SP U-4, which also states that “Future net salvage 5

as included in the accrual equation represents an estimate of the dollars which will be realized from 6

the future retirement of all units now in service.”88 Also, TURN’s citation was in a Future Cost of 7

Removal section reference to Tables 7-A and 7-B in SP U-4. These tables estimate cost of removal 8

as a percent of the original cost of the asset (plant) using recorded data, which has inflation 9

embedded in it.89 All of the estimating discussion and examples in SP U-4 is done in reference to 10

those percentages, thus, the statement that to consider “changes in labor cost for the immediate 11

future” is relative to the inflation already embedded in the historical percentage, not inflation as a 12

mutually exclusive addition. What SP U-4 is saying is to consider cost changes into the immediate 13

future that may be different than what’s already reflected in the percentage. This consideration 14

applies to all drivers, not just inflation. 15

a) Pebbly Beach 16

SCE proposes decommissioning costs of $670,000 per generating unit, or $4 17

million in 2012 dollars, for the six diesel generators in Pebbly Beach Generating Station. The 18

decommissioning cost is escalated to the end of the station’s average remaining life of 19 years 19

resulting in a $6.6 million estimated decommissioning. 20

ORA recommends that SCE be required to perform an updated 21

decommissioning study before additional decommissioning expenses are authorized. SCE’s 22

decommissioning estimates is based on the activities required to perform the demolition and removal 23

activities to decommission the plant. Such activities simply cost more on Catalina given that 24

equipment and materials often have to be transported by boat or barge. In fact, in 1973, Pebbly 25

86 Appendix E, A.07-11-011, Exhibit___MJM-2 p. 6 of 17. 87 TURN-10, p. 20. 88 C.P.U.C. Standard Practice U-4-W, Determination of Straight-Line Remaining Life Depreciation

Accruals. 89 That is, current removal in current dollars divided by original plant cost, which is the dollars incurred in

the original year of installation.

25

Beach Unit 9 was decommissioned for a total cost of approximately $167,000 (in 1973 dollars). 1

Restating these costs in current dollars, using the Handy Whitman Index, would be approximately 2

$1.1 million in 2012. With this context, the proposed increase is appropriate and conservative. 3

26

E. Production Lives are Appropriate 1

As discussed in Mr. Watson’s testimony, transmission and distribution assets are expected to 2

retire individually over a prescribed distribution given the estimated curve-life whereas generation 3

assets, grouped by facility, are expected to all retire when the plant, as a whole, reaches the end of its 4

life. As a result, SCE estimates the lifespan for the property groups to determine the remaining life. 5

SCE is proposing no changes to existing authorized generation lives based on the fact that there 6

have been no changes in circumstances since they were last approved.90 TURN and ORA both propose 7

longer lives for select generation assets as summarized below: 8

Table I-1 Life Proposals by Generating Facility

Production Facility SCE TURN ORA

Peakers 25 years 30 years

Mountainview 30 years 35 years

Solar Photovoltaic 20 years 30 years 25 years

SCE addresses each facility in the following sections. 9

1. Peakers 10

Each peaker power plant includes one General Electric LM6000 natural gas, simple-cycle 11

combustion turbine generator set and associated auxiliary equipment. SCE proposes a 25 year service 12

life for peakers. TURN proposes a 35-year life span stating “The life expectancy for a gas turbine 13

(“GT”), as estimated by the industry, is normally between 30-40 years.”91 14

According to TURN, the shorter lifespans of SCE’s gas turbines are indicative of either a 15

high load factor or an extensive number of start-ups.92 Further, TURN states that because the load factor 16

is not anticipated to be high the turbines can operate for 35 to 45 years.93 The original objective of 17

90 D.12-11-051. 91 TURN-10, p. 13. 92 Id. 93 Id.

27

installing Peakers was to meet peak load demands and to improve local grid stability during critical 1

demand periods. Since then, renewable energy mandates have increased the need for Peakers, due to 2

their quick-start capability, to serve as grid stabilizers to quickly react when renewable generation 3

experiences unpredictable variations in generation output. Therefore, it is not unreasonable to expect the 4

number of start-ups to increase in future years as more renewable power is added to the resource mix.94 5

Additionally, TURN does not consider how economic conditions may not support a life span longer than 6

what the Commission has previously adopted. In addition to increased reliance on renewable power, the 7

risk of stricter emission standards and fluctuation of natural gas prices are all factors not identifiable in 8

the operating capability of the equipment but nevertheless can have life-shortening impacts on the 9

equipment. TURN’s use of broad industry comparisons of “gas turbines” as a basis to change the 10

Commission approved service life is unsupported. 11

2. Mountainview 12

Each Mountainview Unit 3 & 4 consists of two General Electric (GE) “F-class” 13

combustion turbines and one GE “D11” steam turbine. The life span for Mountainview Units 3 & 4 is 14

forecast to be 30 years. 15

TURN’s basis for its 35-year proposal is a general statement that “many other units are 16

expected to operate for at least 35 to 40 years”95 and SCE’s General Electric GTs are “state of the art.”96 17

SCE is not sure what impact “state of the art” has on a longer service life, but regardless, TURN offers 18

no other evidence than vague industry comparisons. TURN fails to realize that in order to run a plant 19

efficiently, besides the turbine generator; other ancillary plant system equipment play a critical role. It 20

should be noted that not all the equipment in Mountainview Units 3 & 4 is “state of the art” as suggested 21

by TURN. SCE acquired Mountainview Units 3 & 4 from InterGen in 2004. At that time, the plants 22

were less than 15% built, shut down and sat abandoned for two years before changing ownership. 23

94 As of year-end of 2013, renewable power accounts for 21.6%3 of SCE’s retail electricity sales. The

percentage will go up steadily to no less than 33% by 2020 in order to meet the California Renewables Portfolio Standard (RPS), one of the most ambitious renewable energy standards in the country.

95 TURN-10, p. 14. 96 Id.

28

3. Solar Photovoltaic 1

ORA proposes an increase in the Solar Photovoltaic (Solar PV) generating units life 2

spans to 25 years based on a statement from SCE’s website about plant lasting at least 20 years.97 3

Additionally, TURN suggests that the Solar PV life be increased from 20 to 30 years (a 50% increase in 4

the service life) based on its “review of utility life span estimates for similar equipment” and “review of 5

solar panel manufacturers information.”98 These considerations, however, do not take into account 6

SCE’s equipment or other forces of retirement. 7

TURN, for example, has referenced Florida Power & Light Company (FPL) as a large 8

utility using a 30-year service life for its solar assets. The technology and equipment use in FPL’s Solar 9

Energy Center and SCE’s rooftop solar program are not similar as shown in Table I-2. 10

Table I-2 Comparison of SCE and FPL Solar Technology

SCE FPLTechnology Photovoltaic Solar ThermalSolar Collector PV Panels Parabolic Mirrors

Power Block No, Inverter and limited balance of plant equipment

Yes, combined-cycle natural gas steam turbine units, & heat

exchange system, etc. This only further demonstrates TURN’s misuse of industry comparisons which is no 11

different here as it is in all of TURN’s proposals. TURN’s basis for its recommended 50% increase in 12

the solar PV life is inappropriate and unjustified. 13

4. Mohave Generating Station 14

SCE proposes to fully amortize the remaining $51 million in capital costs related to 15

Mohave by year-end 2015 pursuant to CPUC Decision D.12-11-051.99 ORA recommends that the 16

remaining cost be amortized over three years (through 2017). ORA claims “this is consistent with 17

97 ORA-23 p. 48. 98 TURN-10, p. 14. 99 This is $26 million in decommissioning costs and $25 investment.

29

SCE’s recommendations that over-collections be amortized back to the ratepayers over the entire three 1

year cycle.”100 2

ORA’s proposal is at odds with the Commission’s authorized schedule and ORA presents 3

no evidence in this proceeding to diverge from the past Commission Decision. Additionally, ORA’s 4

proposal further penalizes SCE since the outstanding balance of costs is currently earning zero percent 5

return on rate base. The Commission should retain the currently authorized cost recovery schedule for 6

Mohave and reject ORA’s proposal. 7

F. Conclusion 8

SCE has clearly demonstrated that ORA’s and TURN’s proposals are not rational relative to SCE 9

recorded costs and are based improper comparisons. The Commission should adopt SCE’s proposed 10

depreciation lives, net salvage ratios, and the resulting depreciation rates. 11

100 ORA-23, p. 47.

30

II. 1

TAXES 2

A. Summary of Rebuttal to TURN 3

This testimony responds to TURN’s proposed ratemaking adjustments to prior year taxes. 4

The proposed adjustments are associated with two issues: (1) 2012-2014 federal repair deductions, 5

and (2) 2013-2014 state income tax depreciation deductions on advanced meters. 6

For repair deductions, TURN proposes to recapture the flow-through impact of repair 7

deductions for 2012-14 that SCE received by electing the “safe harbor” option in Revenue Procedure 8

2011-43. TURN states that because the timing of these voluntary elections was SCE’s choice, the 9

Commission should retroactively normalize prior year federal and state income tax deductions in 10

2015. TURN’s understanding of the facts is wrong and its proposed remedy would be retroactive 11

ratemaking. SCE’s tax elections were appropriate. The changes in tax guidance described further 12

below drove SCE’s deduction elections and the Commission’s flow-through policy dictated the 13

result. TURN’s proposal would be retroactive ratemaking. SCE’s voluntary elections will result in 14

a reduction in 2015-2017 revenue requirements of some $580 million (based on SCE’s proposed 15

expenditures). 16

TURN’s proposed state income tax depreciation deduction for advanced meters is similarly 17

meritless. TURN contends that because the state income tax depreciation adopted in SCE’s 2012 18

GRC did not match what was expected in SCE’s 2013 and 2014 tax returns, SCE should be required 19

to return the incremental amounts to customers in 2015 and the attrition years. To the contrary, SCE 20

followed appropriate regulatory guidance in making the state income tax depreciation elections; the 21

ratemaking impact resulted from the Commission’s flow-through policy. Like its repair deduction 22

proposal, TURN’s state income tax depreciation proposal would be retroactive ratemaking. 23

B. Federal Repair Deductions 24

TURN would have the Commission reduce SCE’s rate base by $293 million to normalize 25

federal repair deductions that SCE had flowed-through in 2012-14. This proposed retroactive repair 26

adjustment rests on TURN’s belief that SCE inappropriately “diverted” tax savings from ratepayers 27

to shareholders through accounting method changes in 2009 and 2011. 28

TURN asks the Commission to reach back into prior years and normalize tax deductions in 29

starting in 2015. TURN claims its proposal would not be retroactive ratemaking because it would 30

apply prospectively. TURN’s proposal would be retroactive ratemaking and contrary to the Public 31

31

Utilities Code and Commission precedent.101 1

1. SCE Has the Responsibility to Comply with Changing Tax Authority to Legally 2

Minimize its Tax Burden 3

TURN criticizes SCE for making “voluntary” elections between rate cases to change 4

its tax method of accounting for repairs.102 TURN’s criticism is wrong. SCE’s 2009 and 2011 5

method changes were prudent and made to minimize its income tax liability. 6

Income tax authority is constantly changing. Congress frequently passes new 7

legislation amending the Internal Revenue Code. The Internal Revenue Service (IRS) frequently 8

issues new guidance in various forms (e.g., regulations, rulings, notices and procedures) that 9

constitute either a change in law or an interpretation of existing law. In addition, federal court 10

decisions serve to create new or modified income tax authority. 11

SCE, like any other taxpayer (whether rate-regulated or not), strives to legally comply 12

with the income tax rules and to pay the tax it owes, but no more than the law requires.103 SCE 13

appropriately monitors tax law changes to identify opportunities to minimize its liability. The 14

Commission develops the rules that determine how income taxes are to be addressed in ratemaking. 15

The impact to customers of SCE’s efforts to minimize its tax liabilities ultimately results from 16

applying the Commission’s ratemaking policies. 17

101 TURN’s proposal would reduce rate base for the tax affected difference between SCE’s 2012-2014 net

repair deduction as reflected in SCE’s 2015 GRC NOI and the 2012-2014 net repair deduction as authorized in the 2012 GRC. TURN-05, Marcus, p. 102.

102 TURN’s claims relate to 2009 and 2011 accounting method changes. While 2009 is a test year, the IRS authority provided to make the voluntary change did not become available until after the record for the 2009 GRC had closed.

103 In a frequently quoted opinion, Judge Learned Hand of the U.S. Second Circuit Court of Appeals, said: “Anyone [sic] may so arrange his affairs that his taxes shall be as low as possible; he is not bound to choose that pattern which will best pay the Treasury; there is not even a patriotic duty to increase one’s taxes. Over and over again the Courts have said that there is nothing sinister in so arranging affairs as to keep taxes as low as possible. Everyone does it, rich and poor alike and all do right, for nobody owes any public duty to pay more than the law demands.” Helvering v. Gregory, 69 F.2d 809, 810 (2d Cir. 1934), aff'd, 293 U.S. 465, 55 S.Ct. 266, 79 L.Ed. 596 (1935).

32

2. Adjustments Can Cut Both Ways And The Commission Has Previously Held 1

That Absent A Memorandum Account, A Utility Cannot “True Up” A Prior 2

Year’s Ratemaking To Match A Subsequent Adjustment 3

Forecast test year ratemaking carries with it the inherent risk that actual income tax 4

amounts will differ from forecast. Among the many situations when this can occur include: 5

� a difference between the amount and/or type of actual expenditures incurred and 6

the amount and/or type of expenditures that had been forecasted; 7

� a change in tax authority impacting a forecasted year where this change was not 8

known at the time the forecast was established; 9

� a challenge to a tax position by the IRS (or a state taxing authority) employing an 10

argument that had not yet been developed by the IRS and/or not known by the 11

taxpayer at the time the forecast was established. 12

The ratemaking impact of differences between forecast and actual will vary based on 13

whether the tax item to which the difference relates is normalized or flowed through.104 In either 14

case, the rate impact will be prospective, but a difference in a normalized tax item can be remediated 15

by the resetting of rates to reflect the actual result in the next rate case; a difference in a flow-16

through tax item cannot be reset. 17

3. TURN’s Proposed Adjustments Are Retroactive Ratemaking 18

a) The Commission Has Previously Rejected An After-The-Fact Attempt To 19

Match Ratemaking Taxes With Paid Taxes 20

Although TURN describes its normalization proposal as not violating the rule 21

against retroactive ratemaking,105 it would in fact do so. This proposal is no different in principle 22

than an issue the Commission addressed in Southern California Gas Company’s 1990 GRC. At 23

issue in that case was the tax treatment of certain employee benefit costs. In a prior GRC, SoCalGas 24

had treated these costs as currently deductible and flowed through the tax benefit in its cost-of 25

service calculations. The IRS later determined that these amounts should be capitalized. In its 1990 26

104 Normalization amortizes the difference between book accounting (GAAP) and income tax accounting

over a period of years. Flow-through matches deductions used to compute cost-of-service income tax expense to those used on the tax return. See Section A.4.

105 TURN-05, Marcus, p. 108.

33

GRC, SoCalGas sought to recover the difference. DRA and TURN objected to SoCalGas’ request, 1

arguing that it amounted to retroactive ratemaking. Agreeing with those parties, the Commission 2

observed that, unless a memorandum account had been established in advance, there can be no after-3

the-fact true-up to match ratemaking taxes with paid taxes: 4

First, as pointed out by DRA, it is fundamental that there can be no after-5 the-fact “true up” to match ratemaking taxes with as-paid taxes, unless the 6 Commission specifically made provision for such an adjustment prior to 7 the rates in question becoming effective. 8

Second, a tax return is filed with the IRS after the tax year in which the 9 return relates is over and tax positions may not have been developed at the 10 time of a general rate case. Because of the rule against retroactive 11 ratemaking, we cannot make a tax memorandum account available to 12 address a tax year that has passed even if such IRS action was not 13 anticipated in the general rate case for that year.106 14

SoCalGas’ position is the counterpart of TURN’s position in this case, which 15

the Commission anticipated in that earlier decision: “The same rule applies whether the amount at 16

issue is an overcollection, resulting in a windfall to the utility, or an undercollection, as is alleged in 17

the instant case.”107 18

b) The Commission Similarly Restricts A Utility From Recovering Tax 19

Obligations Paid In Prior Years 20

This SoCalGas decision was no mere anomaly. A year later the Commission 21

addressed an application from Southern California Water Company “to establish a memorandum 22

account in which it could book as much as $4 million in payments to the IRS for contested back 23

taxes.”108 DRA protested the application, claiming that granting it would amount to retroactive 24

ratemaking. As the Commission described DRA’s position: 25

106 Re Southern California Water Co., D.92-08-007, 1992 Cal. PUC LEXIS 532, at *5-6, 45 CPUC2d 256. 107 Id. at *4. 108 Re Southern California Water Co., D.93-04-046, 1993 Cal. PUC LEXIS 223, at *1, 49 CPUC2d 60. The

Commission described the utility’s request as follows: “The application seeks to book to the tax memorandum account any federal and state income taxes ultimately paid by SCWC as a result of the audit; interest paid to the IRS and to the state as a result of such assessments; attorney and accountant fees and other costs incurred in challenging the assessments, and interest on the unrecovered monthly balances in the memorandum account.”

34

Tax deductions and credits have long since been estimated in SCWC's 1 general rate cases covering the years 1983 through 1988. Those estimates 2 were calculated in the rates that SCWC was authorized to collect in those 3 years. The utility did not seek to keep any tax estimates open for 4 reconsideration by the Commission at a later date. To revisit those 5 estimates now and, ultimately, to collect from ratepayers the actual tax 6 assessment that IRS says should have been paid at that time is, in DRA's 7 view, a classic example of revising rates retroactively. The Division 8 states: 9

The Commission would no more guarantee the utility be made whole for 10 taxes than for any other estimated expense…. Tax deductions and credits 11 are estimates based on the best information available at the time of the 12 estimate. This Commission has never made prospective adjustments to 13 ratemaking tax deductions and credits based on tax refunds received or 14 additional taxes owed based on real world audits by the IRS except for 15 specific unique items held open by Commission decision. 16

The Commission held in the Southern California Water Company decision 17

that the SoCalGas decision discussed above was “dispositive:” 18

The SoCalGas decisions are dispositive of the issues in this application. 19 The facts in SoCalGas were virtually identical to those here. A claim was 20 made that the IRS deficiency claim could not have been foreseen. The 21 disputed tax matter had been part of a rate case. SoCalGas argued that it 22 could not pursue aggressive tax strategies if it was compelled to bear all of 23 the risk of claimed deficiencies. Our conclusion was that none of these 24 factors overcomes our mandate to set rate increases and rate reductions on 25 a prospective basis only, except under certain prescribed conditions. We 26 noted that a utility could always seek – and would be likely to obtain – 27 memorandum account treatment to deal with significant tax uncertainties, 28 provided it sought such relief prospectively. 29

SCWC argues that the claimed deficiency in its case constitutes a 30 prospective cost, rather than an adjustment of a past cost, because the 31 amount has not yet been paid and is not absolutely due until after the IRS 32 appeal process. That argument approaches sophistry. Clearly, the alleged 33 deficiency relates to tax obligations that are alleged to have been due for 34 each of the tax years 1983 through 1988, and that is what the utility would 35 seek to recover through rates.109 36

If Southern California Water Company’s argument “approaches sophistry,” 37

then the Commission has to conclude that the TURN’s proposed adjustment does so as well. TURN 38

wants to reach back to prior ratemaking years and use tax calculations from those years to compute a 39

prospective adjustment. If for no other reason, the TURN Proposal should be rejected for the same 40

109 Id. at *12.

35

reason the Commission rejected the proposals of SoCalGas and Southern California Water Company 1

– accepting such proposals would be retroactive ratemaking. 2

c) Rates May Only Be Set Prospectively 3

The prohibition against retroactive ratemaking reflected in the SoCalGas and 4

Southern California Water Company decisions is more than a matter of Commission ratemaking 5

policy. Public Utilities Code §728 specifically prohibits retroactive ratemaking. Interpreting that 6

statute in Pacific Telephone and Telegraph Company v. Public Utilities Commission,110 the 7

California Supreme Court held that the Commission was empowered in general rate case 8

proceedings to set rates prospectively only, and that the Commission had overstepped its statutory 9

power by ordering a refund of previously approved rates after a Commission investigation had 10

determined that these previously approved rates were too high: 11

Section 728 of the Public Utilities Code provides so far as here material 12 that “Whenever the commission, after a hearing, finds that the rates . . . 13 demanded, observed, charged, or collected by any public utility for or in 14 connection with any service . . . are . . . unreasonable, . . . the commission 15 shall determine and fix, by order, the just, reasonable, or sufficient rates . . 16 . to be thereafter observed and in force.” (Italics added.) 17

As Pacific states, this language is plain and unambiguous. The Legislature 18 has instructed the commission that after a hearing it is to make its order 19 fixing rates to be in force thereafter. 20

TURN’s retroactive ratemaking proposal would also violate Section 728. 21

4. The Commission’s Longstanding Ratemaking Policy Has Been To Flow-22

Through All Income Tax Deductions Except Where Otherwise Required By Law 23

In support of its proposed adjustment, TURN’s witness states: “To my knowledge, 24

the Commission has not opined on this particular tax change generated by Revenue Procedure 2011-25

43 in previous cases.”111 SCE agrees; we are not aware of any Commission decision specifically 26

addressing this Revenue Procedure. However, what TURN omitted is that the Commission’s 27

longstanding policy has been to flow-through all deductions except when specifically required by 28

law (or authorized in a proceeding) to be normalized. In Pacific Bell Telephone Company Interim 29

110 Pacific Telephone and Telegraph Company v. Public Utilities Commission, 62 Cal.2d 634; 1965 Cal.

LEXIS 286. 111 TURN-05, Marcus, p. 106.

36

Opinion, the Commission described the difference between flow-through and normalized ratemaking 1

for income taxes as follows: 2

There are two methods to account for income tax expense for regulatory purposes. 3 Under the flow-through method, the income tax expense recognized for 4 regulatory purposes during a given period is equal to the taxes that are assessed 5 and paid during the period. Under the normalization method, the income tax 6 expense for a given period is based on the net income recognized for regulatory 7 accounting purposes during the period, regardless of when the taxes associated 8 with the accounting income are actually paid. The flow-through method can be 9 viewed as cash-basis accounting, while the normalization method reflects accrual 10 accounting.112 11

In that same decision, the Commission reiterated that its longstanding policy has been 12

to flow-through income tax deductions for ratemaking purposes except when otherwise required by 13

law: 14

In 1981, newly enacted federal tax laws effectively mandated the use of 15 normalized tax accounting for accelerated depreciation and ITC [Investment Tax 16 Credit]. The effect of the new laws was that the Commission could no longer 17 require utilities to flow-through to ratepayers the substantial tax benefits 18 associated with accelerated depreciation and ITC. As a result, ratepayers had to 19 pay substantially more money in rates for income taxes than were actually paid by 20 the utilities. 21

Although federal law had preempted the Commission’s flow-through policy with 22

respect to accelerated depreciation and ITC, in D.84-05-036, the Commission held that its flow-23

through policy should remain in effect to the extent allowed by law.113 Following that policy, SCE 24

treated repair deductions on a flow-through basis. 25

5. SCE’s Tax Filing Actions and Regulatory Treatment were Proper and 26

Appropriate 27

a) SCE’s Repair Deductions Were Prudent and Appropriate 28

TURN claims SCE purposely “diverted” tax benefits from ratepayers to 29

shareholders. This claim is not supported by the facts. As explained below, it was the technical 30

requirements of the tax law and prudent income tax administration that determined how and when 31

SCE acted. The regulatory outcome to which TURN objects was just that – an outcome. The 32

112 Re Pacific Bell, D.04-02-063, pp. 96-97, 2004 Cal. PUC LEXIS 55, at *163. 113 Id. at *190.

37

regulatory outcome was not why SCE made the voluntary changes, nor did it impact the timing of 1

when such changes were made. Almost all utilities in the United States have made changes in their 2

repair deductions over the past several years as a result of changes in guidance by the IRS to address 3

the longstanding issue of determining what qualifies as a repair deduction for federal income tax 4

purposes. 5

There are two key aspects relating to the tax deductions a utility is entitled to 6

claim on account of its incidental repair expenditures: (1) which expenditures qualify as incidental 7

repairs under the applicable tax rules; and (2) when a taxpayer can change its method of accounting 8

for any material item, such as treating an expenditure as a repair. The distinction between whether 9

or not these expenditures are deductible as paid or capitalized and depreciated for income tax 10

purposes has long been a complex and disputed issue between taxpayers and the IRS. The Internal 11

Revenue Code provides that expenditures that: (1) do not substantially prolong the life of an asset; 12

(2) materially increase its value; or (3) adapt it for a substantially different use may be deducted as 13

an expense. Even if a utility were to know which of its expenditures qualified as deductible repairs, 14

if it has not historically deducted them, it cannot start to deduct them unless and until the IRS grants 15

it permission to change its accounting method. 16

Recent developments and guidance in this area has helped clarify the 17

distinction between capital versus immediate deduction. Beginning in 2008, it became evident that 18

the IRS was starting to allow utilities to change their methods of accounting for repairs (hereafter, 19

“Repair Method Change”) in ways that might be favorable (i.e., more expenditures would qualify as 20

repairs so that repair tax deductions would be increased). At that time we understood that grants of 21

permission to change accounting methods were being provided to some of the utilities that requested 22

them. But, while those grants allowed the change to occur, they gave absolutely no direction as to 23

what an acceptable method for identifying qualifying expenditures might be.114 24

114 The qualification of any particular project as a deductible repair for tax purposes is, and has always been,

dependent upon an assessment of the impact of that project on a designated asset (i.e., does it extend the life, increase the capacity, etc.). In tax parlance, this designated asset is a "unit of property.” Without knowing what units of property would be acceptable to the IRS, one could not know what repair deductions would be acceptable. Until very recently, the IRS had never indicated what it considered to be appropriate units of property for utility transmission and distribution assets.

38

b) The Repair Deduction Landscape Was Evolving 1

In late summer 2009, the IRS issued a revenue procedure115 that provided 2

blanket permission to all taxpayers desiring to change their accounting methods for repairs (that is, 3

the IRS granted “automatic” permission to change accounting methods for repairs). However, the 4

IRS had not yet provided guidance as to what it considered to be a permissible method of repair 5

identification. In July 2009, SCE engaged Ernst & Young to conduct a comprehensive study to 6

determine (and to draw upon its expertise and experience in working with other utilities on this same 7

issue) if it would be advantageous to develop a new method for computing the repair deduction. 8

This study involved a significant commitment of time, resources, management attention, and cost.116 9

In December 2009, SCE, like many other utilities, filed a Repair Method Change for its transmission 10

and distribution (“T&D”) assets as well as its electric generating assets117 using preliminary (i.e., 11

Phase 1) results from the study. This enabled SCE to reflect an incremental tax deduction produced 12

by the Repair Method Change on its 2009 income tax returns, thereby reducing its tax liability for 13

that year. While filing a Repair Method Change in 2009 was voluntary, waiting until 2010 would 14

have meant deferring the benefit of the incremental tax deduction. More importantly, waiting 15

beyond 2009 to file the Repair Method Change would have exposed us to the risk of the IRS 16

reversing its policy of granting “automatic” permission for a Repair Method Change. Corporate 17

taxpayers – including utilities – strive to achieve tax reductions at the earliest possible time and in 18

the greatest possible amount consistent with the tax law and the prudent assumption of risk. That 19

was precisely SCE’s motivation. 20

As of year-end 2009, SCE knew that its 2009 Repair Method Change was 21

administratively permissible but still did not know precisely what standards the IRS would apply in 22

evaluating which of our expenditures would qualify as repairs. 23

c) SCE’s 2012 GRC Application 24

When SCE submitted its Notice of Intent for a 2012 GRC in July 2010, we 25

had sufficient assurance of the underlying principles described in the Repair Method Change 26

115 Rev. Proc. 2009-39. 116 For example, it took a team of six to eight individuals several months to complete the initial feasibility

study. 117 As did many companies in the electric utility industry.

39

methodology to determine our estimated repair deductions. As with all estimates of repair 1

deductions in all previous GRCs, SCE flowed these forecast tax deductions through to ratepayers in 2

accordance with the Commission’s longstanding policy, as previously discussed above. 3

SCE filed its 2012 GRC Application in November 2010. In May and June 4

2011, DRA and intervenor testimony was submitted, but none mentioned the repair deductions or the 5

2009 Repair Method Change that SCE described in its testimony. TURN did issue a data request to 6

SCE (to which SCE responded) requesting workpaper support for the repair deductions reflected in 7

the filings.118 8

d) The “Safe-Harbor” Provision of Revenue Procedure 2011-43 9

On August 19, 2011, the IRS issued Revenue Procedure 2011-43 (the “T&D 10

Rev. Proc.”). The T&D Rev. Proc. established a “safe-harbor” that utilities could adopt for repair 11

deductions for T&D assets (the “Safe Harbor”). The T&D Rev. Proc. required that the Safe Harbor 12

be adopted by means of the taxpayer filing a Repair Method Change. 13

On October 24, 2011, SCE submitted its final update to its 2012 GRC. 14

On November 25, 2011, the IRS issued a directive entitled “Large Business & 15

International Directive Transition Rules for Taxpayers Adopting the Safe Harbor Method of 16

Accounting for Electric Transmission and Distribution Property” (“Directive”).119 17

SCE did not incorporate the Safe Harbor in the update as we had not 18

determined at that time whether we would adopt the Safe Harbor. Specifically, SCE had not yet 19

reached the point in our analysis of ascertaining whether, by adopting the Safe Harbor, we would be 20

able to claim additional repair deductions beyond what we could claim under the 2009 Repair 21

Method Change. Additionally, prior to the issuance of the Directive in November 2011, there were 22

also uncertainties associated with adopting the Safe Harbor. As a consequence, rates set for 2012-23

2014 appropriately reflected the estimated level of tax benefits based on SCE’s 2009 Repair Method 24

Change. 25

Prior to filing the 2011 federal income tax return in August 2012, we 26

completed our evaluation of the Safe Harbor. On its 2011 tax return (and on all of its subsequent tax 27

118 See responses to data requests TURN-SCE-002, Q. 13 and Q. 17 (2012 GRC received October 2010. 119 Transition Rules for Taxpayers Adopting the Safe Harbor Method of Accounting for Electric

Transmission and Distribution Property, LB&I Control No. LB&I-4-1111-019 (November 25, 2011).

40

returns), SCE adopted the Safe Harbor. As a result, the repair deductions claimed (or which are 1

expected to be claimed) on SCE’s 2012-2014 tax returns are larger than those reflected in the 2012 2

GRC for those years. SCE could not have incorporated the incremental repair deductions into its 3

2012 GRC or, as alternatively proposed by TURN, waited until the next rate case (i.e., 2015 GRC) to 4

adopt the Safe Harbor. 5

The T&D Rev. Proc. set out detailed rules for computing a utility’s T&D-6

related repair income tax deduction. It defined for the first time the units of property for T&D assets 7

and created certain benchmarks applicable to those units of property. Further, it established various 8

implementation rules. Among the new definitions, benchmarks and rules were: 9

� Definitions of units of property for linear property (e.g., lines, poles, etc.); 10

� Definitions of units of property for non-linear property (e.g., substations); 11

� Establishment of a 10% replacement threshold for linear property; 12

� Definition and treatment of de minimus additions; 13

� Definition and treatment of blanket work orders; 14

� Definition of “per-se” capital additions; 15

� Rules for aggregation of certain related projects; and 16

� Rules for use of statistical sampling and extrapolation. 17

Importantly, it was not clear when the T&D revenue procedure was first 18

issued whether the Safe Harbor would provide a greater repair deduction than SCE’s 2009 Repair 19

Method Change. While Rev. Proc. 2011-43 contained provisions that were favorable to SCE, it also 20

contained provisions that were not.120 21

e) SCE’s Analysis Of The Impact Of Electing The Safe-Harbor Provision 22

Upon the issuance of the T&D Rev. Proc., SCE immediately began analyzing 23

the potential impact on its repair deduction. It soon became clear that the complexity of this analysis 24

would require substantial resources and time. SCE assigned a Principal Manager on a nearly full-25

time basis to direct and augment a team of seven internal resources and outside consultants. 26

120 For example, the Safe Harbor required the aggregation of work orders if “a regulatory commission

decision authorizes the replacements as part of an identified program aimed at a specific purpose.” Significant analysis was required to determine the likelihood that this would require the aggregation (and likely capitalization) of work orders such as those conducted pursuant to the Reliability Investment Incentive Mechanism.

41

The analysis required SCE to reconcile how its new SAP accounting system 1

tracks and identifies work orders. Significantly, SCE’s plant construction and plant accounting 2

systems did not employ the same units of property definitions imposed by the Safe Harbor. We 3

conducted dozens of interviews to find a process to analyze work orders consistent with the T&D 4

Rev. Proc. Eventually, we developed specific programming logic to analyze all work orders. The 5

scale of this undertaking was a function of the sheer number of T&D work orders SCE opens in a 6

given year – generally more than 80,000. This very time-intensive effort was substantially 7

completed in mid-2012.121 Ultimately, the Safe Harbor was deemed favorable and resulted in a 8

larger T&D repair deduction compared to the method SCE had previously adopted under its 2009 9

Repair Method Change. 10

As a result of these efforts, the 2015 GRC tax workpapers122 included annual 11

repair deductions in excess of $500 million in each year (2015, 2016 and 2017). Those deductions 12

will be flowed-through to SCE ratepayers. 13

f) SCE Could Not Have Reflected The Safe Harbor Election In Its 2012 14

GRC 15

To have reflected the results of the analysis in SCE’s 2012 GRC update 16

testimony, we would have to have known both the results of the analysis for 2011 and projections of 17

SCE’s repair deduction for the three subsequent years under the Safe Harbor. October 2011 was 18

only two months after the issuance of the T&D Rev. Proc. and was prior to the issuance of the 19

Directive. This timing was not possible as the basic analysis was not completed until at least eight 20

months later. As discussed below, the IRS audit protection that was ultimately afforded in the 21

November 2011 Directive was not yet known. The effort to evaluate, apply and then quantify the 22

impact of the Safe Harbor was substantial and time intensive (8,000 man hours). 23

g) SCE Adopted The Safe Harbor As Soon As It Determined The Tax 24

Benefits Of Doing So 25

SCE was able to adopt the Safe Harbor on its 2011 income tax return due to 26

specific implementation provisions in Rev. Proc. 2011-43. The procedure required for perfecting 27

121 The Rev. Proc. also contained other requirements that SCE is still currently working to comply with.

Failure to satisfy these requirements would limit SCE’s ability to continue to utilize the Safe Harbor methodology.

122 SCE-10, Vol. 02, Ch. IV, Revision 1, workpaper, p. 22.

42

this 2011 Repair Method Change was to include the impact of the adoption along with the 1

attachment of an election form. Since SCE's 2011 federal income tax return was not filed until 2

August 2012, the Company had slightly over a year to perform the necessary analysis before SCE 3

needed to reflect such change on its 2011 return.123 4

There were three reasons for SCE to adopt the Safe Harbor at the earliest 5

possible time. The most obvious reason was that the sooner it was adopted, the sooner SCE’s tax 6

liabilities would be reduced. The second reason was audit protection. The Directive specifically 7

directed IRS personnel not to audit the repair deduction claimed in any prior year by a utility that 8

adopted the Safe Harbor in 2010 or 2011. Absent adoption in one of these two years, the deduction 9

was subject to full audit and the IRS had signaled that they would direct significant resources to 10

audit those taxpayers who chose not to adopt the Safe Harbor. Since SCE’s 2009 Repair Method 11

Change was based on its own interpretation of the applicable legal standards,124 the availability of 12

such protection was an important inducement. When addressing a similar Repair Method Change 13

made by Pacificorp in their 2011 GRC, the Commission acknowledged and noted “[t]he tax benefits 14

generated by the repairs deduction involve a materially higher than normal risk as compared to other 15

book-tax differences, because the method of accounting is new and still unaudited by the Internal 16

Revenue Service.”125 Finally, under the terms of the Rev. Proc., utilities adopting the Safe Harbor in 17

2010 or 2011 were relieved of restrictions on the timing of their change in accounting method to 18

which taxpayers are normally subject (e.g., when under audit, where the accounting method for the 19

same item has been changed in the past five years, etc.).126 20

In conclusion, SCE proceeded in a rational manner. We quantified the impact 21

of implementing Rev. Proc. 2011-43 as quickly as practicable. We reduced our tax liability at the 22

earliest possible time. We eliminated the time, expense, and risk of potentially contentious IRS 23

audits for prior year tax returns subject to audit. Contrary to TURN’s assertion, SCE was not 24

motivated by the desire to “divert” tax benefits. SCE handled its corporate tax affairs prudently. 25

123 The statutory due date for filing the 2011 federal income tax return was September 15, 2012. 124 The Safe Harbor rules did not apply. 125 D.10-09-010, p. 11. 126 Note that on September 24, 2012, the IRS issued Proc. 2012-39, and on October 9, 2012 issued Rev. Proc.

2012-14, 2012-41 IRB 470, which extended by one year the time within which the Safe Harbor needed to be adopted. By this time, SCE had already filed its 2011 federal income tax return.

43

6. The Commission Has The Discretion To Switch To A Policy Of Normalizing All 1

Deductions But Should Only Do So Prospectively And Consistently 2

TURN recommends that the repair deduction be treated on a flow-through basis 3

prospectively (i.e., starting in 2015) but also that a special rate base adjustment be applied to address 4

what had been authorized in the 2012 GRC relative to the recorded 2012-2014 repair deductions. 5

This rate base adjustment applies a normalization-like offset to repair deductions that were subject to 6

flow-through treatment based on longstanding Commission policy. This Commission certainly has 7

the discretion to change to a normalization policy. In fact, normalization of tax deductions is the 8

policy followed by the Federal Energy Regulatory Commission (FERC) and most other states. For 9

example, following a period during which it had switched from normalization to flow-through, 10

FERC ultimately went back to an all-normalization policy in 1975, a policy it continues to follows: 11

[T]his Commission’s policy (and that of its predecessor) on flow through has not 12 been consistent. In 1954 the Commission adopted mandatory normalization of 13 timing differences Amere Gas Utilities Co., 15 FPC 760 (1956). Subsequently, 14 the FPC adopted as controlling the flow through method. Alabama-Tennessee 15 Natural Gas Co., 31 FPC 208 (1964), aff’d, 359 F.2d (5th Cir. 1966), cert. den., 16 385 U.S. 847 (1966). By Order No. 404, 43 FPC 740 (1970), aff’d, Memphis 17 Light, Gas & Water Division v. F.P.C., 462 F.2d 853 (D.C. Cir. 1972) the 18 Commission permitted normalization of post-1969 expansion property, and later 19 extended this normalization to pre-1970 property by Opinion No. 578, Texas Gas 20 Transmission Corp., 43 FPC 824 (1970), rev’d, Memphis Light, Gas & Water, 21 supra, rev’d and rem., F.P.C. v. Memphis Light, Gas & Water Division, 411 U.S. 22 458 (1973), aff’d on remand, 500 F.2d 798 (1974). In 1975, the Commission 23 advocated full normalization in promulgating Order No. 530, 53 FPC 2123 24 (1975), which later developed into a policy of mandatory normalization with the 25 promulgation of Order Nos. 144 and 144-A, supra 127 26

This Commission can choose to switch to a full normalization policy, but should only 27

do so prospectively and consistently, applying that policy to all utilities under its jurisdiction after 28

notice and opportunity for all affected parties to be heard. Perhaps the time is ripe for the 29

Commission to initiate a generic investigation to revisit its normalization policy. But unless and 30

until it does so, it should not inconsistently apply normalization in some instances and flow-through 31

in others. Or, in the case of TURN’s proposal, apply both at the same time. 32

127 Kansas Gas and Electric Co., 28 FERC ¶63,004 (July 13, 1984), 1984 FERC LEXIS 1767, at *111. See

Regulations Implementing Tax Normalization for Certain Items Reflecting Timing Differences, 46 Federal Register 26613 (May 14, 1981), amending 18 C.F.R. §2.202.

44

C. State Tax Depreciable Lives For Advanced Meters 1

1. TURN Proposes “to Disgorge” SCE’s 2013 and 2014 Rates Established and 2

Approved in D. 12-11-051 3

TURN recommends SCE be required “to disgorge $7.3 million”128 from its 2013-4

2014 revenue requirement and apply this amount to reduce its future income tax expense in this 5

GRC. TURN recommends this approach because the 2013 and 2014 state income tax depreciation 6

adopted in SCE’s 2012 GRC differs from what is expected to be in SCE’s 2013 and 2014 state tax 7

returns.129 Like its proposed normalization adjustment for the repair deduction, TURN asserts that 8

“[t]his is not retroactive ratemaking; this is correcting more of Edison’s unapproved tax flow-9

through accounting.” 10

2. TURN’s Proposal On Advanced Meters Is Also Retroactive Ratemaking 11

Like its repair deduction proposal, TURN’s proposal on advanced meters would also 12

be retroactive ratemaking. TURN proposes that SCE return approved and established revenue from 13

its 2012 GRC (D. 12-11-051, AL 2832-E for 2013 and AL 2961-E for 2014) through a refund to 14

ratepayers in the 2015 GRC test year and attrition years (i.e., 2015 through 2017). 15

TURN’s assertions that a “larger question” is raised because of “some unexplained 16

and unapproved maneuvers in accounting that Edison made when it closed the AMI balancing 17

account” and “that Edison adopted a very strange accounting convention for the advanced meters” 18

fail to mention that SCE’s actions followed the appropriate regulatory guidance: D.08-09-039 19

(which required SCE to reflect actual amounts through 2012) and D.12-11-051 (which required SCE 20

128 “TURN recommends that state tax accounting for this item be approved in this rate case to disgorge the

$7.3 million that Edison took without approval . . .” TURN-05, Marcus, p. 109. 129 This difference in tax depreciation is due to SCE’s compliance with IRS Technical Advice Memorandum

(“TAM”) 201244015 that was issued on November 2, 2012 and which concluded that advanced meters qualified as Asset Class 00.12 (6-year Class Life) instead of Asset Class 49.14 (30-year Class Life). SCE made this change consistent with TAM 201244015 at its first available opportunity (i.e., beginning 2012), and reflected this change and related tax benefits in 2012 regulated rates through its AMI Balancing Account, and has reflected this change and related tax benefits in this 2015 GRC proceeding. However, because of a previously issued CPUC decision (D. 08-09-039, p. 38) that required the AMI balancing account to end in 2012 and for the recovery of advanced meters to be included in general rates beginning 2013, SCE was unable to reflect the 2013 and 2014 change in state tax depreciation into rates because the TAM was not issued until after the 2012 GRC proceedings were completed. The 2012 GRC forecast reflected the pre-TAM 30-year life for years 2013 and 2014.

45

to reflect forecasts amounts for 2013 and 2014). In our 2015 GRC, SCE reflected forecasted 1

amounts for 2015 through 2017 based on most current data. 2

As discussed earlier, this Commission denied, as impermissible retroactive 3

ratemaking, SoCalGas’s request for recovery (through a tax memorandum account) of flow-through 4

taxes resulting from differences in what was approved in that utility’s 1983 through 1985 cost of 5

service calculations and what was reflected in its 1983 through 1985 tax returns. A similar result 6

was reached a year later in the Southern California Water decision also discussed above. Here 7

TURN has identified an item (tax depreciation for advanced meters) within a prior year's (2013 and 8

2014) tax calculation which: (1) was flowed through when rates were set in 2012; and which (2) 9

turned out to be larger than the deduction that was projected at that time. This TURN proposal is no 10

different in kind than those rejected in the SoCalGas and Southern California Water Company 11

decisions. For the same reasons, the Commission should reject TURN’s retroactive ratemaking 12

proposal. 13

46

III. 1

RATE BASE 2

A. Customer Advances 3

1. SCE Position 4

SCE estimated a $280 customer advances per meter set based on a five-year average. 5

SCE estimated 2015 total customer advances of $45.3 million. 6

2. ORA Position 7

a) Electric Construction 8

ORA proposes a three-year average (2010-2012) advance per meter set of 9

$353, which it contends reflects current economic conditions. 10

3. TURN Position 11

a) Electric Construction 12

TURN proposes an $8.5 million increase to SCE’s 2014 and 2015 forecasts. 13

b) Temporary Services 14

TURN recommends reducing SCE’s 2015 forecast by $1 million. This 15

includes replacing SCE’s five-year average of recorded data (2008-2012) with a four-year average 16

updated for 2013 recorded activity, “including only periods after the recession (2010-2013) escalated 17

with inflation to 2015.”130 18

4. SCE’s Rebuttal 19

ORA uses a three-year average (2010-2012), instead of a five-year average, to 20

calculate costs per meter set. It then applies this average to SCE’s meter set forecast for the rate case 21

period, stating that it “accurately reflects the current economic conditions.” 131 ORA does not 22

provide support for why this shorter time period would more accurately reflect current economic 23

conditions or explain why the conditions during the three-year period are indicative of the future. In 24

addition, ORA’s argument is contrary to the position it took in SCE’s 2012 GRC, where it argued 25

that using a five-year average for advance per meter set “covers a longer time period which includes 26

periods of some economic growth, smooths the data, and takes into consideration that there is not 27

absolute certainty that the economic conditions will be similar to that of 2007-2009 [three year 28

130 TURN-05, Marcus, p. 125. 131 ORA-24, p. 5.

47

average for the most recent historic period], but are expected to slowly improve.”132 SCE chose to 1

follow ORA’s prior forecast approach because the reasoning is supported in this instance. ORA’s 2

decision to backtrack on its support of a five-year average is unexplained and unsupported. Further, 3

ORA’s position is also contradictory because it did not oppose SCE’s five-year average for 4

Temporary Services.133 The Commission should reject ORA’s proposed three-year average. 5

TURN’s proposal for adjusting Customer Advances for Construction also lacks 6

support. TURN applies the $8.5 million actual to forecast variance experienced in 2013 (as shown 7

in Table III-3 below) directly to SCE’s forecasted average balances for 2014 and 2015. Each 8

forecast balance is then exactly $8.5 million higher in each year. 9

Table III-3 2013 Customer Advances – Electric Construction EOY Balance

Actual to Forecast Comparison (Nominal $000)

2013�Actual 2013�Forecast Variance %

Year�End�Balance $51,910 $43,398 $8,512 20% SCE compared actual to forecast balances for construction customer advances 10

included in the most recent rate cases in Table III-4 below. This comparison demonstrates that 11

variance in a particular year is not indicative of variances in other years. In 2013 more construction 12

customer advance dollars were taken in and less customer advance dollars were refunded than 13

expected, resulting in a 20% variance. Due to the multitude of disparate, unpredictable, and 14

uncontrollable (externally driven) factors affecting the inflows and outflows to construction 15

advances, the balances will fluctuate from year to year. This is precisely why SCE used a five-year 16

average. Table III-4 also demonstrates that this approach is usually beneficial to ratepayers. Note 17

that for both Test Years’ 2009 and 2012 forecasts in Table III-4, the variances started out with actual 18

balances being greater than forecast but ended where the forecast Rate Base offsets impacting rates 19

were greater than the actual amounts (e.g., TY 2009 actual balance was approximately 21% less than 20

forecast). It would be unreasonable to rely on a single year’s variance to forecast 2014 and 2015 21

balances. TURN’s adjustment should be rejected. 22

132 ORA-19, p. 5 (2012 GRC). 133 Exhibit ORA-24, p. 5.

48

Table III-4 Comparison – Actual to Recent GRC Forecasts of Construction Customer

Advance Balances ($000 Nominal Average Balances)

2010 2011 TY�2012Actual� 77,227$�� 69,965$�� 61,032$��2012�Test�Year�GRC�Forecast 77,046$�� 66,399$�� 62,562$��Actual�less�GRC�Forecast 181$�� 3,566$�� (1,530)$��% 0.2% 5.4% �2.4%

2007 2008 TY�2009Actual� 100,733$�� 97,747$�� 88,384$��2009�Test�Year�GRC�Forecast 99,802$�� 107,674$�� 111,130$��Actual�less�GRC�Forecast 931$�� (9,927)$�� (22,746)$��% 0.9% �9.2% �20.5% In addition, both ORA and TURN propose lower new meter set forecasts in other 1

sections of their testimony.134 However, neither proposes reductions in SCE’s forecasts of 2

construction customer advance inflows tied to new meter sets in this section. Since ORA and TURN 3

argue for lower SCE costs due to lower meter set forecasts in other sections yet not for lower Rate 4

Base offsets pertaining to the same driver in this section indicate an oversight or bias in their 5

forecasting methods. 6


a) SCE’s Forecast Methods utilizing Five-Year Averages are Reasonable 8

As discussed in Exhibit SCE-10, Volume 2,135 SCE chose a five-year average 9

advance per meter set to account for the fluctuations that occur in this account. Our forecast shows 10

Customer Advances declining through 2014 (due to recent construction activity and actual meter set 11

experience) but meter set activity is expected to level off in 2015, and then increase in 2016 and 12

2017. See Figure III-8 below. SCE chose a five-year average (versus a three-year average) of the 13

most recent recorded numbers to include historic periods where balances were higher.136 This 14

134 ORA-03, p. 1 and TURN-05, Marcus, p. 47. 135 SCE-10, Vol. 2, p. 58. 136 SCE consistently utilized 5 year averages of 2008-2012 historic data throughout its customer advance

forecasts as follows: 1) Construction Advance receipts (inflows) – 2008-2012 average to determine (Continued)

49

approach gives ratepayers the benefit of the expected leveling off and then upswing in activity in the 1

future. 2

Figure III-8 Original Application Study*

GR

84 88

67

4632 26 20 23

3346

60 67 68

78

96110 106

9784

7667

5648 45 48 52

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Recorded Forecasted CustomerAdvances($ millions)

Meter Sets(Thousands)

*Exhibit SCE-10, Volume 2, see supporting Workpapers entitled "Customer Advances"

APH

Table III-5 below compares 2013 actual to forecast for Average Customer 3

Advances (Construction Advances and Temporary Services). The comparison demonstrates that 4

SCE’s overall forecast for 2013 customer advances is consistent with recent recorded data. 5

Table III-5 Average Customer Advances 2013 Forecast Compared to Actual

(Nominal Average Balances - $ Million) � 2013 2013

Actual Forecast Variance %

Average Customer Advances* $58 $56 $2 4%

* Customer Advances - Electric Construction and Temporary Services

Continued from the previous page

advance dollars per meter, 2) Construction Advance payments (outflows) – incorporated 10 years of refund history adjusted to reflect the average 2008-2012 pattern, and 3) Temporary Services – forecast balances based on 2008-2012 average balances.

50

In addition, where data follows a pattern, SCE has incorporated the driver in 1

its customer advance forecasts. For example, SCE has forecast construction customer advance 2

inflows (receipts) based on a forecast of meter sets to properly incorporate the expectation of 3

customer growth. Historically, recorded Customer Advance Receipts and Meter Sets have tracked 4

each other well in times of both high and low customer growth. See Figure III-9 below. 5

Figure III-9 Recorded Customer Advance Receipts/Meter Sets

GRAPH

SCE’s use of a five-year average to forecast customer advance forecasts is 6

reasonable due to the largely unpredictable and externally driven nature of advance inflows and 7

outflows. Relying solely on any one particular year’s activity to forecast the test year balance would 8

be inappropriate. There are many approaches to forecasting Test Year expenses and many different 9

methods have been used in prior GRCs. The Commission revisited the issue of forecasting 10

methodologies in its decision on Pacific Gas and Electric Company’s 1999 GRC: 11

51

The Commission has recognized that there are different valid and 1 acceptable methods for account-by-account forecasting Test Year costs in 2 a GRC, including using a single recorded year's expenses ... and using 3 multi-year average recorded costs.... The question at hand is which of 4 these two methods yields the most accurate and reliable forecast of Test 5 Year expenses. In PG&E's Test Year 1990 GRC the Commission 6 described the following criteria for developing a base estimate of Test 7 Year expenses: 8

If recorded expenses in an account have been relatively stable for three or 9 more years, the 1987 recorded expense is an appropriate base estimate for 10 1990.137 11

If recorded expenses in an account have shown a trend in a certain 12 direction over three or more years, the 1987 level is the most recent point 13 in the trend and is an appropriate base estimate for 1990.138 14

For those accounts which have significant fluctuations in 15 recorded expenses from year to year, or which are influenced by 16 weather or other external forces beyond the control of the utility, 17 an average of recorded expenses over a period of time (typical 18 four years) is a reasonable base expense for the 1990 Test Year.139 19

With respect to a particular account in that GRC (Account 588), the 20 Commission went on to state: 21

Absent a specific explanation of why 1987 recorded data best reflects the 22 estimated 1990 expenses of an account with fluctuating expense levels and 23 no discernible trends, we find it most appropriate to use a four-year 24 average as the base 1990 estimate.140 25

Based on the behavior of customer advance accounts, SCE’s approach yields 26

the most reasonable forecast of test year balances. 27

B. Materials And Supplies 28

1. ORA Position 29

Transmission and Distribution M&S 30

ORA adjusts SCE’s proposed 2015 Transmission and Distribution Materials and 31

Supplies (T&D M&S) based on the difference between the $40,000 regression-derived T&D M&S 32

137 D.89-12-057, (mimeo) p. 15. 138 Id. 139 Id. 140 Id. at 29.

52

forecast factor adopted by the Commission in SCE’s 2009 GRC141 and SCE’s current GRC 1

regression-derived T&D M&S forecast factor of $55,000.142 ORA reduces SCE’s proposed 2015 2

T&D M&S balance by approximately 27% [ = (55,000 - 40,000)/55,000]143 or approximately $41 3

million. 4


a) ORA’s Proposed Reduction Calculation Is Arbitrary, Contradictory, Has 6

No Basis and Results in an Insufficient T&D M&S Balance 7

There are multiple problems with ORA’s approach: (1) ORA does not use the 8

same regression methodology found reasonable by the Commission in its 2009 and 2012 GRCs; (2) 9

ORA did not perform additional regression analyses or employ other methodologies in addition to 10

the regression analysis performed in this GRC calculation, rather ORA reduces SCE’s 2015 T&D 11

M&S balance in an arbitrary manner; (3) ORA argues for averaging the most recent years for the 12

forecast of Electric Construction Customer Advances, yet proposes to adjust T&D M&S with a 13

factor associated with economic conditions that existed several years ago; and, (4) ORA provides no 14

analysis to substantiate its proposed reduction. 15

As shown in Table III-6, although recent historical data shows that weighted 16

average T&D M&S inventory has grown by a compound annual growth rate of 4.5 percent since 17

2009, SCE applied an Operational Excellence adjustment of $41 million to the 2015 M&S forecast 18

of expenses, the bulk of which can be attributed to T&D M&S by proportion. 19

141 D.09-03-025, p. 273. 142 SCE-10, Vol. 2, p. 62. 143 ORA-24 Rate Base Workpaper incorrectly depicted this calculation. ORA-24, p. 7. The correct

calculation as shown was provided by ORA in response to data request SCE-DRA-034-GIE. See Appendix F.

53

Table III-6 Recorded T&D M&S Growth

(Nominal Weighted Average Balances, $000)

Item 2009 2010 2011 2012 2013*

Transmission & Distribution

104,012 119,324 118,319 113,519 123,937 4.5%

Compound Annual Growth Rate

* Recorded 2013 Average Balance provided in response to Data Request TURN-SCE-021, Question 8.

See Appendix F

Moreover, Table III-7 below shows that the 2013 T&D M&S recorded 1

balance was approximately $9.6 million greater than the 2013 forecast balance included in the GRC 2

requirement (unadjusted for Operational Excellence improvement credits that SCE applied as a 3

bottom line adjustment to its total yearly M&S requirement). 4

Table III-7 2013 Recorded vs. Forecast T&D M&S

(Nominal Weighted Average Balances, $000)

Item 2013 Forecast

2013 Recorded*

Variance %

Transmission & Distribution 114,370 123,937 9,567 8%

* Recorded provided in response to Data Request TURN-SCE-021, Question 8. See Appendix F.

Therefore, applying ORA’s additional $41 million adjustment to SCE’s 5

already slimmed down T&D M&S requirement would result in an insufficient T&D M&S Balance. 6

ORA’s recommendation should be rejected. 7

b) SCE’s Regression Analysis Is Reasonable 8

As mentioned above, ORA has provided no support for its recommendation to 9

ignore SCE’s latest regression analysis and M&S data other than a statement that “SCE’s 10

justification for this methodology is that the correlation is ‘strong’ between the expenditures and 11

inventory – SCE’s 2012 regression analysis results in an R square of 0.89.”144 SCE is employing the 12

same methodology found reasonable by the Commission since its 2009 GRC. In fact, in this case, 13

144 ORA-24, p. 7.

54

SCE has incorporated additional years of recorded data that ORA did not incorporate in its proposal. 1

Moreover, SCE’s 2012 GRC T&D regression calculations similarly resulted in an R square of 0.89. 2

As part of the Commission’s decision on SCE’s GRC, it specifically mentioned the adequacy of an 3

R square within this range with the following comments: 4

As in the 2009 GRC, we generally find SCE’s methodology to be 5 reasonable. Although the correlation factors are slightly lower (0.88 to 6 0.89) in this GRC, we are persuaded that the correlation is still strong at a 7 95% confidence level, and the $60,000 ratio is the result of more recent 8 data (2007-2009).145 9

In addition, SCE updated its regression analysis with 2013 recorded 10

information and determined that the R square with the latest available information was 0.90. 11

Therefore, SCE continues to feel confident in the reasonableness of its regression methodology. 12

c) M&S-Related Rate Base Adjustments 13

As discussed in Exhibit SCE-10, Volume 2,146 as part of its forecast SCE 14

proposed M&S-Related Rate Base Adjustments for unpaid sales tax liabilities and unpaid invoices. 15

These Rate Base Adjustments are driven by the level of actual M&S Inventory. In its 16

recommendation, ORA failed to properly reflect the impact of the proposed reduction in T&D M&S 17

on these Rate Base Adjustments. See Table III-8 below for the calculation of ORA’s 18

recommendation with the corresponding impacts to M&S-Related Rate Base Adjustments. 19

145 D.12-11-051, p. 632. 146 SCE-10, Vol. 2, pp. 58-59.

55

Table III-8 M&S Accounting Adjustments

(ORA’s Recommendation, $000)

Item 2015

SCE's Proposed T&D M&S 149,990ORA's Recommendation 109,083

ORA's Adjustment 40,907

Accounting Adjustments Sales Tax Adj (1.32%)* 540 Unpaid Analysis (8.3%)* 3,395Total Accounting Adjustments 3,935

Op-Ex Adjustment (21.69%) 8,874

28,098

* This adjustment was calculated using 2013 recorded data.

ORA's Proposal with Accounting Adjustments

In addition, Operational Excellence improvement credits that SCE applied as 1

a bottom-line adjustment to its total yearly M&S requirement should also be proportionally reduced 2

if SCE’s T&D requirement is reduced by ORA’s proposal. 3

Despite the reasons stated above for rejecting ORA’s approach, if the 4

Commission nonetheless finds it reasonable to reduce T&D M&S, it should also reflect a 5

commensurate adjustment to M&S-Related Rate Base Adjustments. 6

C. Working Cash – Operational Cash 7

1. ORA Position 8

ORA accepts SCE’s Operational Working Cash estimates with one exception: ORA 9

proposes to eliminate the Cash Balances. ORA recommends SCE’s cash balances of $6 million be 10

removed from the Test Year 2015 working cash requirement, citing prior Commission decisions 11

D.09-03-025 and D.06-05-016, where the Commission authorized no funding for Cash Balances. 12

56

2. TURN Position 1

a) Prepayments 2

TURN proposes to remove the Mountainview Hot Gas Path Prepayment. In 3

Data Request response TURN DR 21-23 (See Confidential Appendix F). SCE agreed that this 4

prepayment is not a required addition to Rate Base under the rate treatment that SCE has proposed. 5

SCE proposed averaging Hot Gas Path adjustment costs incurred during the rate cycle over three 6

years. TURN agreed to this proposal with different parameters, as discussed in Section III.C of its 7

testimony. 8

b) Other Accounts Receivable 9

(1) Other Accounts Receivable for Non-Tariffed Products and 10

Services and Reserves for Uncollectibles 11

Citing SCE’s response to TURN DR 21-17 (See Appendix F), TURN 12

proposes to reduce Rate Base by: (1) $22.1 million associated with SCE’s incorrect inclusion of 13

non-tariffed products and services (NTP&S) related receivable balances in Rate Base, and (2) by 14

$3.3 million associated with SCE’s incorrect exclusion of certain uncollectable reserves balances 15

(pertaining to joint relocation, added facilities, interconnection facilities, and Catalina Island) from 16

Rate Base in the Application filing.”147 17

(2) Accounts Receivable from PBOPs Trust 18

In 2012, SCE identified some errors in the VEBA trust assignment 19

programming logic. As a result, the VEBA trust reimbursement had to be manually prepared on a 20

carrier-by-carrier basis. This manual process, along with the associated quality controls that were 21

needed, significantly delayed the VEBA trust reimbursement cycle time for 2012 and 2013. This 22

situation is anticipated to be corrected by the 2015 Test Year. TURN proposes to estimate PBOPs 23

trust receivables on the basis of 2011 average receivables, escalated to 2015 using a health care 24

escalation rate. TURN’s 2011 base year is $23,205,000. With escalation to 2015, TURN’s figure is 25

$30,537,000, which is $14,598,000 below Edison’s request. 26

147 TURN-05, Marcus, p. 126.

57

c) Long-Term Incentives 1

TURN opposes ratepayer funding of SCE’s Long-Term Incentive Plan 2

(LTIP), and thus reverses SCE’s reduction to Rate Base of $5.7 million, created by the timing 3

difference between the receipt of cash from ratepayers and the funding of the LTIP. 4


a) SCE’s Minimum Cash Balance Should Be Included in Working Cash 6

SCE does not disagree with the concept that only minimum required bank 7

balances should be included in working cash (as per Standard Practice U-16). However, the $6 8

million included in its proposed working cash is a required minimum balance. Although it is not an 9

institutionally required minimum balance specifically mandated by the banks, it is a functionally 10

required minimum balance. SP U-16 does not specifically state the “required bank deposit” must be 11

required by a financial institution. To the contrary, SP U-16 provides for the use of analyst 12

judgment with respect to the cash balance component of working cash: 13

This balance sheet account includes the utility’s current cash monies on 14 hand and bank deposits except those classed as petty cash or other 15 working funds. The largest portion [of] this account will generally be 16 actually working, such as cash on hand to pay expenses prior to the receipt 17 of payments from customers. Other amounts of cash may be on hand to 18 pay dividends, debt interest or costs for construction purposes. The 19 account fluctuates with regular frequency depending upon anticipated 20 large cash outlays such as accrued taxes, bond interest, dividends, and 21 construction expenditures. The problem, therefore, is to separate cash 22 items which are necessary for the utility ‘to operate economically and 23 efficiently’.148 24

If SP U-16 intended that only minimum bank deposits required by a financial 25

institution should be included in Rate Base, there would be no need for the use of judgment or 26

analysis to determine what is necessary for the utility “to operate economically and efficiently.” The 27

$6 million included in SCE’s working cash requirement represents the average balance remaining at 28

the end of the business day in which SCE is unable to invest due to the nature of banking operations 29

and deadlines. Third-party remittances (wires) received after the 2:00 Pacific investment cut-off 30

time cannot be appropriately invested until the next business day. Moreover, the full availability of 31

daily customer payment processing for investment is unknown to SCE until the next day. SCE is 32

148 CPUC Standard Practice U-16-W Determination of Working Cash Allowance, Chapter 3, paragraph 10.

58

necessarily conservative in its estimation of this cash available for investment because the cost of 1

overdrafts in prohibitively high to the company. The confluence of these constraints results in a 2

minimum bank cash balance that cannot be eliminated and should be reflected in the working cash. 3

b) Prepayments 4

SCE does not oppose TURN’s proposed removal of the Mountainview Hot 5

Gas Path Prepayment from Rate Base with the condition that SCE’s proposal for averaging Hot Gas 6

Path adjustment costs incurred during the rate cycle over three years (as outlined in SCE-18, Vol. 7

8-Mountainview O&M and Capital) is approved for SCE’s rates. If this proposal is not approved, it 8

would be appropriate to include the proposed prepayment for this expense in its working capital 9

requirement. 10

c) Other Accounts Receivable 11

(1) Other Accounts Receivable for Non-Tariffed Products and 12

Services and Reserves for Uncollectibles 13

SCE identified errors in its Other Accounts Receivable and 14

Uncollectable Reserves balances (as stated in its response to TURN DR 21-17 - See Appendix F) 15

through SCE’s own procedures after the Application filing. This issue was uncovered months before 16

receiving data requests from opposing parties. SCE’s errata reflects the corrected balances and as 17

noted in TURN’s testimony, SCE provided the corrected information in response to TURN data 18

request 21-17. 19

(2) Accounts Receivable from PBOPs Trust 20

Although SCE does not agree with TURN’s characterization of the 21

issue, SCE acknowledges that the receivable balance for this account should be reduced. SCE works 22

closely with the benefit administrator and health insurance carriers to ensure that vendor transitions 23

are handled as accurately and efficiently as possible. The complexity inherent in accurately 24

allocating expenses to the appropriate funding vehicles may, for a period of time, result in a delay in 25

obtaining reimbursement. SCE believes that any delays are a normal consequence of the need to 26

occasionally replace vendors to ensure that the vendors SCE utilizes are the most cost effective and 27

high value available in the marketplace. However, since the problems experienced in 2012 have 28

been remediated for 2014 and going forward, SCE recognizes that a lower receivable balance for this 29

59

account should be utilized for the test year. SCE accepts TURN’s recalculation of the balance as 1

reasonable.149 2

d) Long-Term Incentives 3

As stated in SCE-22, Chapter IV, SCE disagrees with TURN’s position 4

regarding ratepayer funding of SCE’s Long-Term Incentive Plan (LTIP). However, if TURN’s 5

position on this matter is approved by the Commission, SCE will make this adjustment to increase 6

rate base by $5.7 million accordingly. 7

In addition, in Exhibit ORA-16, ORA recommended no ratepayer funding for 8

Long-Term Incentive Program expenses.150 Yet, ORA did not reflect a corresponding adjustment to 9

remove the associated Rate Base offset for LTIP as TURN proposed. 10

D. Lead Lag Study 11

1. ORA Position 12

a) ORA’s Adjustment to Income Tax Lags 13

(1) Federal Income Tax (FIT) Lag Days 14

ORA proposes a three-year average of tax lag data from 2008, 2009, 15

and 2011 to develop the estimate of FIT lag days. ORA stated that “the 2010 lag days was 16

uncharacteristic (due to tax refunds) compared to the other years. Based on this, ORA did not 17

include the 2010 data in calculating the average.”151 ORA recommends the Commission adopt an 18

FIT lag of 119.21 days for 2015 based on its three-year averaging methodology. 19

(2) California Corporate Franchise Tax (CCFT) Lag Days 20

Like FIT, ORA proposes a three-year average of 2008, 2009 and 2011 21

tax lag data to develop the estimate of CCFT lag days. ORA excludes 2010 data as being 22

“uncharacteristic (due to tax refunds).”152 ORA recommends that the Commission adopt a CCFT of 23

82.12 lag days for 2015 based on its three-year average. 24

149 The adjusted balance identified in TURN-05, Marcus, p. 128 was incorrect. TURN subsequently

confirmed the correct adjusted balance of $30,353,678 in response to data request SCE-TURN-014, Q-1. See Appendix F.

150 ORA-16, p. 38. 151 ORA-24, p. 1. 152 ORA-24, p. 12.

60

2. TURN Position 1

a) Revenue Lag 2

TURN proposes reducing SCE’s 2015 revenue requirement by $5.676 million 3

to account for the return of $593 million of GHG revenues to SCE customers.153 This reduces 4

uncollectible accounts expenses by $1.317 million (using ORA’s percentage), and reduces cash 5

working capital rate base by $37.2 million (reducing return and taxes by $4.359 million). TURN 6

states that if the Commission does not adopt TURN’s position regarding cash working capital, it 7

should instead reduce the 2015 revenue requirement by an even larger amount - a total of $6.712 8

million (the same $1.317 million in uncollectibles plus a reduction in reduced franchise fee expenses 9

of $5.395 million). 10

TURN claims SCE has made internally inconsistent assumptions and has 11

chosen an outcome that benefits itself because SCE’s proposal gives ratepayers none of 12

uncollectibles, franchise fees, or a reduction in billing lag. TURN asserts that uncollectibles are 13

undeniably avoided by GHG revenues, and that ratepayers should also be credited with either 14

franchise fees or reduced billing lag, but not both, depending on whose money it is.154 15

TURN calculates its California Climate Credit related billing lag adjustment 16

by assigning a billing lag of 15.2 days to 4.004% of revenue and SCE’s calculation of 44.6 lag days 17

to the other 95.996% of revenue, the total Revenue Lag Days is effectively lowered to 43.42 days, 18

resulting in the $37.2 million reduction. 19

b) Purchased Power Lag Days 20

TURN proposes adjusting SCE’s Purchased Power Lag Days21

days, effectively

increasing SCE’s Purchased Power Lag Days by days, reducing Rate Base by $198 thousand. 24

c) Labor Lag Days 25

TURN has proposed a reduction to Rate Base in the amount of $2.2 million to 26

reflect its recommendation to charge LTIP to shareholders. By removing $18.1 million of labor with 27

153 TURN-05, Marcus p. 113. 154 Id. at 115.

61

0 lag days, TURN has recalculated an increase to the remaining Labor Lag Days from 11.54 to 1

11.62. 2

d) Income Tax Lag Days 3

TURN opposes SCE’s five-year average for Federal Income Tax (FIT) lag 4

and proposes a dollar-day weighted average of 2008-09 alone for the FIT lag, calculated as 102.09 5

days. The years 2008-09 were chosen because they were the only two years in the recent period that 6

contain substantial amounts of cash taxes paid. For the California Corporate Franchise Tax (CCFT) 7

lag, TURN uses a five-year average in dollar-days because substantial amounts of state taxes were 8

paid in each of the five years, calculated as 56.33 days. 9


a) ORA’s and TURN’s Income Tax Lag Proposals are Arbitrary and 11

Unsupported. 12

For FIT and CCFT tax lags, ORA has excluded years when SCE paid no taxes 13

(2012) or received refunds (2010), specifically mentioning 2010 as uncharacteristic. Excluding 2010 14

and 2012 from the average is not reasonable and is done with the sole purpose of creating the 15

maximum lag days out of the arrayed data. 16

Similarly, for its FIT lag proposal, TURN simply picks the two years (2008 17

and 2009) with the highest tax payments for its lag calculation (excluding years where SCE paid 18

lower taxes, received refunds or paid no taxes). TURN’s CCFT tax lag calculation is essentially the 19

same as SCE’s 5 year average calculation (which includes 2012 - a year where SCE paid zero taxes) 20

with the difference being that it dollar weights the calculation to skew the numbers to periods with 21

higher tax payment amounts. TURN’s inconsistent FIT and CCFT calculation methods are also 22

designed only to produce higher tax lags--although with the appearance of more reasonableness than 23

ORA’s proposals. 24

ORA’s and TURN’s cherry-picking of certain tax years to compute FIT/CCFT 25

and FIT is unreasonable. From 2002-2012, SCE experienced refunds or paid no taxes in six of 26

eleven years. These occurrences are hardly anomalous, with the payment of taxes varying not only 27

on economic conditions but changes in tax law. With the historical unpredictable fluctuation of 28

these payments and lack of a discernable trend, SCE chose to apply a five-year average of recent 29

recorded data consistent with D 89.12.057. In addition, TURN’s five-year average CCFT 30

calculation should also be rejected. TURN appears to agree with SCE that a five-year average 31

62

period is an appropriate calculation but bases its lag calculation on dollar weighting. This biased 1

method lends greater weight to periods of higher tax payments and provides no value in determining 2

futures tax lags. 3

In SCE’s 2009 GRC, the Commission adopted SCE’s five-year average (even 4

given anomalous data in one year),155 recognizing it was appropriate considering the experienced 5

fluctuation in income tax lag days. Taking that into consideration, SCE’s five-year average of tax 6

lag days is appropriate. ORA’s and TURN’s proposals should be rejected. 7

b) Revenue Lag Days 8

As discussed elsewhere in this rebuttal (SCE-26, Vol 1),156 TURN mistakenly 9

believes that SCE does not provide ratepayers the benefit of a reduction in Franchise Fees and 10

Uncollectables (FF&U) due to GHG Revenues collected. SCE does in fact gross up GHG revenues 11

for FF&U for return to customers. Strictly following TURN’s argument regarding the either /or 12

proposition in giving the ratepayer the benefit of a reduction of billing lag or Franchise Fees, this 13

gross up of Franchise Fees to GHG revenues in the GHG Revenue Balancing Account (GHGRBA) 14

would render its position on billing lag moot. 15

However, SCE analyzed the issue and noted that the notion of reducing billing 16

lag due to GHG revenues collected for customers does indeed have merit outside of any Franchise 17

Fee reduction. This is because the GHGRBA account liability to customers (cash pre-collected for 18

customers) is relieved (and SCE stops paying interest on the amounts) at time that the associated 19

credits are presented on customer bills. This differs from the usual set of circumstances associated 20

with returning balancing account over-collections to customers. SCE also noted that GHG cost 21

impacts SCE’s Lead-Lag study via the Power Procurement Lag calculation, but there is no offsetting 22

impact of GHG revenues collected up-front for these costs in the working capital study. 23

For these reasons, SCE agrees that the revenue lag as presented in the 24

Application should be reduced. However, TURN’s calculation to determine the adjustment should 25

be corrected. In order to determine the “% GHG” and “Remaining %” weighting factors for its 26

155 D.09-03-025, pp. 253-57. 156 TURN-05, Marcus, p. 113. Other Accounting and Ratemaking Issues, A. Ratemaking Treatment of

Greenhouse Gas (GHG) Revenues Returned to Utility Customers.

63

calculation, TURN157 divides Average monthly total GHG revenue by Average monthly receivable in 1

2012 (see TURN Original Calculation in Table I-7 below). Since the 2012 receivables basis in the 2

calculation does not include GHG costs billed to customers (which first occurred in 2014), the GHG 3

% factor in the calculation is slightly overstated. To correct this, SCE recalculated the weighing 4

factors by adding an estimate of average monthly GHG cost billed to customers to the 2012 5

receivables basis. See Table III-9 for a comparison of TURN’s original calculation and SCE’s 6

revised calculation. 7

Table III-9 GHG Revenue Billing Lag Weighting Factors Recalculated

(Nominal Average Balances, $000) TURN ORIGINAL CALCULATIONAverage monthly receivable in 2012 1,234,509 Average monthly total GHG revenue 49,433 4.004% -GHG

95.996% -Remaining

SCE RECALCULATION TO INCLUDE GHG COST IN RECEIVABLESAverage monthly receivable in 2012 1,234,509 Add estimated average monthly GHG cost 34,993Revised average monthly receivables basis 1,269,502 Average monthly total GHG revenue 49,433 3.894% -GHG

96.106% -Remaining

In addition, TURN’s adjustment calculation fails to consider SCE’s Rate Base 8

Adjustment in which SCE offset its working cash requirement for expected Revenue Lag benefits 9

associated SmartConnectTM driven billing improvements.158 If the existing SmartConnectTM Rate 10

Base offset is considered, an effective Total Revenue Lag of days should be used in the 11

calculation versus 44.6 days. See Table III-10 below which converts the SmartConnectTM offset into 12

its equivalent revenue lag impact for purposes of determining SCE’s effective Total Revenue Lag to 13

the used in the GHG revenue adjustment calculation. 14

157 TURN-05, Marcus Public Workpapers, Ch XI, TURN GHG Revenue impact workpaper starting with DR

36-08 Attachment.xlsx. 158 SCE-10, Vol. 2, p. 79, Table V-17.

64

Table III-10 SmartConnectTM Offset Equivalent Revenue Lag Impact

('000s - Nominal) Column A Column B Column C Column D

Existing SmartConnect Rate Base Offset Applied

to Working Cash

Avg Daily Expense for 2015 Working Cash

Calculation

Rate Base Offset Equivalent in Working Cash Days

(Col A/ Col B)

Unadjusted Total Revenue Lag

Effective Revenue Lag -- Reflects Rate Base Offset in

Column A(Col D - Col C)

$32,582 44.6

Table III-11 below recomputes TURN’s composite revenue lag calculation 1

with SCE’s revised weighting factors and Effective Total Revenue Lag as discussed above. 2

Table III-11 Composite Revenue Lag Days Recalculated

% GHG Billing Lag Remaining %Effective

Total LagComposite Lag

All Revenues 3.894% 15.2 96.106%

SCE’s corrections to the calculation result in a Revenue Lag reduction of 3

days (the difference between total lag and composite lag) versus TURN’s result of 1.18 days. The 4

rate base reduction amount associated with SCE’s corrected calculation is $ 34,933,000 (return and 5

taxes reduction of $ 4,091,000 – assuming TURN’s return and tax rate of 11.71%) versus TURN’s 6

$37,228,000 (return and taxes of $4,359,000) reduction159. 7

c) Purchased Power Lag Days 8

9

See Confidential

Appendix F. 12

159 Note: if the composite lag rate in Table I-9 is used for Revenue Lag, SCE will remove the existing $32.6

million SmartConnectTM Rate Base offset adjustment from the RO Model because the smart meter related billing improvements reduction in revenue lag is now fully reflected in the composite lag rate (as shown in Table I-8).

65

1

SCE’s Purchased Power Lag Days calculation for the rate case period.

and that SCE did not include these expenses in the Power

Procurement expense forecast used for the working cash study. Therefore, given these 10

circumstances and the de minimis nature of the adjustment, SCE does not oppose TURN’s request. 11

d) Labor Lag Days 12

As stated above and elsewhere, SCE disagrees with TURN’s position 13

regarding zero ratepayer funding of SCE’s Long-Term Incentive Plan (LTIP). However, if TURN’s 14

position on this matter is upheld by the Commission, SCE will remove the $18.1 million of LTIP 15

related labor cost from its calculation which will increase to the remaining Labor Lag Days from 16

11.54 to 11.62.17

66

IV. 1

CUSTOMER DEPOSITS 2

A. Introduction 3

SCE’s direct testimony describes in detail the reasons why customer deposits should not be 4

deducted from rate base.160 This testimony responds to arguments by TURN’s witness William 5

Marcus supporting a rate base adjustment.161 TURN’s testimony ignores key attributes of customer 6

deposits and underplays their impact on SCE. In addition, TURN’s arguments are countered by the 7

Commission’s findings in the recent decision in PG&E’s 2014 General Rate Case.162 8

1. TURN Presents an Inaccurate View of Short-term Interest Rates 9

TURN’s testimony notes that SCE’s commercial paper interest rate has recently been 10

below 0.5% and uses this fact to downplay the differences between customer deposits and other 11

working cash adjustments.163 In doing so, TURN ignores historical interest rate levels and the high 12

likelihood of future rate increases. Current short-term interest rates stem from unprecedented 13

Federal Reserve economic stimulus in response to the financial crisis that began in 2008. In 2007, 14

three month commercial paper rates averaged nearly 5.0%,164 ten times TURN’s recent statistic. 15

Furthermore, as is well known, the U.S. economy is showing signs of recovery and the Federal 16

Reserve is expected to end the accommodative policies supporting this period of historic low rates. 17

IHS Global Insight is presently forecasting commercial paper rates to reach 4.0% within SCE’s 18

current rate case cycle.165 Should the economy rebound more quickly, rates could rise even higher. 19

As a point of reference, SCE’s current authorized embedded cost of long-term debt is 5.49%.166 As 20

160 SCE-10, Vol. 02, Revision 1, pp. 82-94. 161 Although Table 24-1 of ORA’s testimony shows a zero dollar adjustment to rate base in the line item for

customer deposits, ORA provides no discussion of this position in its testimony. As a result, SCE’s testimony only responds to TURN’s positions. (See ORA-24, p. 3.)

162 D.14-08-032. 163 TURN-05, Marcus, p. 133. 164 The 90-day AA Non-Financial Commercial Paper Rate for 2007 averaged 4.92%. Annual data series

downloaded from: http://www.federalreserve.gov/releases/h15/data.htm. 165 90-day Commercial Paper Rates for 3rd and 4th quarter 2017 from IHS Global Insight July 2014 Short

Term Macro Forecast. 166 D. 12-12-034, p. 52.

67

a result, TURN’s deeming commercial paper rates a “pittance” discounts the financial reality of its 1

recommendation. 2

2. Customer Deposits Are Debts, and Are Not Like Accruals or Other Working 3

Cash Adjustments 4

TURN attempts to conflate customer deposits with other working cash adjustments 5

despite fundamental differences. Customer deposits are not like working cash adjustments such as 6

vacation accruals. Accruals are deductions made to account for timing differences between when 7

costs are incurred and when bills are paid. This delayed payout improves cash flow and makes 8

working cash available, but these accounting liabilities differ from customer deposits, which are 9

debts owed to customers. 10

TURN argues “The only difference between miscellaneous accounts payable and 11

customer deposits is the small amount of interest paid on the deposits.”167 However, unlike accruals, 12

customer deposits are collected from specific customers (either individuals or businesses) and 13

separately tracked as amounts owed these customers. In addition, customer deposits interest is 14

included in the Company’s credit ratio calculations. As discussed in SCE’s direct testimony,168 the 15

Commission has distinguished interest-bearing customer deposits from non-interest bearing deposits 16

and other working cash adjustments, stating that interest bearing deposits are excluded from working 17

cash.169 Although TURN implies this perspective is old and outdated,170 the Commission adopted 18

the same distinction for water companies in 2006.171 More importantly, after a review of customer 19

deposits in PG&E’s 2014 General Rate Case, the Commission’s August 2014 decision stated: 20

167 Turn-05, Marcus, p. 133. 168 SCE-10, Vol. 02, Revision 1, p. 89. 169 C.P.U.C., SP U-16, Determination of Working Cash Allowance, pp. 3-7. 170 TURN-05, Marcus, p. 136. 171 C.P.U.C., SP U-16-W, Determination of Working Cash Allowance, pp. 1-8.

68

We find that TURN’s proposed treatment of customer deposits deviates from 1 Commission SP U-16 which excludes interest bearing customer deposits from 2 working cash, and only includes non-interest-bearing customer deposits. As the 3 Commission has previously held, SP U-16 is only a guide, and deviations may be 4 appropriate where circumstances so warrant.147 As a general matter, however, we 5 presume that ratemaking treatment consistent with SP U-16 should be deemed 6 reasonable, especially where there are no special circumstances that justify a 7 deviation.172 8

3. TURN’s Assertions about Financial Risk are Conjecture 9

Regarding the financial risks associated with its recommended rate base adjustment, 10

TURN’s witness states: “The more reasonable assumption is that, like the current interest paid on 11

deposits, any impact rounds to zero.”173 TURN’s witness argues that the Commission understands 12

the risks it has imposed, and because no rating downgrade has occurred, the rate base adjustment has 13

no impact. However, the fact that a Commission action has not caused a rating downgrade does not 14

mean it has no impact on risk. 15

Customer deposits are admittedly not sizeable enough to cause a credit rating 16

downgrade on their own at the present time. However, as debts, they affect SCE’s interest coverage 17

like other borrowing. As discussed in detail in SCE’s direct testimony, treating customer deposits as 18

if they were equity weakens credit quality. The risks associated with customer deposits policy must 19

be viewed within the context of SCE’s overall risk position. TURN argues that the financial risks 20

from customer deposits adjustments do not dissuade other commissions from applying ratemaking 21

adjustments.174 Many factors affect a utility’s risk profile, and no conclusions regarding a 22

company’s ability to withstand additional risk can be drawn without looking at each utility and its 23

particular circumstances. As a result, TURN’s remarks regarding debt ratios relative to SCE provide 24

no valid insights. For example, as TURN acknowledges, regulators in some states have not adopted 25

a rate base adjustment, but rather include customer deposits in the utility capital structure.175 26

Furthermore, TURN relegates to a footnote thefact that unlike other states, California 27

reduces rate base for fuel inventories, further increasing the debt in SCE’s financial capital 28

172 D.14-08-032, pp. 627-628. 173 TURN-05, Marcus, p. 136. 174 Id. at p. 138. 175 Id. at p. 135.

69

structure.176 As described in SCE’s direct testimony, excluding fuel inventories from rate base 1

compounds the financial risk imposed by the customer deposits ratebase adjustment.177 2

4. Customer Deposits Are Debt, Not Equity 3

TURN makes no attempt to directly rebut SCE’s testimony that a rate base 4

adjustment wrongly treats customer deposits as if they had an equity component, providing excess 5

returns to customers. As SCE’s direct testimony notes, customers face a risk on their deposits 6

similar to commercial paper rate lenders, yet receive a rate of return equal to the long-term cost of 7

capital.178 Customer deposits do not provide SCE with the benefits of equity investments, including 8

the ability to suspend dividend payments, and the benefit that equity investments never need to be 9

paid back. 10

TURN argues that fluctuations in customer deposits balances do not mean they are 11

not permanent capital.179 As SCE’s direct testimony discusses, fluctuations will result from changes 12

in Commission policies and new approaches to billing, factors completely independent of SCE’s 13

capital needs. Even if customer deposits could be deemed “permanent” to some extent, they 14

certainly cannot be deemed to be equivalent to real equity, which is issued or redeemed at the sole 15

discretion of SCE’s management. In PG&E’s recent decision, the Commission agreed, stating: 16

“Customer deposits are not equity.”180 As discussed further below, there are no fundamental 17

differences between SCE and PG&E that would negate the conclusion that customer deposits are not 18

equity. 19

5. Differences between PG&E and SCE Do Not Invalidate SCE’s Position that 20

Customer Deposits Should Be Excluded from Rate Base 21

TURN’s testimony states “There are significant differences between Edison and 22

PG&E.”181 TURN points out differences in SCE’s and PG&E’s balancing account undercollections, 23

176 Id. at p. 139. 177 SCE-10, Vol. 02, Revision 1, p. 92. 178 Id. 179 TURN-05, Marcus, p. 136. 180 D.14-08-032, p. 627. 181 TURN-05, Marcus, p. 138. Interestingly, Mr. Marcus’ testimony in PG&E’s 2014 GRC states with regard

to customer deposits: “TURN does not believe that there is any significant difference between PG&E and Edison on this issue.” A.12-11-009, p. 83.

70

and quotes the Commission’s recent statement in PG&E’s GRC that customer deposits balances 1

should be applied to undercollections first rather than applying the deposits as rate base 2

adjustments.182 TURN does not comment on the fact that the Decision does not apply any deposits 3

as rate base adjustments. Differences in balancing account balances are irrelevant. 4

TURN also points to differences between SCE’s and PG&E’s nuclear fuel balances in 5

arguing for different treatment for SCE.183 Although it is true that SCE’s nuclear fuel balances have 6

declined with the closure of the company’s San Onofre nuclear plant, SCE retains sizeable fuel 7

inventories through its partial ownership of the Palo Verde Nuclear plant in Arizona. SCE’s Palo 8

Verde fuel inventory was valued at $132 million184 as of year-end 2013. It is improper for TURN to 9

argue that $180 million in customer deposits is “substantial”185 yet imply that the value of this 10

inventory is irrelevant. As a result, this distinction also has little relevance where customer deposits 11

are concerned. 12

6. Conclusion: SCE’s Customer Deposits Should Not Be Excluded from Rate Base 13

As discussed above, any differences between the two companies bear little relevance 14

to the question of proper regulatory treatment of customer deposits. SCE remains the only 15

California utility with a rate base adjustment for customer deposits. As discussed in SCE’s direct 16

testimony, neither San Diego Gas and Electric nor Southern California Gas Company’s receive rate 17

base reductions for customer deposits.186 The Commission should erase this disparity.18

182 Id. at p. 139. 183 Id. 184 Edison International Financial and Statistical Report, 2013, p. 19. 185 TURN-05, Marcus, p. 134 186 SCE-10, Vol. 02, Revision 1, p. 84.

Appendix A

Accounting Literature

9/6/2014 360-10-35 Subsequent Measurement - Print Friendly

https://asc.fasb.org/print&rendercmd=section&trid=2155842 1/8

September 06, 2014

360 Property, Plant, and Equipment 10 Overall 35 Subsequent Measurement

General Note: The Subsequent Measurement Section provides guidance on an entity’ssubsequent measurement and subsequent recognition of an item. Situations that may result insubsequent changes to carrying amount include impairment, fair value adjustments, depreciationand amortization, and so forth.

General

360-10-35-1 This Subsection addresses depreciation of property, plant, and equipment and thepost acquisition accounting for an interest in the residual value of a leased asset.

> Depreciation

360-10-35-2 This guidance addresses the concept of depreciation accounting and the variousfactors to consider in selecting the related periods and methods to be used in such accounting.

360-10-35-3 Depreciation expense in financial statements for an asset shall be determined basedon the asset's useful life.

360-10-35-4 The cost of a productive facility is one of the costs of the services it renders duringits useful economic life. Generally accepted accounting principles (GAAP) require that this cost bespread over the expected useful life of the facility in such a way as to allocate it as equitably aspossible to the periods during which services are obtained from the use of the facility. Thisprocedure is known as depreciation accounting, a system of accounting which aims to distribute thecost or other basic value of tangible capital assets, less salvage (if any), over the estimated usefullife of the unit (which may be a group of assets) in a systematic and rational manner. It is a processof allocation, not of valuation.

360-10-35-5 See paragraph 360-10-35-20 for a discussion of depreciation of a new cost basisafter recognition of an impairment loss.

360-10-35-6 See paragraph 360-10-35-43 for a discussion of cessation of depreciation on long-lived assets classified as held for sale.

> > Declining Balance Method

360-10-35-7 The declining-balance method is an example of one of the methods that meet therequirements of being systematic and rational. If the expected productivity or revenue-earningpower of the asset is relatively greater during the earlier years of its life, or maintenance chargestend to increase during later years, the declining-balance method may provide the most satisfactoryallocation of cost. That conclusion also applies to other methods, including the sum-of-the-years'-



digits method, that produce substantially similar results.

Pending Content: Transition Date: (P) December 15, 2016; (N) December 15, 2018 Transition Guidance: 606-10-65-1

The declining-balance method is an example of one of the methods that meet the requirementsof being systematic and rational. If the expected productivity of the asset or ability of the assetto generate revenue is relatively greater during the earlier years of its life, or maintenancecharges tend to increase during later years, the declining-balance method may provide themost satisfactory allocation of cost. That conclusion also applies to other methods, including thesum-of-the-years'-digits method, that produce substantially similar results.

> > Loss or Damage Experience as a Factor in Estimating Depreciable Lives

360-10-35-8 In practice, experience regarding loss or damage to depreciable assets is in somecases one of the factors considered in estimating the depreciable lives of a group of depreciableassets, along with such other factors as wear and tear, obsolescence, and maintenance andreplacement policies.

> > Unacceptable Depreciation Methods

360-10-35-9 If the number of years specified by the Accelerated Cost Recovery System of theInternal Revenue Service (IRS) for recovery deductions for an asset does not fall within areasonable range of the asset's useful life, the recovery deductions shall not be used as depreciationexpense for financial reporting.

360-10-35-10 Annuity methods of depreciation are not acceptable for entities in general.

> > Accounting Changes

360-10-35-11 See paragraphs 250-10-45-17 through 45-20 for guidance on the accounting andpresentation of changes in methods of depreciation.

360-10-35-12 [Paragraph not used]

> Adjusting the Residual Value in Leased Assets by a Third Party

360-10-35-13 The following paragraph provides guidance on how an entity acquiring an interestin the residual value of a leased asset shall account for that asset during the lease term.

360-10-35-14 An entity acquiring an interest in the residual value of any leased asset,irrespective of the classification of the related lease by the lessor, shall not recognize increases tothe asset's estimated value over the remaining term of the related lease, and the asset shall bereported at no more than its acquisition cost until sale or disposition. If it is subsequentlydetermined that the fair value of the residual value of a leased asset has declined below thecarrying amount of the acquired interest and that decline is other than temporary, the asset shall bewritten down to fair value, and the amount of the write-down shall be recognized as a loss. That fairvalue becomes the asset's new carrying amount, and the asset shall not be increased for anysubsequent increase in its fair value before its sale or disposition.

Impairment or Disposal of Long-Lived Assets



360-10-35-15 There are unique requirements of accounting for the impairment or disposal oflong-lived assets to be held and used or to be disposed of. Although this guidance deals withmatters which may lead to the ultimate disposition of assets, it is included in this Subsectionbecause it describes the measurement and classification of assets to be held and used and assetsheld for disposal before actual disposition and derecognition. See the Impairment or Disposal ofLong-Lived Assets Subsection of Section 360–10–40 for a discussion of assets or asset groups forwhich disposition has taken place in an exchange or distribution to owners.

> Long-Lived Assets Classified as Held and Used

360-10-35-16 This guidance addresses how long-lived assets or asset groups that are intendedto be held and used in an entity's business shall be reviewed for impairment.

> > Measurement of an Impairment Loss

360-10-35-17 An impairment loss shall be recognized only if the carrying amount of a long-livedasset (asset group) is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset (asset group) is not recoverable if it exceeds the sum of the undiscounted cash flowsexpected to result from the use and eventual disposition of the asset (asset group). Thatassessment shall be based on the carrying amount of the asset (asset group) at the date it is testedfor recoverability, whether in use (see paragraph 360-10-35-33) or under development (seeparagraph 360-10-35-34). An impairment loss shall be measured as the amount by which thecarrying amount of a long-lived asset (asset group) exceeds its fair value.

> > > Assets Subject to Asset Retirement Obligations

360-10-35-18 In applying the provisions of this Subtopic, the carrying amount of the asset beingtested for impairment shall include amounts of capitalized asset retirement costs. Estimated futurecash flows related to the liability for an asset retirement obligation that has been recognized in thefinancial statements shall be excluded from both of the following:

a. The undiscounted cash flows used to test the asset for recoverability

b. The discounted cash flows used to measure the asset’s fair value.

360-10-35-19 If the fair value of the asset is based on a quoted market price and that priceconsiders the costs that will be incurred in retiring that asset, the quoted market price shall beincreased by the fair value of the asset retirement obligation for purposes of measuring impairment.

> > Adjusted Carrying Amount Becomes New Cost Basis

360-10-35-20 If an impairment loss is recognized, the adjusted carrying amount of a long-livedasset shall be its new cost basis. For a depreciable long-lived asset, the new cost basis shall bedepreciated (amortized) over the remaining useful life of that asset. Restoration of a previouslyrecognized impairment loss is prohibited.

> > When to Test a Long-Lived Asset for Recoverability

360-10-35-21 A long-lived asset (asset group) shall be tested for recoverability whenever eventsor changes in circumstances indicate that its carrying amount may not be recoverable. The followingare examples of such events or changes in circumstances:

a. A significant decrease in the market price of a long-lived asset (asset group)



b. A significant adverse change in the extent or manner in which a long-lived asset (assetgroup) is being used or in its physical condition

c. A significant adverse change in legal factors or in the business climate that could affect thevalue of a long-lived asset (asset group), including an adverse action or assessment by aregulator

d. An accumulation of costs significantly in excess of the amount originally expected for theacquisition or construction of a long-lived asset (asset group)

e. A current-period operating or cash flow loss combined with a history of operating or cashflow losses or a projection or forecast that demonstrates continuing losses associated with theuse of a long-lived asset (asset group)

f. A current expectation that, more likely than not, a long-lived asset (asset group) will be soldor otherwise disposed of significantly before the end of its previously estimated useful life. Theterm more likely than not refers to a level of likelihood that is more than 50 percent.

360-10-35-22 When a long-lived asset (asset group) is tested for recoverability, it also may benecessary to review depreciation estimates and method as required by Topic 250 or theamortization period as required by Topic 350. Paragraphs 250-10-45-17 through 45-20 and 250-10-50-4 address the accounting for changes in estimates, including changes in the method ofdepreciation, amortization, and depletion. Paragraphs 350-30-35-1 through 35-5 address thedetermination of the useful life of an intangible asset. Any revision to the remaining useful life of along-lived asset resulting from that review also shall be considered in developing estimates of futurecash flows used to test the asset (asset group) for recoverability (see paragraphs 360-10-35-31through 35-32). However, any change in the accounting method for the asset resulting from thatreview shall be made only after applying this Subtopic.

> > Grouping Long-Lived Assets Classified as Held and Used

360-10-35-23 For purposes of recognition and measurement of an impairment loss, a long-livedasset or assets shall be grouped with other assets and liabilities at the lowest level for whichidentifiable cash flows are largely independent of the cash flows of other assets and liabilities.However, an impairment loss, if any, that results from applying this Subtopic shall reduce only thecarrying amount of a long-lived asset or assets of the group in accordance with paragraph 360-10-35-28.

360-10-35-24 In limited circumstances, a long-lived asset (for example, a corporateheadquarters facility) may not have identifiable cash flows that are largely independent of the cashflows of other assets and liabilities and of other asset groups. In those circumstances, the assetgroup for that long-lived asset shall include all assets and liabilities of the entity.

360-10-35-25 In limited circumstances, an asset group will include all assets and liabilities of theentity. For example, the cost of operating assets such as corporate headquarters or centralizedresearch facilities may be funded by revenue-producing activities at lower levels of the entity.Accordingly, in limited circumstances, the lowest level of identifiable cash flows that are largelyindependent of other asset groups may be the entity level. See Example 4 (paragraph 360-10-55-35).

> > > Effect of Goodwill when Grouping

360-10-35-26 Goodwill shall be included in an asset group to be tested for impairment under thisSubtopic only if the asset group is or includes a reporting unit. Goodwill shall not be included in alower-level asset group that includes only part of a reporting unit. Estimates of future cash flows



used to test that lower-level asset group for recoverability shall not be adjusted for the effect ofexcluding goodwill from the group. The term reporting unit is defined in Topic 350 as the same levelas or one level below an operating segment. That Topic requires that goodwill be tested forimpairment at the reporting unit level.

360-10-35-27 Other than goodwill, the carrying amounts of any assets (such as accountsreceivable and inventory) and liabilities (such as accounts payable, long-term debt, and assetretirement obligations) not covered by this Subtopic that are included in an asset group shall beadjusted in accordance with other applicable generally accepted accounting principles (GAAP) beforetesting the asset group for recoverability. Paragraph 350-20-35-31 requires that goodwill be testedfor impairment only after the carrying amounts of the other assets of the reporting unit, includingthe long-lived assets covered by this Subtopic, have been tested for impairment under otherapplicable accounting guidance.

> > Allocating Impairment Losses to an Asset Group

360-10-35-28 An impairment loss for an asset group shall reduce only the carrying amounts of along-lived asset or assets of the group. The loss shall be allocated to the long-lived assets of thegroup on a pro rata basis using the relative carrying amounts of those assets, except that the lossallocated to an individual long-lived asset of the group shall not reduce the carrying amount of thatasset below its fair value whenever that fair value is determinable without undue cost and effort.See Example 1 (paragraph 360-10-55-20) for an illustration of this guidance.

> > Estimates of Future Cash Flows Used to Test a Long-Lived Asset for Recoverability

360-10-35-29 Estimates of future cash flows used to test the recoverability of a long-lived asset(asset group) shall include only the future cash flows (cash inflows less associated cash outflows)that are directly associated with and that are expected to arise as a direct result of the use andeventual disposition of the asset (asset group). Those estimates shall exclude interest charges thatwill be recognized as an expense when incurred.

360-10-35-30 Estimates of future cash flows used to test the recoverability of a long-lived asset(asset group) shall incorporate the entity’s own assumptions about its use of the asset (assetgroup) and shall consider all available evidence. The assumptions used in developing thoseestimates shall be reasonable in relation to the assumptions used in developing other informationused by the entity for comparable periods, such as internal budgets and projections, accrualsrelated to incentive compensation plans, or information communicated to others. However, ifalternative courses of action to recover the carrying amount of a long-lived asset (asset group) areunder consideration or if a range is estimated for the amount of possible future cash flowsassociated with the likely course of action, the likelihood of those possible outcomes shall beconsidered. A probability-weighted approach may be useful in considering the likelihood of thosepossible outcomes. See Example 2 (paragraph 360-10-55-23) for an illustration of this guidance.

360-10-35-31 Estimates of future cash flows used to test the recoverability of a long-lived asset(asset group) shall be made for the remaining useful life of the asset (asset group) to the entity.The remaining useful life of an asset group shall be based on the remaining useful life of theprimary asset of the group. For purposes of this Subtopic, the primary asset is the principal long-lived tangible asset being depreciated or intangible asset being amortized that is the mostsignificant component asset from which the asset group derives its cash-flow-generating capacity.The primary asset of an asset group therefore cannot be land or an intangible asset not beingamortized.

360-10-35-32 Factors that an entity generally shall consider in determining whether a long-livedasset is the primary asset of an asset group include the following:

a. Whether other assets of the group would have been acquired by the entity without the asset



b. The level of investment that would be required to replace the asset

c. The remaining useful life of the asset relative to other assets of the group. If the primaryasset is not the asset of the group with the longest remaining useful life, estimates of futurecash flows for the group shall assume the sale of the group at the end of the remaining usefullife of the primary asset.

360-10-35-33 Estimates of future cash flows used to test the recoverability of a long-lived asset(asset group) that is in use, including a long-lived asset (asset group) for which development issubstantially complete, shall be based on the existing service potential of the asset (asset group) atthe date it is tested. The service potential of a long-lived asset (asset group) encompasses itsremaining useful life, cash-flow-generating capacity, and for tangible assets, physical outputcapacity. Those estimates shall include cash flows associated with future expenditures necessary tomaintain the existing service potential of a long-lived asset (asset group), including those thatreplace the service potential of component parts of a long-lived asset (for example, the roof of abuilding) and component assets other than the primary asset of an asset group. Those estimatesshall exclude cash flows associated with future capital expenditures that would increase the servicepotential of a long-lived asset (asset group).

360-10-35-34 Estimates of future cash flows used to test the recoverability of a long-lived asset(asset group) that is under development shall be based on the expected service potential of theasset (group) when development is substantially complete. Those estimates shall include cash flowsassociated with all future expenditures necessary to develop a long-lived asset (asset group),including interest payments that will be capitalized as part of the cost of the asset (asset group).Subtopic 835-20 requires the capitalization period to end when the asset is substantially completeand ready for its intended use.

360-10-35-35 If a long-lived asset that is under development is part of an asset group that is inuse, estimates of future cash flows used to test the recoverability of that group shall include thecash flows associated with future expenditures necessary to maintain the existing service potentialof the group (see paragraph 360-10-35-33) as well as the cash flows associated with all futureexpenditures necessary to substantially complete the asset that is under development (see thepreceding paragraph). See Example 3 (paragraph 360-10-55-33). See also paragraphs 360-10-55-7through 55-18 for considerations of site restoration and environmental exit costs.

> > Fair Value

360-10-35-36 For long-lived assets (asset groups) that have uncertainties both in timing andamount, an expected present value technique will often be the appropriate technique with which toestimate fair value.

> Long-Lived Assets Classified as Held for Sale

360-10-35-37 This guidance addresses the accounting for expected disposal losses for long-livedassets and asset groups that are classified as held for sale but have not yet been sold. Seeparagraphs 360-10-45-9 through 45-11 for the initial criteria to be met for classification as held forsale.

> > Measurement of Expected Disposal Loss or Gain

360-10-35-38 Costs to sell are the incremental direct costs to transact a sale, that is, the coststhat result directly from and are essential to a sale transaction and that would not have beenincurred by the entity had the decision to sell not been made. Those costs include brokercommissions, legal and title transfer fees, and closing costs that must be incurred before legal titlecan be transferred. Those costs exclude expected future losses associated with the operations of a



long-lived asset (disposal group) while it is classified as held for sale. Expected future operatinglosses that marketplace participants would not similarly consider in their estimates of the fair valueless cost to sell of a long-lived asset (disposal group) classified as held for sale shall not beindirectly recognized as part of an expected loss on the sale by reducing the carrying amount of theasset (disposal group) to an amount less than its current fair value less cost to sell. If the sale isexpected to occur beyond one year as permitted in limited situations by paragraph 360-10-45-11,the cost to sell shall be discounted.

360-10-35-39 The carrying amounts of any assets that are not covered by this Subtopic,including goodwill, that are included in a disposal group classified as held for sale shall be adjustedin accordance with other applicable GAAP prior to measuring the fair value less cost to sell of thedisposal group. Paragraphs 350-20-40-1 through 40-7 provide guidance for allocating goodwill to alower-level asset group to be disposed of that is part of a reporting unit and that constitutes abusiness. Goodwill is not included in a lower-level asset group to be disposed of that is part of areporting unit if it does not constitute a business.

360-10-35-40 A loss shall be recognized for any initial or subsequent write-down to fair valueless cost to sell. A gain shall be recognized for any subsequent increase in fair value less cost tosell, but not in excess of the cumulative loss previously recognized (for a write-down to fair valueless cost to sell). The loss or gain shall adjust only the carrying amount of a long-lived asset,whether classified as held for sale individually or as part of a disposal group.

360-10-35-41 See paragraphs 310-40-35-11 and 310-40-40-10 for guidance related todetermination of cost basis for foreclosed assets under Subtopic 310-40 and the measurement ofcumulative losses previously recognized under the preceding paragraph.

360-10-35-42 See paragraphs 830-30-45-13 through 45-15 for guidance regarding theapplication of Topic 830 to an investment being evaluated for impairment that will be disposed of.

> > Accounting While Held for Sale

360-10-35-43 A long-lived asset (disposal group) classified as held for sale shall be measured atthe lower of its carrying amount or fair value less cost to sell. If the asset (disposal group) is newlyacquired, the carrying amount of the asset (disposal group) shall be established based on its fairvalue less cost to sell at the acquisition date. A long-lived asset shall not be depreciated (amortized)while it is classified as held for sale. Interest and other expenses attributable to the liabilities of adisposal group classified as held for sale shall continue to be accrued.

> > Changes to a Plan of Sale

360-10-35-44 If circumstances arise that previously were considered unlikely and, as a result, anentity decides not to sell a long-lived asset (disposal group) previously classified as held for sale,the asset (disposal group) shall be reclassified as held and used. A long-lived asset that isreclassified shall be measured individually at the lower of the following:

a. Its carrying amount before the asset (disposal group) was classified as held for sale,adjusted for any depreciation (amortization) expense that would have been recognized had theasset (disposal group) been continuously classified as held and used

b. Its fair value at the date of the subsequent decision not to sell.

360-10-35-45 If an entity removes an individual asset or liability from a disposal grouppreviously classified as held for sale, the remaining assets and liabilities of the disposal group to besold shall continue to be measured as a group only if the criteria in paragraph 360-10-45-9 are met.Otherwise, the remaining long-lived assets of the group shall be measured individually at the lowerof their carrying amounts or fair values less cost to sell at that date.



> Long-Lived Assets to Be Disposed of Other than by Sale

360-10-35-46 This guidance addresses the accounting for impairment of long-lived assets andasset groups that are intended to be disposed of by abandonment.

> > Long-Lived Assets to Be Abandoned

360-10-35-47 For purposes of this Subtopic, a long-lived asset to be abandoned is disposed ofwhen it ceases to be used. If an entity commits to a plan to abandon a long-lived asset before theend of its previously estimated useful life, depreciation estimates shall be revised in accordance withparagraphs 250-10-45-17 through 45-20 and 250-10-50-4 to reflect the use of the asset over itsshortened useful life (see paragraph 360-10-35-22).

360-10-35-48 Because the continued use of a long-lived asset demonstrates the presence ofservice potential, only in unusual situations would the fair value of a long-lived asset to beabandoned be zero while it is being used. When a long-lived asset ceases to be used, the carryingamount of the asset should equal its salvage value, if any. The salvage value of the asset shall notbe reduced to an amount less than zero.

> > Long-Lived Asset Temporarily Idled

360-10-35-49 A long-lived asset that has been temporarily idled shall not be accounted for as ifabandoned.

Appendix B

Supplemental Studies on the Impact of Depreciation on Revenue Requirement

A study was conducted in support of Southern California Edison’s 2009 rebuttal in its 2009 General Rate Case to get a full understanding about different allocation methods for book depreciation and evaluate the impacted factors such as the rate base and revenue requirement.1 A theoretical model for revenue requirement was created for this study that incorporates a complete set of components generally included in revenue requirement.

That study modeled seven different depreciation methods: Straight-Line Depreciation Method Authentic Sinking Fund Depreciation Method TURN’s Modified Depreciation Method TURN’s Modified Depreciation Method using Remaining Life TURN’s Normalized Depreciation Method TURN’s Present Value Depreciation Method TURN’s Hypothetical Depreciation Method

There is no need to go into the details of these depreciation methods in this report, other than to point out that of these methods represents a different method of allocation and not a difference in what the cost being allocated was. Southern California Edison Submitted the results of the study in a full write-up as part of its rebuttal in its 2009 General Rate Case. Excerpts from the results of those depreciation method in that study are included in this document where referenced

This supplemental study was built upon the prior modeling in order to analyze the impact of different depreciation proposals in Southern California Edison’s 2012 General Rate Case. Section 1 includes a general introduction to different depreciation methods as well as the applied techniques and grouping methods. Section 2 provides a brief outline of the revenue requirement. Section 3 provides a detailed description about the theoretical model. Section 4 provides several comparisons of various scenarios with different depreciation methods and other modifications.

1.1 Depreciation Methods: Four different depreciation methods were modeled under various scenarios: Under the straight-line depreciation method:

1 Depreciation in this report will refer to book depreciation unless specified otherwise.

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Using Proper Net Salvage Rates (SL Proper Net Salvage) TURN’s Proposal Using 25% of Proper Net Salvage (TURN’s 25% of Proper) Using 60% of Proper Net Salvage Ratio (60% of Proper) Using 60% of Proper Net Salvage Ratio for 60 years, with a progression to Proper Rates (60% Progress to Proper) Using 200% of Proper Net Salvage Ratio (200% of Proper) Using 15-year Historical Average Net Salvage Ratio (15y Avg Net Salvage)

Using a cash basis method, the following scenario was analyzed:

Cash Basis throughout the life (Cash Basis)

Additionally, two methods previously proposed by TURN were modeled:

TURN’s Present Value Depreciation Method (TURN’s Present Value) TURN’s Normalized Net Salvage Allowance (TURN’s NNA)

1.1.1 Straight-Line Depreciation Method, Remaining Life Technique:

The straight-line method ratably charges the same nominal amount to each accounting period over the service life of a plant item or plant group. It directly meets the depreciation objective, which accounts for its wide acceptance in utility practice. The basic formula is:

LifeServiceCosteDepreciablAccrualonDepreciatiAnnual D

Where depreciable cost is the original or gross plant cost less estimated net salvage.2 In actual practice a depreciation rate is applied to the book cost of plant.

The following formula is used to determine the depreciation rate to be applied to the book plant basis:

LUcd Uc100

Where: d is the depreciation rate in percent of plant c is the future net salvage in percent of plant U is the accumulated depreciation in percent of plant L is the estimated remaining life3

2 Net salvage is the gross salvage value of the retired asset less any cost to retire, remove, and dispose of the asset. 3 For further discussion of the remaining life technique please see section 1.3 Application Techniques.

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This is an accurate representation of the method and technique used in the first modeling group, SL Proper NS Ratios, and serves as the benchmark all other models are measured against.

1.1.1.1 Straight Line Depreciation Using Adjusted Net Salvage Rates In the 25%, 60%, and 200% of proper net salvage ratio models, the net salvage ratio is adjusted downward or upward by a percentage.

The following formula may be used to determine the depreciation rate to be applied to the book plant basis:

Where: c is the future net salvage in percent of plant AR is the adjustment ratio used to adapt the net salvage ratio to proposals. AR can further be identified as the ratio of Proposed c:Proper c.

This formula is the same as the straight-line method remaining life technique but allows for the modeling of proposals set forth by Southern California Edison and TURN.

Deficiency of 25% of Proper Net Salvage Rates TURN’s proposal for account 364 (distribution poles) is a -90% net salvage ratio, which results in a net salvage cost of approximately $840 per distribution pole. The future per unit cost, assuming constant 2% inflation is approximately $3,500 per distribution pole ($1,870 average per pole in 2009 dollars over 31.4 years) TURN’s proposal is thereforemodeled by using a 25% adjustment ratio.

Deficiency of 60% of Proper Net Salvage Rates Southern California Edison’s proposal for account 364 is a -200% net salvage ratio which results in a net salvage cost of approximately $1,840 per distribution pole. The future per unit cost, assuming constant 2% inflation is approximately $3,500 per distribution pole ($1,870 average per pole in 2009 dollars over 31.4 years) SCE’s proposal is therefore modeled by using a 60% adjustment ratio.

Using 60% of Proper Net Salvage Ratio for 60 years, with Progression to Proper Rates Southern California Edison’s proposal for account 364 is -200% net salvage ratio which results in a net salvage cost of approximately $1,840 per distribution pole. The future per unit cost, assuming constant 2% inflation is approximately $3,500 per distribution pole ($1,870 average per pole in 2009 dollars over 31.4 years) SCE’s proposal is therefore modeled by using a 60% adjustment ratio. However, in this scenario the adjustment ratio is increased evenly every three years, for nine years similar to SCE’s rate case cycle. This scenario reflects the objective of increasing net salvage ratios over a period of time.

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Using 200% of Proper Net Salvage Ratio A 200% adjustment ratio is used to model the effect of excessively high net salvage estimates.

1.1.1.2 Straight-Line Depreciation Method with 15 Year Average Net Salvage Ratios The 15-year average uses the straight line method but calculates net salvage ratios using the 15-year average experienced (recorded) net salvage. The following formula shows the net salvage ratio in year i:

This formula models the decision in Southern California Edison’s 2006 General Rate Case to increase net salvage ratios to 15-year average net salvage ratios at that time. This scenario highlights the impacts of simply relying on an average recorded cost Net salvage is a function of cost of removal divided by original installation. Cost of removal is subject to forces of inflation and drives increases in the net salvage ratio as plant ages. For this reason, the 15 year average net salvage ratio is modeled to show the effect of using historical ratios instead of future ratios.

1.1.2 Cash Basis Method of Depreciation Under the cash-basis method of depreciation, cost of removal is collected in the period incurred. There is no explicit net salvage ratio in the cash basis method. Rather, the costs incurred to remove plant can be divided by the retired plant balance to determine the experienced net salvage ratio during the year. Each year’s depreciation rate and revenue requirement is determined by the net salvage costs incurred that year. Those costs are borne by the customers in that year.

1.1.3 TURN’s Present Value Depreciation Method An approach previously introduced by TURN is the present value method. The method is to “merely discount [an account’s] future cost of removal estimates back to [current year] values using the inflation factor that [is] used for [the account’s] ARO calculations.”4

The formula for annual net salvage rate in year r can be expressed as:

r

r

r plantcurrentL

Usalvagenetfutureofvaluespresenttotal

d

U

Where L is the remaining life U is the beginning-of-year reserve

4 A.04-12-014, Direct Testimony of Witness Michael J. Majoros, Jr.

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1.1.4 TURN’s Normalized Net Salvage Allowance Approach In the 2006 General Rate Case Mr. Majoros’ proposed the “Normalized Net Salvage Allowance”. This method states:

“the annual average net salvage, which includes cost of removal, is included as a specifically identifiable amount or rate with the annual depreciation accrual. In other words, a normalized net salvage amount is still a component of depreciation expense accrual and is credited to accumulated depreciation and actual cost of removal continues to be charged to accumulated depreciation.”5

The annual net salvage allowance “could be either a fixed amount or a rolling five year average amount.”6 In order to incorporate this amount into the depreciation rate, SCE uses the following formulas:

Lxpenditureesalvagenet

salvagenetAnnual ssr

r Lsnet s

5

5

1

Where: L is the remaining life

And the annual depreciation rate:

Luc

Lryearinplantcurrent

ULxpenditureesalvagenet

ryearinplantcurrent

d

rs

sr

r

uc

ULsnet s

100

5

5

1

Where: rU is the net salvage reserve in year r

L is the remaining life

1.2 Category Grouping Procedures The utility industry uses group depreciation, as opposed to unit depreciation. The primary difference is how the depreciation expense is recorded to accumulated depreciation and the determination of the accumulated depreciation upon retirement of the assets. Under unit depreciation procedures, accumulated depreciation would be tracked for each individual asset unit. When that unit is retired, the difference between the plant balance less net salvage and accumulated depreciation for that unit will typically be recorded as a gain or loss. 5 Id. at 42. 6 Id.

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Utility property, however, is often made up of millions of units of assets. Accounting for unit depreciation is impractical. So utilities will depreciate assets using grouping procedures. When a unit retires under a group accounting procedure, the asset is assumed to be fully depreciated, and so plant and accumulated depreciation are credited and debited, respectively, the same amount. Net salvage is charged to accumulated depreciation. The grouping procedures also keep depreciation rates relatively stable, which is typically preferred in cost of service ratemaking.

There are three primary grouping procedures, which are listed below along with the use of the procedure in the study:

1) Vintage Group (VG) 2) Equal Life Group (ELG) 3) Broad Group (BG)

A general description for each grouping method is shown here:

The Broad Group Under the broad group (BG) procedure all units of plant within a particular depreciation category, usually a plant account or subaccount, are considered to be one group. Within the broad group there will be dispersions of retirements by age, due to the many causes of retirements as well as the characteristics of the different assets in the group. The broad group procedure is the simplest procedure to use and is the least volatile. The broad group’s allocation of cost over the life of the assets, however, is the least similar to the life characteristics of underlying assets.

The Vintage Group Under the vintage group (VG) procedure, each vintage or placement year within the depreciation category is considered to be a separate group. This combines, into one group, all the assets placed in a single calendar year, or vintage. Even within each vintage group there will be dispersions of retirements by age, due to the many causes of retirements. In practice, this requires that each vintage group be analyzed separately to determine its average life. In development of a depreciation rate, typically all depreciation accrual determinations for each vintage are combined to produce a composite depreciation rate.

The Equal Life Group Under the equal life group (ELG) procedure, the plant units are grouped according to their service lives, with the units from each vintage expected to experience the same service life being included in the same life group. Thisprocedure permits accruing the full cost of the shorter-lived units to the accumulated depreciation while they are in service. This is accomplished by dividing each vintage group (plant placed in a single year) into smaller groups, each of which is limited to units that are expected to have the same life. This distribution is based on life tables developed from the recorded experience, with respect to the mortality of utility plant. While it is not possible to identify the

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individual units of plant that will have a given life, it is possible to estimate statistically the number of units or dollars of plant in each equal life group. While prediction of future retirement pattern is also necessary in application of the broad and vintage group procedures, ,the ELG procedure is much more sensitive to these predictions. ELG may be expected to produce greater fluctuations in depreciation expense from year to year than both the vintage and broad group procedure

1.3 Application Techniques There are two techniques commonly used to determine the depreciation rate to be applied to a utility’s plant depreciation categories Whole Life and Remaining Life. In this study, the remaining life is implemented, and below is a general introduction to the remaining life technique.

The remaining life technique aims to recover the undepreciated original plant cost less future net salvage over the remaining life of remaining assets. With this technique, the gross plant less book accumulated depreciation is used as the depreciable cost and the remaining life is used in the denominator. The formula is

ECUBD 'CUB

Where: D is the depreciation expense or annual accrual B is the book cost of the gross plant U is the book accumulated depreciation at the beginning of the year C’ is the estimated future net salvage in dollarsE is estimated average remaining life

The following formula is used to arrive at the depreciation rate in percent:

Depreciation rate 1001BDd

This rate may also be derived by dealing entirely in percentages as follows:

Depreciation rate 100'100 11E

cud

Where, accumulated depreciation as a percent of plant: 1001BUu

Where, net salvage as a percent of plant: BCc ''BC

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A review of the accumulated depreciation is appropriate at the commencement of use of remaining life technique to ensure consistency with prior accounting and regulatory policies. The desirability of using the remaining life technique is that any necessary adjustments of depreciation reserves, because of changes to estimates of life on net salvage, are accrued automatically over the remaining life of the property. The Commission’s STANDARD PRACTICE U-4, DETERMINATION OF STRAIGHT-LINE REMAINING LIFE DEPRECIATION ACCRUALS states:

“Application of the remaining principle consistently applied over a period of years in connection with a depreciated rate base will normally tend to produce equitable results inrate proceedings even if these points have been incorrectly determined.” [emphasis added]

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1.4 Iowa Curves It is evident that an estimate of the life of property is essential to all the seven methods of computing depreciation accruals. Many utilities rely on standardized retirement dispersion curves to analyze and predict the average service lives of utility property. Awidely used set of standardized curves are the Iowa curves, first introduced by Edwin Kurtz and Robley Winfrey in Bulletin 103. Life Characteristics of Physical Property issued in 1931. The Iowa curves were empirically developed to describe the life characteristics of most industrial and utility property.

The curves were placed into L, R, or S families depending upon whether the highest point (mode) of the retirement frequency curve was left of, right of, or symmetrical to the curve’s average life. The curves in each family were then ordered according to the magnitude of the mode from low (e.g. L0) to high (e.g. L5).

2.1 Components of the Revenue Requirement For purposes of this study, the revenue requirement (cost of service) is calculated by summing operation and maintenance expenses, depreciation expenses, tax expenses, and a return on net investment, which is the product of rate base and cost of capital.

2.2 Impact of Depreciation Expenses on a Utility’s Revenue Requirement Depreciation has a profound effect on the revenue requirement of a utility, and for many utilities, depreciation expense represents a large percentage of total operating expense. In addition, deferred income taxes, rate base, and cost of capital may be affected by the depreciation practices of a utility.

7 STANDARD PRACTICE U-4, p. 9.

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In the following subsections, the impacts of depreciation on the components of the revenue requirement are described.

2.2.1 Rate Base The effect of depreciation on rate base is detailed by accounting entries in the accumulated depreciation account. Accumulated depreciation is considered a contra-asset account, which is a reduction to rate base. As depreciation expense is recorded, an equal amount is recorded to the accumulated depreciation account each period. These amounts accumulate until the plant is retired. At that time, the accumulated depreciation is reduced by the book (original or gross) cost of the retirements and net salvage cost (consistent with group depreciation procedures addressed above). Any gross salvage received increases the accumulated depreciation account.

2.2.2 Cost of Capital The cost of capital is the cost of debt and equity required to finance the utility’s capital expenditures and working capital. The return on rate base is determined by multiplying rate base by the cost of capital rate. The cost of capital rates used in this model are 8.75% (after-tax) and 12.79% (pre-tax).

2.2.3 Deferred Income Taxes The difference between tax and book treatment of certain financial statement items is accounted for in a deferred income tax account. The largest differences for utilities often stem from differences in depreciation accruals.

Tax depreciation rates based on the Internal Revenue Code classify assets into broad groups. Tax depreciation rates are often based on factors other than the goal of matching depreciation expense with capital consumption. In the past, tax depreciation rates have been accelerated in an effort to stimulate private investment in times of economic recession. Therefore, depreciation rates for tax purposes are, generally, greater than book depreciation rates and result in depreciating the asset cost over a shorter time period. The tax effect of the difference between book and tax depreciation results in deferred income taxes.

2.2.4 Operations and Maintenance Expense Operation and Maintenance (O&M) expenses include such costs as fuel, maintenance, income taxes, and depreciation. Because depreciation is a major portion of O&M expenses, it is generally treated separately.

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Based on the background of the revenue requirement described in the preceding sections, a complete theoretical forecasting model is set up to illustrated the impacts of depreciation expenses on revenue requirement. This revenue requirement model includes the following components:

Rate base includes:

In the following subsections, the assumptions and modeling of the above parameters will be discussed in detailed.

3.1 Total Expenses

3.1.1 O&M Expenses For modeling purposes in this study O&M expense computed as a function of asset age, a certain decay rate, a certain maximum maintenance expense, and surviving asset quantities. Asset age and the decay rate are used to identify the production efficiency of the assets. Since asset age is computed as a function of the asset assumptions, only the decay rate needs to be determined. In the model, a straight-line pattern, linear-decay allocation, is adopted:

O&M = Decay Rate x Age x Max Maintenance Expense per unit x Surviving Quantity

Two assumptions are made for both the decay rate and the maximum maintenance expense: one percent decay rate and $5,000 maximum maintenance expense. With these assumptions and the R1-40 Iowa curve, the following figure shows the annual O&M Expenses over the life of a single vintage installation of 1,000 units $8,000 each.

O&M Expenses

Total Expenses Depreciation Expenses

Revenue Requirement Taxes Expense

Return on Rate Base

Fixed Capital

Rate Base Working CapitalAccumulated Depreciation

Deductions For ReservesAccumulated Deferred Taxes

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11

3.1.2 Depreciation Expenses Depreciation expense is a crucial factor in the model, and all nine scenarios introduced in Section 1.1 are analyzed and compared. In this model, depreciation accrual for both plant (installation and material)and net salvage cost(NS) will be calculated.8 Take straight-line method remaining life technique depreciation as an example

1)-(iyear in life remaining1)-(iyear in on depreciati daccumulate-1-iyear in plant iyear in plant for accrualon depreciati p

1)-(iyear in life remaining

cost NSiyear in NSfor accrualon depreciati

year ending

irrNS

year ding

ii

For all depreciation methods examined in the study, the depreciation accrual for the plant cost is determined using a straight-line method.9 The differences are only for the allocation of the net salvage cost.

A series of comparisons among all eight scenarios will be illustrated in section 4.

3.1.3 Tax Expenses The total income tax expense reported in the financial statements is based on pretax book income (income before income taxes). It’s the amount of income tax allocable to a period, whether or not currently payable or refundable. It is equal to the product of tax rate and pretax accounting income. In this model, 40% is used for the tax rate.

3.2 Return on Rate Base

3.2.1 Fixed Assets The plant balance for each year can be determined by subtracting the retired dollars during the previous year from the beginning-of-year plant balance of the previous year:

8 For purposes of the model, salvage value is assumed to be zero, so net salvage is equal to cost of removal. 9 TURN’s proposals don’t suggest changes in the depreciation of the book cost of plant, only the net salvage cost.

-

200

400

600

800

1,000

1,200

1 11 21 31 41 51 61 71Year

O&M Expense

B-11

12

)1()1( )1)1 iyearindollarsretirediyearinplantiyearinplantcurrent

In this model, the latter approach is adopted. Each year’s retirements are determined based on the retirement dispersion of the chosen Iowa curve.

3.2.2 Working Cash Working capital is decomposed into four factors for this model: working cash on depreciation, working cash on income taxes, working cash on property taxes, and working cash on O&M expenses.

expenses M&Oon cash workingandaxesproperty ton cash working taxesincomeon cash workingondepreciation cash workingcash working

awww

From this equation, it can be found that the first two components are related to functions of depreciation, and the latter two are not.10

The calculation of the working cash on different parameters depends on the average of number of days lag recognized for each parameter. To be specific for SCE’s case, the averages or number of days lag recognized are approximately 42 days for revenue requirement, 0 days for depreciation, 74 days for taxes on income, 39 days for taxes on properties, and 32 days for O&M expenses. The working cash for a given parameter can be expressed as:

req) rev of lag days ofnumber -][Parameter of lag days ofnumber (365

dollars]in [Parameter of Value (V

Working cash on depreciation has the same up and down trend with depreciation accrual. The higher the depreciation accrual, the higher the working cash on depreciation, and vice versa.

This relationship does not hold for working cash on income taxes. Income taxes can be calculated as the product of the net income and the tax rate, and hence it can be simply regarded as a proportion of the net income. In this model, an after-tax-basis cost of capital 8.75% and a pre-tax-basis cost of capital 12.79%. After applying the two rates on rate base, the after-tax-basis and pre-tax-basis return on rate base is determined. The difference between the two returns is equal to the income taxes. As a result income taxes have an indirect relationship with the depreciation accruals.

3.2.3 Accumulated Depreciation The accumulated depreciation is calculated by summing all of the depreciation accruals to the date, less plant retirements, plus net salvage:

accumulated depreciation in year (i): 10 Property tax in this model is calculated on the gross plant balance.

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13

= accumulated depreciation in year (i -1) + depreciation on accrual in year (i) – retired plant in year (i -1) + net salvage incurred in year (i-1)

3.2.4 Deferred Taxes As introduced in Section 2.2.3, deferred tax is an accounting term resulting from temporary differences between book value of assets and liabilities, computed in accordance with GAAP, and the tax value, determined using rules of the Internal Revenue Code (IRC).

A normalized tax treatment for ratemaking will accumulate deferred tax accruals as an offset to rate base until the accruals are reversed when book depreciation exceeds tax depreciation. A flow-through tax treatment for ratemaking, as the name implies, flows the tax effect to current income and not as an accumulated rate base offset. This treatment will lower cost of service in the early years of an asset’s service life and increase it towards the end of the asset’s service life. Normalized tax treatment is used in this model.

The formula to calculate the deferred taxes is:

deferred tax expense in year (i)

= tax basis tax expense in year (i) – book basis tax expense in year (i -1)

And the current year deferred tax balance is the previous year deferred tax balance plus the current year deferred tax expense.

deferred tax balance in year (i)

= deferred tax balance in year (i – 1) + deferred tax expense in year (i)

The deferred tax balance is an offset to rate base. It should be noted that the deferred taxes result from the timing differences, indicating that taxes will be payable in the future when the timing differences reverse. This characteristic of deferred taxes, as well as the offsetting impact of accumulated depreciation and deferred taxes, will have a large impact on our comparisons about rate base and revenue requirement among different depreciation methods, which will be illustrated in the following sections.

In Section 1.1, nine different depreciation scenarios are described. Except the straight-line depreciation method at proper and 200% of proper net salvage ratios, the seven other methods result in deferring depreciation accruals.

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The comparisons among different depreciation methods will be demonstrated from two perspectives and with different scenarios. The two perspectives are the single-vintage and multi-vintage perspective.

For the following discussion the following are the model inputs:Average service life is 40 years with an R 1.0 Iowa curve Consecutive installations of 1,000 units over 80 years, resulting in 80 vintages Install and removal costs in year 1 are $8,000 and $2,000 respectively The escalation rate, or inflation rate, is constant at 3.0% for all costs The pre-tax and after tax rate of return is 8.75% and 12.79% respectively All figures are in thousands of dollars

Any additional assumptions not covered in the above will be described in the individual model scenarios.

4.1 Impacts of Changing Net Salvage Accrual Prior to examining specific scenarios it is beneficial to view the general impacts of changing net salvage ratios on depreciation accruals, rate base, and revenues. To illustrate this assume three scenarios:

1) Using proper net salvage ratios 2) Using half (50%) of proper net salvage ratios 3) Using double (200%) of proper net salvage ratios

4.1.1 Theoretical Comparison of Depreciation Accruals Figure 1

Single Vintage Depreciation Accrual Under Adjusted Net Salvage Ratios

In figure 1 the accruals using proper net salvage ratios represent the equitable distribution of depreciation accruals over the life of a single vintage and is the benchmark for all other methods. Keeping in mind that total depreciation accruals over the life cycle are equal in each scenario, it is clear that using the 50% and 200% of proper net salvage ratios results

(300)

(200)

(100)

-

100

200

300

400

500

600

700

1 11 21 31 41 51 61 71

50% of ProperProper200% of Proper

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15

in the inappropriate allocation of costs. More specifically, using an excessive (200%) net salvage ratio accelerates depreciation accruals to the benefit of future customers. Alternatively, collecting only half (50%) of proper net salvage accruals marginally benefits current customers at the expense of future customers.

This effect is amplified by the aggregation of single vintages into a multiple vintage model as shown in figure 2.

Figure 2Multiple Vintage Depreciation Accrual Comparison of Adjusted Net Salvage Rates

The proper net salvage ratio remains the benchmark of the equitable distribution of depreciation accruals. Total depreciation accruals remain equal as well in the multiple vintage model.11 Over the 80 years of unit installations, depreciation accruals for the 200% group are higher than the proper and 50% of proper net salvage ratio scenarios. This increased deprecation accrual is reversed in year 103 at which point future customers benefit from the depreciation accruals paid by customers in prior years. The inverse of this relationship is true for the 50% group and customers after year 103 must pay for the benefit extended to past customers. Keep in mind however, depreciation accrual represents only one component of the revenue requirement12 and the actual benefits (or additional costs) to customers will occur at different periods when examining the total revenue requirements.

4.1.2 Theoretical Comparison of Rate Base Figure 3 shows the effect of changing net salvage ratios on rate base.

11 See Table 1 in Section 4.1.4. 12 See section 2.1. Revenue Requirement = O&M + Depreciation + Tax Expense + Return on Investment.

(60,000)

(40,000)

(20,000)

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161


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16

Figure 3Single Vintage Comparison of Impacts of Depreciation on Rate Base

Note that proper net salvage rates in the single vintage model reduces rate base below zero in year 27. In the 200% scenario, the accelerated depreciation accruals amplify this effect and negative rate base is experienced in year 18. The only scenario that maintains positive rate base for the majority of the asset life is the 50% of proper net salvage ratios. This is significant as the impacts are amplified in the multiple vintage model.

Figure 4Multiple Vintage Comparison of Impacts of Depreciation on Rate Base

In Figure 4 rate base drops below zero in years 80 and 93 for the 200% of proper and proper net salvage ratio scenarios, respectively. The aggregation of single vintages also

(6,000)

(4,000)

(2,000)

-

2,000

4,000

6,000

8,000

10,000

1 11 21 31 41 51 61 71 81


(1,500,000)

(1,000,000)

(500,000)

-

500,000

1,000,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161

50% of ProperProper200% of Theoretical

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17

results in a rate base that is never negative. The net effect is exaggerated rate base throughout the life of the account. The importance of this can be seen in an analysis of revenue requirements.

4.1.3 Theoretical Comparison of Revenue Requirement Figure 5 shows the impact of changing net salvage ratios on the revenue requirement in the single-vintage models.

Figure 5Single-Vintage Comparison of Impacts of Depreciation on Revenue Requirement

*Comments reference the 50% of proper scenario

In the theoretical model above there is an inverse relationship between the pattern of revenue requirements for the 50% and 200% of proper net salvage ratio scenarios. At 33% of the average service life (year 13) the lower revenue requirements extended to customers in the 50% of proper scenario is lost. As the inverse, the 200% or proper scenario experiences a similar effect and higher rates give way to lower than proper rates in the same period (year 13). On a cumulative cost of service basis13 all initial savings and extra costs of the 50% and 200% of proper scenarios, respectively, are eliminated after 64% of the average service life (year 25). Table 1 summarizes these changes.

Table 1 Impacts of Depreciation on Revenue Requirements as a % of Life Cycle

13 Total cost of service is equal to the sum of all period’s revenue requirements to a given year.

(400)

(200)

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

1 11 21 31 41 51 61 71 81


Cost Experience 50% 200% 50% 200%Lower Rates 16% 84% 19% 81%Lower Total Cost 31% 69% 27% 73%Higher Rates 84% 16% 81% 19%Higher Total cost 69% 31% 73% 27%

Single Vintage Multiple Vintage

Higher Rates and Total CostsHigher Rates

Lower Rates

Lower Total Costs

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18

The aggregate effect of the single vintage revenue requirement is shown in the multiple-vintage comparison in Figure 6.

Figure 6Multiple-Vintage Comparison of Impacts of Depreciation on Revenue Requirement

*Comments reference the 50% of proper scenario

Similar to the single vintage model the 50% and 200% of proper net salvage ratio scenarios have an inverse relationship. Lower revenue requirements experienced by customers of the 50% of proper scenario are lost after year 30 and total cost savings are lost after year 43. Alternatively, increased costs borne by early customers in the 200% of proper net salvage ratio scenario are reduced below proper in year 30 and total cost savings begin in year 43.14 More significant than this is the degree of cost savings and additional costs experienced by customers. The weighted average increase in revenue requirements of the 200% group over the 50% group is only 6% in the first 30 years. The total revenue requirement however is over three times higher in the 50% of proper group. Even on a present value basis the total cumulative revenue requirement higher in the 50% group. The results of this analysis can be seen in table 2 below.

Table 2Impacts of Depreciation on Rate Base and Revenue Requirement

14 See Table 1 on the previous page.

(150,000)

(100,000)

(50,000)

-

50,000

100,000

150,000

200,000

250,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161


Percent of Depr. Rev NPV Depr. Rev NPVTheoretical Accrual Req Rev Req Accrual Req Rev Req

50% 15,532 77,539 35,658 4,990,835 13,733,486 1,952,198100% 15,532 67,866 33,641 4,990,835 10,242,258 1,781,968200% 15,532 48,514 29,606 4,990,835 3,259,784 1,441,512


Lower Rates

Higher Rates and Total CostsHigher Rates

Lower Total Costs

B-18

19

Despite initial costs savings and equal depreciation accrual the total revenue requirement is $3.5 billion higher when proper net salvage ratios are reduced by 50%. This model makes use of the assumptions described in section 3 for O&M and working cash expenses in determining revenue requirement. However even if these values are ignored the resulting pattern of higher revenue requirement is still experienced as illustrated in figure 7.

Figure 7Multi-Vintage Impacts of Depreciation on Revenue Requirement no O&M or WC

Table 3Impacts of Depreciation on Rate Base and Revenue Requirement

Without O&M or Working Cash Components

With an understanding of depreciation accrual’s impact on rate base and the revenue requirement a comparison of TURN’s and Southern California Edison’s proposals can be examined

4.2 Comparison of Depreciation Methods In the 2012 General Rate Case TURN and Southern California Edison have submitted different net salvage ratios for account 364. To understand the implications and effects of these proposals, four groups of scenarios are examined.

TURN’s Proposals The 15 year average net salvage ratio Southern California Edison’s Proposal

(150,000)

(100,000)

(50,000)

-

50,000

100,000

150,000

200,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161


Percent of Depr. Rev NPV Depr. Rev NPVTheoretical Accrual Req Rev Req Accrual Req Rev Req

50% 15,532 29,462 17,458 4,990,835 9,844,894 1,383,037100% 15,532 19,747 15,408 4,990,835 6,341,377 1,210,299200% 15,532 338 11,316 4,990,835 (665,676) 864,825


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Excessive net salvage ratios

4.2.1 TURN’s Proposals and the Cash-Basis Method of Depreciation As described in section 1.1.2 a cash basis method of allocating net salvage costs to customers allocates net salvage costs incurred from plant retirements in the period the plant is retired. The allocated net salvage cost will rise and fall with the frequency of plant retirements and the per unit cost of removal This explains the net salvage accrual curve in figure 8.

Figure 8Multiple-Vintage Net Salvage Accrual: Cash Basis and Proper Net Salvage Methods

At the beginning of the group’s life, the retirement frequency is low and inflation has very little effect on the per unit cost of net salvage. As plant ages and retirements and costs increase future customers face increasing expenses associated with retiring plant that has provided service to customers in previous periods. This is undesirable as it fails to match the loss in service value (expense) to the period (and customers) that benefit from that service values.

Under cash basis accounting net salvage costs are deferred to the end of the plant’s service life. It would be logical to assume that using the cash-basis method results in the maximum deferral of net salvage accrual possible. As shown in Figure 9 however, this is not the case.

-

10,000

20,000

30,000

40,000

50,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

SL Proper NS Ratios

Cash Basis

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Figure 9Multiple-Vintage Net Salvage Accrual: Cash Basis and TURN’s 25% of Proper

When insufficient net salvage ratios are used to determine the depreciation accruals, net salvage incurred may be greater than net salvage allowed. This deficiency is taken to accumulated depreciation and reallocated over the assets remaining life. This continues until net salvage accruals reach proper levels accruals match the loss in service value and the accumulated deficiency is allocated over the remaining life of the group. In Figure 9 the net salvage accrual between year 55 and 122 is lower than the net salvage incurred—the difference is an annual deficit that accumulates. The accumulated deficiency is allocated to customers in periods after year 122.

TURN has made similar proposals in the past. In particular, the methods described in Section 1 result in similar deferrals of net salvage costs and fail to match costs to the benefits received from the asset. Figure 10 shows the results of TURN’s depreciation recommendations on net salvage accruals.

Figure 10Multi-Vintage Comparison of Net Salvage Accruals Under TURN Proposals

-

10,000

20,000

30,000

40,000

50,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

SL Proper NS RatiosTURN's 25% of ProperCash Basis

Accrual < Cash Basis

- 5,000

10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

SL Proper NS Ratios

TURN's Present Value

TURN's Normalized Net Salvage

TURN's 25% of Proper

B-21

22

Keeping in mind the relationship between TURN’s 25% of proper net salvage ratios and the cash basis method it is apparent that TURN’s normalized net salvage allowance approach has similar results to the cash-basis method of depreciation. TURN’s Present Value Method also results in similar deferrals although slightly less so than the methods previously discussed.

Figure 11 shows the impacts of net salvage deferral on the revenue requirement.

Figure 11Multi-Vintage: Impacts of TURN’s Proposals on Revenue Requirement

Table 3Average Annual Revenue Requirement Impact of TURN Proposals

*All comparisons are to proper net salvage ratios

Table 3 and Figure 11 show initial cost savings of approximately 3% are overshadowed by the substantial cost increases of 25.5%, 30.4%, and 28.6% from TURN’s 25% of proper, TURN’s Normalized Net Salvage Allowance Approach and TURN’s Present Value methods respectively. Table 3 also highlights that the cost discrepancies are not theresult of timing differences as the net present value method produces significant increases in revenue requirements as well.

(10,000)

40,000

90,000

140,000

190,000

240,000

290,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

SL Proper NS Ratios

TURN's 25% of Proper

TURN's Present Value

TURN's Normalized NSLower Rates

Higher Rates

Method Savings Prior to Year 32 Increase After Year 31TURN's 25% of Proper 2.71% 25.5%TURN's Normalized Net Salvage 3.13% 30.4%TURN's Present Value 3.05% 28.6%Cash Basis 2.18% 23.2%

B-22

23

4.2.2 15-Year Average Net Salvage Method In SCE’s 2006 General rate Case the Commission adopted DRA’s proposal based on using 15-year historical average net salvage ratios to determine the rate to be applied to future plant. As Figure 12 shows, modeling the results of this decision prove this to be an ineffective method of allocating net salvage.

Figure 12Multi-Vintage Comparison of 15 Year Average to Proper Net Salvage Accrual

The deferral of costs in this case is a function of the forces of depreciation, namely inflation’s impact on net salvage. This is due to the fact that retirements in the beginning of the asset group’s life are subject to less inflation, and thus, will have a lower net salvage ratio. So, using the past average results in deficient net salvage accruals. In an environment with constant cost escalation for all costs, future net salvage cost ratios will always be more negative than recorded net salvage ratios. In application to utility property, calculating a 15-year average on historical experience alone and not considering future costs will result in deficient accruals.

While use of the 15-year average in determining net salvage accrual over the lifetime of the asset results in less deferral of costs than TURN’s current proposal of 25% of proper net salvage ratios it fails to match net salvage costs to customers benefiting from the asset’s service. Compared to using proper net salvage ratios, the 15-year average results in a cumulative revenue requirement that is 28% (9.2% on a net present value basis) higher.

4.2.3 Southern California Edison’s Proposals Southern California Edison has proposed a net salvage ratio of -200% for account 364, approximately 60% of the net salvage ratio of -310% supported by analysis. The 10% increase of current net salvage ratios (190% to 200%) is in line with the goal of increasing net salvage ratios to proper levels in the future. Figure 13 models the effects of

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

SL Proper NS Ratios

SL 15 Year Avg NS Ratios

B-23

24

adopting Southern California Edison’s net salvage ratio and: (1) maintaining the proposal over the life of the asset, and; (2) increasing the net salvage to proper levels over the three year general rate case cycles.

Figure 13Multi-Vintage Net Salvage Cost Accrual SCE Proposal and Goals

Southern California Edison’s current proposal rates result in slightly less deferral than the 15 year average and substantially less than TURN’s proposals and the cash basis method.15 However, were Southern California Edison’s rates increased gradually starting in year four(2% every three years per the GRC cycle) the deferral could be mitigated and the net salvage accruals better matched to customers who receive the service value of the underlying assets. Using this gradual approach, however, proper rates would not be achieved until almost 60 years later, or approximately 20 GRCs. This is shown in Figure 13 in the 60% of proper with gradual increase curve.

Were these increases deferred however, it would require larger increases to allocate costs appropriately. If these increases were not accepted and a gradual increase was prescribed, net salvage accruals would be deferred.. Figure 14 shows the impacts of deferral of net salvage ratios on the net salvage accrual and revenue requirement.

15 See table 4.

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

Proper

60% of Proper

60% of Proper 2%Progress to Proper

B-24

25

Figure 14Multi-Vintage: Net Salvage Accruals and Revenue Requirements

Net Salvage Accruals

Revenue Requirement

Figure 14 illustrates two scenarios: (1) maintaining net salvage ratios at 60% of proper for 60 years followed by 10% increases every three years (per the GRC cycle) until increased to proper; and (2) maintaining net salvage ratios at 60% of proper for 60 years followed by 2% increases every 3 years.16

The additional revenue requirement for customers is apparent. Efforts to bring net salvage ratios up to proper after a prolonged deferral results in higher revenue requirements that are difficult to remedy without larger increases in the net salvage ratios.

16 10% and 2% increases are added to the net salvage ratio , that is the initial10% increase will result in anet salvage ratio of 70% (60% + 10%) of proper and the initial 2% increase will result in a net salvage ratio of 62% (60% + 2%) of proper.

-

10,000

20,000

30,000

40,000

50,000

(50,000)

-

50,000

100,000

150,000

200,000

250,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

SL Proper NS Ratios

60% of Proper with 10%Increase after 60 Years

60% of Proper 2% Increaseafter 60 years

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26

The recommendations and objectives proposed by Southern California Edison closely match the results of the theoretical model and more closely matches costs to customers in the period of plant service.

4.2.4 High Net Salvage Ratios Figure 15 represent the changes in net salvage accruals and the impact on revenue requirements if the net salvage cost ratio was double the proper ratio.

Figure 15Multi-Vintage: High Net Salvage Accruals and Revenue Requirements

Net Salvage Accruals

Revenue Requirement

As shown above the over allocation of net salvage cost in early periods results in current customers overpaying for net salvage costs. As described in the theoretical discussion in section 4.1, however, any over accrual creates an offset to plant in service, reduces rate base and, ultimately, reduces the revenue requirement. Despite that, in this scenario net salvage accruals do not drop below accruals using proper ratios until year 103, the

(45,000)

(25,000)

(5,000)

15,000

35,000

55,000

75,000

95,000SL Proper NS Ratios

SL 200% of Proper

(150,000)

(100,000)

(50,000)

-

50,000

100,000

150,000

200,000

250,000

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161Year

B-26

27

customer benefits as a result of reduced rate base beginning in year 31. This is consistent with the theoretical model described in section 4.1 and as Table 4 highlights, the revenue requirement reductions are greater in scenarios with higher net salvage ratios and accruals.

Table 4Total Revenue Requirement Comparison (000’s)

*Sorted by multi-vintage revenue requirement

As shown in the table 4. TURN’s deferral methods of depreciation consistently result in greater cost to customers as a result of higher revenue requirements. In fact none of Southern California Edison proposals exceed TURN’s in total cost to customers. TURN’s methods fail to equitably charge customers and result in a greater cumulative cost of service.

This study investigates the impacts of changing net salvage ratios on the revenue requirement. Eight different depreciation methods are modeled

Straight-line depreciation method using proper net salvage ratios Six deferral depreciation methods, and One accelerated depreciation method.

All of the deferral deprecation methods proposed by TURN and DRA fail to serve the purpose of matching costs to customers and reducing the revenue requirement. From the perspective of the single-vintage group, although the deferral depreciation methods have lower depreciation expenses when compared to using proper net salvage ratios in the first several years, the relatively lower revenue requirements are experienced for a shortperiod followed by higher revenue requirements over the remaining life cycle of the assets. The situation is exacerbated when examining the impacts from a multi-vintage perspective.

Revenue NPV of Revenue NPV ofCategory Requirement Rev Req Requirement* Rev Req

TURN's 25% of Proper 82,359 36,666 15,478,519 2,037,307TURN's NNA 82,973 37,021 14,982,747 2,043,467Cash Basis 82,523 36,921 14,847,834 2,033,890TURN's Present Value 77,199 35,864 13,637,561 1,969,59615 Year Average NS 78,992 36,161 13,047,074 1,946,59060% of Proper 75,598 35,255 13,034,935 1,918,149Increasing by 2% from 60% of ProperIncreasing by 10% from 60% of ProperProper NS Ratios 67,866 33,641 10,242,258 1,781,968200% of Proper 48,535 29,608 3,260,573 1,441,519

77,239 35,485 11,861,423 1,889,780


11,013,09975,365 35,237 1,857,564

B-27

28

It can be concluded that the motivation of trying to reduce customers’ charge from using the deferral methods fails to serve its purpose over the life cycle of a group of assets. In addition, the straight-line method using proper net salvage ratios ensures that each generation of customers incurs an equitable share of the costs over the life of the property.

B-28

Appendix C

Supporting Calculations

Accoun

tDe

scrip

tion

YE20

12Plan

tAu

thorized

Prop

osed

Varia

nce

Plan

tWeightedIncrease

352Structures

andIm

provem

ents

376,68

0,05

330

%35

%5%

(18,83

4,00

3)353StationEq

uipm

ent

3,98

1,95

7,65

55%

15%

10%

(398

,195

,766

)35

4To

wersa

ndFixtures

772,20

3,66

670

%10

0%30

%(231

,661

,100

)35

5Po

lesa

ndFixtures

603,69

2,25

470

%85

%15

%(90,55

3,83

8)35

6OverheadCo

nductors&De

vices

706,02

0,71

180

%10

0%20

%(141

,204

,142

)35

7Und

ergrou

ndCo

nduit

48,517

,033

0%0%

0%35

8Und

ergrou

ndCo

nductors&De

vices

208,16

7,36

720

%15

%5%

10,408

,368

359Ro

adsa

ndTrails

43,038

,583

0%0%

0%36

1Structures

andIm

provem

ents

436,83

0,74

925

%25

%0%

362StationEq

uipm

ent

1,76

1,03

7,88

320

%30

%10

%(176

,103

,788

)36

4Po

les,To

wersa

ndFixtures

1,65

5,02

7,11

819

0%22

5%35

%(579

,259

,491

)36

5OverheadCo

nductors&De

vices

1,19

5,65

3,26

211

0%12

5%15

%(179

,347

,989

)36

6Und

ergrou

ndCo

nduit

1,38

9,56

3,20

020

%40

%20

%(277

,912

,640

)36

7Und

ergrou

ndCo

nductors&De

vices

4,40

2,04

3,70

660

%80

%20

%(880

,408

,741

)368Line

Transformers

3,02

2,09

5,50

70%

20%

20%

(604

,419

,101

)36

9Services

1,17

2,06

2,08

785

%12

5%40

%(468

,824

,835

)37

0Meters

888,75

9,13

25%

5%0%

373Street

Lightin

g&SignalSystem

s75

3,72

0,53

820

%40

%20

%(150

,744

,108

)

Total

23,417

,070

,503

(4,187

,061

,174

)17

.88%

Net

SalvageRa

tio

Sout

hern

Cal

iforn

ia E

diso

nSu

mm

ary

of N

et S

alva

ge R

ate

Incr

ease

sFo

r Yea

r End

201

2

C-1

Plan

t and

Net

Sal

vage

Cos

t of R

emov

alPl

ant +

Gro

ss S

alva

geA

ccou

ntC

AD

Rec

orde

dVa

rianc

eA

ccou

ntC

AD

Rec

orde

dVa

rianc

eA

ccou

ntC

AD

Rec

orde

dVa

rianc

e

352

109,

871,

678

90,8

28,8

51

(19,

042,

827)

35

232

,076

,662

27

,931

,061

(4

,145

,601

)

352

77,7

95,0

16

62,8

97,7

90

(14,

897,

226)

353

927,

068,

948

514,

217,

874

(412

,851

,073

)

35

317

1,71

1,18

1

41

0,00

7

(1

71,3

01,1

74)

353

755,

357,

767

513,

807,

867

(241

,549

,900

)

354

439,

624,

380

421,

305,

615

(18,

318,

766)

35

426

0,59

4,07

0

18

1,51

7,32

8

(7

9,07

6,74

2)

354

179,

030,

310

239,

788,

286

60,7

57,9

76

355

231,

634,

005

174,

800,

929

(56,

833,

076)

35

513

8,22

8,91

2

84

,945

,925

(5

3,28

2,98

7)

355

93,4

05,0

93

89,8

55,0

04

(3,5

50,0

89)

356

558,

758,

662

537,

696,

385

(21,

062,

277)

35

640

7,03

2,79

0

33

3,08

8,62

8

(7

3,94

4,16

3)

356

151,

725,

872

204,

607,

758

52,8

81,8

86

357

13,4

66,9

55

15,2

74,8

40

1,80

7,88

5

35

7(1

12,0

30)

(7,2

84)

10

4,74

6

357

13,5

78,9

85

15,2

82,1

23

1,70

3,13

8

358

63,6

69,6

78

78,2

44,9

52

14,5

75,2

74

358

19,5

90,6

14

26,3

54,0

53

6,76

3,43

9

35

844

,079

,064

51

,890

,899

7,

811,

835

359

10,5

13,5

73

13,9

80,8

65

3,46

7,29

2

35

9(6

38,7

99)

(6,4

15)

63

2,38

4

359

11,1

52,3

73

13,9

87,2

81

2,83

4,90

8

361

168,

379,

674

159,

481,

896

(8,8

97,7

77)

36

132

,987

,073

18

,526

,076

(1

4,46

0,99

7)

361

135,

392,

601

140,

955,

820

5,56

3,21

9

362

542,

134,

026

281,

581,

641

(260

,552

,386

)

36

217

4,75

3,07

1

28

,046

,119

(1

46,7

06,9

52)

362

367,

380,

955

253,

535,

521

(113

,845

,434

)

364

881,

814,

800

623,

811,

488

(258

,003

,313

)

36

467

1,30

0,34

9

37

7,20

4,48

4

(2

94,0

95,8

66)

364

210,

514,

451

246,

607,

004

36,0

92,5

53

365

561,

845,

277

520,

102,

755

(41,

742,

522)

36

534

1,42

9,57

7

32

4,33

0,78

2

(1

7,09

8,79

4)

365

220,

415,

700

195,

771,

972

(24,

643,

728)

366

459,

830,

355

424,

307,

681

(35,

522,

674)

36

613

9,04

1,95

1

79

,912

,765

(5

9,12

9,18

6)

366

320,

788,

404

344,

394,

916

23,6

06,5

12

367

1,38

5,63

5,87

0

2,03

0,29

3,63

4

644,

657,

764

367

647,

109,

860

775,

175,

958

128,

066,

097

367

738,

526,

010

1,25

5,11

7,67

7

516,

591,

667

368

936,

539,

885

684,

576,

066

(251

,963

,818

)

36

828

6,74

6,91

8

(1

2,93

6,27

5)

(2

99,6

83,1

93)

368

649,

792,

967

697,

512,

342

47,7

19,3

75

369

812,

506,

450

683,

575,

166

(128

,931

,285

)

36

950

2,36

3,19

9

32

1,05

1,63

7

(1

81,3

11,5

62)

369

310,

143,

251

362,

523,

529

52,3

80,2

78

370

82,1

21,4

53

73,3

10,3

62

(8,8

11,0

91)

37

03,

921,

055

(1

6,24

9,29

1)

(2

0,17

0,34

6)

370

78,2

00,3

98

89,5

59,6

53

11,3

59,2

55

373

251,

217,

041

267,

633,

255

16,4

16,2

14

373

161,

444,

673

140,

350,

143

(21,

094,

530)

37

389

,772

,369

12

7,28

3,11

3

37

,510

,744

TOTA

L8,

436,

632,

711

7,

595,

024,

257

(8

41,6

08,4

55)

TOTA

L3,

989,

581,

125

2,

689,

645,

701

(1

,299

,935

,424

)

TOTA

L4,

447,

051,

586

4,

905,

378,

556

45

8,32

6,96

9

Sout

hern

Cal

iforn

ia E

diso

nSu

mm

ary

of C

alcu

late

d A

ccum

ulat

ed D

epre

ciat

ion

(CA

D)

For Y

ear E

nd 2

012

C-2

Accoun

tDe

scrip

tion

YE20

12Plan

tAu

thorized

SCE

ORA

TURN

Authorized

SCE

ORA

TURN

352Structures

andIm

provem

ents

376,68

02.39

%2.53

%2.42

%2.53

%8,98

49,53

79,10

79,53

7353StationEquipm

ent

3,98

1,95

82.82

%3.04

%2.89

%2.40

%11

2,30

012

1,11

911

5,18

795

,682

354To

wersa

ndFixtures

772,20

42.51

%3.17

%2.51

%1.79

%19

,412

24,456

19,412

13,802

355Po

lesa

ndFixtures

603,69

23.48

%4.38

%4.01

%3.66

%20

,999

26,418

24,217

22,082

356OverheadCo

nductors&De

vices

706,02

13.67

%3.67

%3.08

%1.83

%25

,909

25,894

21,712

12,900

357Und

ergrou

ndCo

nduit

48,517

1.73

%1.73

%1.73

%1.73

%83

983

983

983

935

8Und

ergrou

ndCo

nductors&De

vices

208,16

72.82

%2.65

%2.65

%2.65

%5,86

85,51

25,51

25,51

235

9Ro

adsa

ndTrails

43,039

1.52

%1.52

%1.52

%1.52

%65

465

465

465

436

1Structures

andIm

provem

ents

436,83

13.23

%3.04

%3.04

%3.04

%14

,102

13,289

13,289

13,289

362StationEquipm

ent

1,76

1,03

82.99

%3.28

%2.52

%2.46

%52

,672

57,736

44,326

43,293

364Po

les,To

wersa

ndFixtures

1,65

5,02

77.04

%7.81

%6.51

%5.02

%11

6,44

412

9,29

610

7,77

983

,119

365OverheadCo

nductors&De

vices

1,19

5,65

34.73

%5.15

%4.73

%4.02

%56

,542

61,636

56,542

48,052

366Und

ergrou

ndCo

nduit

1,38

9,56

32.19

%2.45

%2.05

%2.00

%30

,461

34,015

28,421

27,800

367Und

ergrou

ndCo

nductors&De

vices

4,40

2,04

43.52

%3.90

%2.70

%3.03

%15

5,01

417

1,80

611

8,76

713

3,30

7368Line

Transformers

3,02

2,09

63.63

%3.93

%2.78

%3.93

%10

9,56

711

8,75

884

,068

118,75

836

9Services

1,17

2,06

24.68

%5.76

%3.29

%4.37

%54

,863

67,467

38,594

51,276

370Meters

888,75

95.30

%5.30

%5.30

%5.30

%47

,142

47,142

47,142

47,142

373Street

Lightin

g&SignalSystem

s75

3,72

12.77

%3.43

%2.68

%3.43

%20

,910

25,860

20,163

25,860

23,417

,071

852,68

294

1,43

475

5,73

375

2,90

4

Compo

site

Rate

3.64

%4.02

%3.23

%3.22

%

%Ch

ange

from

Authorized

10.4%

11.4%

11.7%

Depreciatio

nRa

teAc

crua

l

Sout

hern

Cal

iforn

ia E

diso

nC

ompo

site

Rat

e C

alcu

latio

nsFo

r Yea

r End

201

2

C-3

Appendix D

Data Requests

Southern California Edison2015 GRC A.13-11-XXX

DATA REQUEST SET DRA-001-MK3

To: DRAPrepared by: Rick Fisher

Title: ManagerDated: 09/25/2013

Received Date: 09/25/2013

Question 01:

Originator: Matthew Karle

Exhibit Reference: SCE-10, Volumes 2 and 3

Subject: Depreciation

Please provide the following:

1. In D.12-11-051, the Commission ordered SCE to “provide testimony in its next GRC to provide more information about COR in asset accounts where SCE’s proposed NSR is at least 25% more than comparable industry averages.” Please identify all asset accounts where proposed NSR is at least 25% more than comparable industry averages.

Response to Question 01:

For a general discussion of the factors contributing to higher net salvage rates, please refer to page 87 of Exhibit SCE-10, Volume 3. SCE provided information regarding COR in each and every account. SCE does not possess nor is it aware of any industry statistics that provide recorded net salvage ratios so that SCE might be able to pinpoint the specific accounts where SCE's proposed net salvage ratio is at least 25% more than comparable industry averages. Thus, based on the information currently in SCE's possession, SCE cannot draw the comparison. SCE is in the process of trying to generate industry statistics so that we may be able to draw the comparison between SCE's net salvage ratio and comparable industry averages. SCE expects to complete that process by end of November 2013 and will supplement this data request response with the outcome or status of our efforts at that time.

SCE is available at ORA's convenience if ORA wishes to discuss in greater detail.

D-1

Southern California Edison2015 GRC A.13-11-003

DATA REQUEST SET DRA-001-MK3

To: DRAPrepared by: David Gunn

Title: Financial AnalystDated: 09/25/2013


Question 01 Supplemental :

Originator: Matthew Karle

Exhibit Reference: SCE-10, Volumes 2 and 3

Subject: Depreciation

Please provide the following:

1. In D.12-11-051, the Commission ordered SCE to “provide testimony in its next GRC to provide more information about COR in asset accounts where SCE’s proposed NSR is at least 25% more than comparable industry averages.” Please identify all asset accounts where proposed NSR is at least 25% more than comparable industry averages.

Response to Question 01 Supplemental :

As discussed in the original response to question one of DRA-001-MK3 a study of the industry statistics for realized net salvage pertaining to T&D assets was undertaken by SCE’s depreciation consultant Dane Watson at Alliance Consulting. The results show that out of the 18 transmission and distribution non-land accounts, only 4 were greater than the industry average by 25% or more. Of the remaining 14 accounts 13 had higher average net salvage rates than those proposed by SCE. The last account had a lower average net salvage rate than SCE’s proposal but by less than 25% of SCE’s proposed rate.

The accounts in which SCE’s proposals were 25% more than comparable industry averages are summarized below:

D-2

SCE provided information regarding net salvage for each of the above accounts in its testimony (see Exhibit SCE-10, Volume 3). The attachment to this data request is proprietary information provided by Alliance Consulting in response to DRA-001-MK3 Question 1.

D-3

Account Company 3 yr Avg 5 yr Avg

352/361 Oncor 116.8% 84.3%352 Duke Energy Carolinas 116.0% 54.0%352 Oncor 80.9% 52.3%352 Idaho Power Company 68.0% 31.0%352 Public Service of Colorado 61.7% 50.8%352 Kansas City Power and Light 46.0% 28.8%352 Pacificorp 36.0% 51.0%352 American Transmission Company 24.8% 26.0%352 SPS Texas/ SPS NM 20.9% 13.3%352 Northern States Power Wisconsin 16.3% 15.9%352 Entergy Arkansas 16.0% 0.0%352 Progress Energy Carolina 13.6% 18.7%

352 Production Northern States Power Wisconsin 11.6% 11.6%352 Louisville Gas and Electric 5.0% 4.0%352 Northern States Power MN 1.2% 15.3%352 CenterPoint Electric 0.0% 0.0%352 El Paso Electric Company 0.0% 0.0%352 Entergy Texas 40.4% 25.1%352 Gulf Energy 1.7%352 Alaska Electric Power and Light NA NA352 Cleco NA NA352 Minnesota Power (Allete) NA NA352 Municipal Power and Light, City of Anchorage NA 0.0%352 Sharyland NA NA

352.01 Pacific Gas and Electric 382.0% 415.0%352.01 American Transmission Company 0.0% 0.0%

Southern California EdisonNet Salvage Survey Collected Data

Account 352

D-4



353 Texas NewMexico Power 144.8% 134.5%353 Duke Energy Carolinas 63.0% 54.0%353 Northern States Power MN 32.8% 24.2%353 Public Service of Colorado 32.6% 30.1%353 Northern States Power Wisconsin 24.6% 26.1%353 Louisville Gas and Electric 24.0% 14.0%353 Entergy Texas 18.4% 14.4%353 Alaska Electric Power and Light 16.9% 16.9%353 Minnesota Power (Allete) 15.4% 13.1%353 Idaho Power Company 15.0% 9.0%353 PSI Energy 14.0% 11.0%353 Oncor 13.2% 15.5%353 Pacificorp 13.0% 14.0%353 Progress Energy Carolina 9.9% 13.4%353 Kansas City Power and Light 6.4% 10.4%353 Municipal Power and Light, City of Anchorage 5.2% 4.2%353 Entergy Arkansas 3.0% 5.0%353 CenterPoint Electric 2.6% 3.2%353 El Paso Electric Company 1.0% 1.0%

353 Comm Kansas City Power and Light 0.8% 0.8%353 Production Northern States Power Wisconsin 0.0% 19.8%

353 Sharyland 8.4% 112.6%353 Cleco 16.2% 8.8%353 Gulf Energy 10.5%353 Otter Tail Power Company 5.0%

353.01 Pacific Gas and Electric 114.0% 83.0%353.01 American Transmission Company 16.1% 21.0%353.02 American Transmission Company 25.1% 26.1%353.02 Pacific Gas and Electric 0.0% 3.0%353.03 American Transmission Company 23.5% 28.2%353.1 Public Service of Colorado 136.8% NA353.1 Minnesota Power (Allete) NA NA353.2 PSI Energy NA 5.0%

Account 353

D-5



354 Northern States Power Wisconsin 6432.3% 6466.6%354 Pacific Gas and Electric 289.0% 323.0%354 PSI Energy 157.0% 11.0%354 Entergy Arkansas 153.0% 116.0%354 Public Service of Colorado 144.9% 109.9%354 Northern States Power MN 130.5% 72.1%354 Louisville Gas and Electric 59.0% 59.0%354 Pacificorp 52.0% 35.0%354 Duke Energy Carolinas 46.0% 62.0%354 Idaho Power Company 34.0% 19.0%354 Entergy Texas 33.8% 136.3%354 Oncor 33.4% 39.9%354 Alaska Electric Power and Light 31.2% 31.2%354 Progress Energy Carolina 22.0% 19.2%354 American Transmission Company 18.2% 71.8%354 CenterPoint Electric 6.8% 10.9%354 Minnesota Power (Allete) 2.0% 2.0%354 Kansas City Power and Light 0.0% 0.0%354 Gulf Energy 33.9%354 Otter Tail Power Company 10.0%354 Cleco NA NA354 Sharyland NA NA354 Texas NewMexico Power NA NA354 (blank) NA NA354.1 Municipal Power and Light, City of Anchorage NA NA

Account 354

D-6



355 Sharyland 614.7% 54.3%355 (blank) 484.5% 483.4%355 Northern States Power Wisconsin 217.5% 92.2%355 Kansas City Power and Light 212.1% 212.7%355 Public Service of Colorado 210.9% 31.6%355 Oncor 162.6% 228.9%355 Texas NewMexico Power 147.2% 110.2%355 Louisville Gas and Electric 138.0% 168.0%355 Entergy Texas 136.6% 69.0%355 Northern States Power MN 88.4% 101.9%355 Pacificorp 67.0% 39.0%355 Entergy Arkansas 60.0% 49.0%355 Idaho Power Company 57.0% 53.0%355 PSI Energy 55.0% 61.0%355 Pacific Gas and Electric 49.0% 62.0%355 Alaska Electric Power and Light 32.8% 47.5%355 CenterPoint Electric 32.3% 34.8%355 Cleco 32.1% 66.9%355 Minnesota Power (Allete) 15.8% 38.7%355 Municipal Power and Light, City of Anchorage 12.1% 11.2%355 Duke Energy Carolinas 7.0% 24.0%355 Progress Energy Carolina 3.7% 13.4%355 El Paso Electric Company 1.0% 3.0%355 Gulf Energy 149.1%355 Otter Tail Power Company 50.0%

355.01 American Transmission Company 117.3% 76.4%355.02 American Transmission Company 188.1% 135.5%355.1 Municipal Power and Light, City of Anchorage NA 0.0%

Account 355

D-7



356 American Transmission Company 296.4% 143.8%356 Texas NewMexico Power 232.2% 249.7%356 Kansas City Power and Light 191.6% 157.3%356 CenterPoint Electric 151.3% 168.5%356 Pacific Gas and Electric 91.0% 100.0%356 Oncor 90.4% 154.5%356 Entergy Arkansas 89.0% 82.0%356 PSI Energy 89.0% 40.0%356 Louisville Gas and Electric 83.0% 66.0%356 Duke Energy Carolinas 78.0% 82.0%356 Northern States Power Wisconsin 70.0% 35.9%356 Entergy Texas 61.7% 33.9%356 Pacificorp 50.0% 28.0%356 (blank) 48.2% 61.1%356 Idaho Power Company 48.0% 42.0%356 Progress Energy Carolina 38.9% 37.0%356 Northern States Power MN 12.9% 27.2%356 Municipal Power and Light, City of Anchorage 9.5% 7.4%356 Public Service of Colorado 7.8% 2.1%356 El Paso Electric Company 0.0% 0.0%356 Cleco 1.1% 24.0%356 Minnesota Power (Allete) 12.2% 9.9%356 Gulf Energy 24.7%356 Otter Tail Power Company 30.0%356 Alaska Electric Power and Light NA 31.7%356 Sharyland NA 57.3%

356.01 American Transmission Company 24.9% 22.2%356.02 American Transmission Company NA 0.0%356.03 American Transmission Company NA NA356.1 Municipal Power and Light, City of Anchorage 0.0% 0.0%356.1 Minnesota Power (Allete) NA NA

Account 356

D-8



357 Oncor 28.8% 28.8%357 Northern States Power MN 0.0% 0.0%357 Pacific Gas and Electric 0.0% 0.0%357 Pacificorp 0.0% 0.0%357 American Transmission Company NA 33.5%357 CenterPoint Electric NA NA357 Kansas City Power and Light NA NA357 Municipal Power and Light, City of Anchorage NA NA357 Northern States Power Wisconsin NA NA357 Progress Energy Carolina NA NA357 Public Service of Colorado NA NA357 (blank) NA NA

358 Louisville Gas and Electric 61.0% 8.0%358 Oncor 48.0% 48.0%358 Pacific Gas and Electric 38.0% 54.0%358 Northern States Power Wisconsin 37.7% 37.7%358 American Transmission Company 23.8% 26.2%358 Northern States Power MN 14.9% 12.3%358 Pacificorp 0.0% 0.0%358 Otter Tail Power Company 5.0%358 Alaska Electric Power and Light NA 32.1%358 CenterPoint Electric NA NA358 Cleco NA NA358 Kansas City Power and Light NA NA358 Municipal Power and Light, City of Anchorage NA NA358 Progress Energy Carolina NA NA358 Public Service of Colorado NA 37.9%358 (blank) NA NA

Account 357

Account 358

D-9



359 Pacific Gas and Electric 180.0% 164.0%359 CenterPoint Electric 50.1% 64.7%359 Pacificorp 0.0% 0.0%359 American Transmission Company NA NA359 Cleco NA NA359 Minnesota Power (Allete) NA NA359 Northern States Power Wisconsin NA NA359 Progress Energy Carolina NA 0.0%359 Public Service of Colorado NA NA359.1 Municipal Power and Light, City of Anchorage NA NA

Account 359

D-10



361 Potomac Electric Power Company 585.0% 134.0%361 San Diego Gas and Electric 466.3% 384.2%361 PSI Energy 234.0% 307.0%361 Oncor 194.5% 165.5%361 Northern States Power MN 112.1% 109.9%361 Kansas City Power and Light 103.9% 70.7%361 Northern States Power Wisconsin 88.4% 42.3%361 Potomac Electric Power Company 75.4% NA361 Louisville Gas and Electric 55.0% 1.0%361 Texas NewMexico Power 39.6% 18.2%361 Idaho Power Company 39.0% 25.0%361 Minnesota Power (Allete) 36.5% 35.5%361 Consumers Energy 28.4% 65.5%361 Progress Energy Carolina 19.8% 50.5%361 Duke Energy Carolinas 18.0% 12.0%361 Public Service of Colorado 17.5% 19.9%361 WE Energies 15.5% 51.8%361 Entergy Arkansas 13.0% 12.0%361 Entergy Texas 11.7% 9.7%361 Pacificorp 6.0% 201.0%361 CenterPoint Electric 2.5% 4.3%361 Upper Peninsula Power Company 0.0% 0.0%361 (blank) 1.8% 17.8%361 Gulf Energy 49.6%361 Alaska Electric Power and Light NA 14.1%361 Cleco NA NA361 Liberty Utilities NA NA361 Municipal Power and Light, City of Anchorage NA 0.0%361 Sharyland NA NA

361.01 Pacific Gas and Electric 4.0% 10.0%361.02 Pacific Gas and Electric 602.0% 688.0%361.1 Consumers Energy 11.7% 8.6%

Account 361

D-11



362 San Diego Gas and Electric 225.2% 209.7%362 Potomac Electric Power Company 64.0% 97.0%362 Louisville Gas and Electric 55.0% 7.0%362 Pacific Gas and Electric 51.0% 57.0%362 Potomac Electric Power Company 41.1% NA362 Liberty Utilities 38.8% 26.2%362 Northern States Power MN 32.7% 26.6%362 Entergy Texas 26.5% 21.4%362 Consumers Energy 23.2% 15.3%362 Public Service of Colorado 20.8% 22.1%362 WE Energies 18.5% 15.1%362 (blank) 18.3% 19.1%362 Pacificorp 18.0% 20.0%362 Oncor 16.6% 15.6%362 Duke Energy Carolinas 16.0% 18.0%362 Northern States Power Wisconsin 15.5% 20.5%362 Alaska Electric Power and Light 14.1% 16.3%362 Minnesota Power (Allete) 12.7% 27.1%362 Municipal Power and Light, City of Anchorage 8.7% 7.9%362 Upper Peninsula Power Company 8.0% 6.0%362 Texas NewMexico Power 7.0% 12.5%362 El Paso Electric Company 3.0% 18.0%362 PSI Energy 3.0% 6.0%362 Idaho Power Company 2.0% 9.0%362 CenterPoint Electric 0.5% 5.2%362 Entergy Arkansas 5.0% 9.0%362 Sharyland 5.1% 7.1%362 Cleco 7.0% 3.4%362 Kansas City Power and Light 7.1% 8.2%362 Progress Energy Carolina 21.0% 8.4%362 Gulf Energy 11.6%362 Otter Tail Power Company 5.0%362 Western Massachusetts Electric Company 21.5%

362 Production Northern States Power Wisconsin NA NA362.03 Comm Kansas City Power and Light 0.9% 0.9%

362.1 Consumers Energy 37.1% 32.5%362.1 Minnesota Power (Allete) 0.4% 0.4%362.7 Pacificorp 0.0% 5.0%

Account 362

D-12



364 Pacific Gas and Electric 785.0% 681.0%364 Potomac Electric Power Company 480.0% 116.0%364 Liberty Utilities 328.8% 246.1%364 Progress Energy Carolina 324.6% 276.0%364 Consumers Energy 233.1% 231.4%364 Northern States Power Wisconsin 230.8% 232.8%364 Louisville Gas and Electric 230.0% 232.0%364 Sharyland 211.3% 228.3%364 Minnesota Power (Allete) 206.5% 202.5%364 Northern States Power MN 184.8% 233.8%364 Pacificorp 181.0% 161.0%364 Kansas City Power and Light 174.2% 139.6%364 Texas NewMexico Power 156.7% 120.7%364 Potomac Electric Power Company 117.1% NA364 (blank) 112.3% 114.1%364 Upper Peninsula Power Company 103.0% 96.0%364 Oncor 92.6% 92.8%364 San Diego Gas and Electric 89.6% 89.9%364 Idaho Power Company 85.0% 91.0%364 WE Energies 58.7% 73.7%364 PSI Energy 54.0% 58.0%364 Municipal Power and Light, City of Anchorage 51.9% 32.0%364 Public Service of Colorado 44.3% 41.0%364 Cleco 37.5% 26.1%364 Entergy Texas 34.5% 29.2%364 Alaska Electric Power and Light 30.4% 160.5%364 Entergy Arkansas 28.0% 19.0%364 CenterPoint Electric 24.4% 31.8%364 Duke Energy Carolinas 13.0% 8.0%364 El Paso Electric Company 23.0% 8.0%364 Gulf Energy 112.7%364 Otter Tail Power Company 75.0%364 Western Massachusetts Electric Company 69.2%364.1 Consumers Energy 1548.0% 250.6%364.2 Consumers Energy NA NA364.3 Consumers Energy 200.4% 96.6%364.4 Consumers Energy 0.0% 0.0%

Account 364

D-13



365 Pacific Gas and Electric 777.0% 589.0%365 Minnesota Power (Allete) 293.4% 295.5%365 Louisville Gas and Electric 219.0% 208.0%365 Texas NewMexico Power 185.7% 114.2%365 Potomac Electric Power Company 142.0% 79.0%365 Kansas City Power and Light 106.7% 107.6%365 Upper Peninsula Power Company 88.0% 87.0%365 Pacificorp 77.0% 68.0%365 San Diego Gas and Electric 74.0% 62.8%365 Progress Energy Carolina 68.1% 82.8%365 Sharyland 61.8% 63.0%365 Public Service of Colorado 60.1% 40.8%365 Oncor 58.1% 60.2%365 (blank) 52.8% 48.3%365 Municipal Power and Light, City of Anchorage 51.3% 41.1%365 Potomac Electric Power Company 48.2% NA365 Liberty Utilities 46.0% 50.8%365 PSI Energy 44.0% 50.0%365 Northern States Power Wisconsin 40.8% 37.8%365 Idaho Power Company 40.0% 50.0%365 Consumers Energy 29.9% 32.9%365 WE Energies 24.2% 35.8%365 Entergy Texas 24.1% 18.5%365 Northern States Power MN 22.5% 22.5%365 Alaska Electric Power and Light 10.8% 22.1%365 Entergy Arkansas 7.0% 3.0%365 CenterPoint Electric 3.2% 7.6%365 El Paso Electric Company 0.0% 0.0%365 Duke Energy Carolinas 8.0% 12.0%365 Cleco 28.4% 18.1%365 Gulf Energy 62.8%365 Otter Tail Power Company 100.0%365 Western Massachusetts Electric Company 158.4%365.1 Minnesota Power (Allete) NA NA365.2 Consumers Energy 59.6% 47.8%

Account 365

D-14



366 Louisville Gas and Electric 384.0% 389.0%366 Pacific Gas and Electric 340.0% 311.0%366 Entergy Texas 252.9% 37.3%366 (blank) 250.4% 99.8%366 Duke Energy Carolinas 217.0% 136.0%366 Northern States Power Wisconsin 179.5% 155.8%366 Texas NewMexico Power 165.3% 107.8%366 Entergy Arkansas 97.0% 17.0%366 Oncor 80.7% 65.7%366 Public Service of Colorado 72.5% 45.7%366 San Diego Gas and Electric 59.2% 56.6%366 Potomac Electric Power Company 57.0% 62.0%366 WE Energies 49.4% 48.0%366 PSI Energy 49.0% 31.0%366 Pacificorp 43.0% 51.0%366 Kansas City Power and Light 34.2% 55.4%366 Consumers Energy 32.0% 41.8%366 Northern States Power MN 23.9% 36.1%366 Minnesota Power (Allete) 23.7% 25.9%366 Liberty Utilities 19.4% 776.8%366 Potomac Electric Power Company 17.8% NA366 Idaho Power Company 17.0% 14.0%366 CenterPoint Electric 15.7% 24.5%366 Progress Energy Carolina 7.1% 1.5%366 El Paso Electric Company 4.0% 2.0%366 Cleco 3.9% 3.4%366 Municipal Power and Light, City of Anchorage 20.7% 8.8%366 Western Massachusetts Electric Company 42.4%366 Alaska Electric Power and Light NA 44.4%366.1 Consumers Energy NA 21.6%

Account 366

D-15



367 Potomac Electric Power Company 135.0% NA367 Potomac Electric Power Company 132.0% 96.0%367 Louisville Gas and Electric 129.0% 128.0%367 Sharyland 86.7% 91.6%367 Texas NewMexico Power 78.2% 45.4%367 Pacific Gas and Electric 66.0% 62.0%367 Liberty Utilities 51.0% 48.3%367 San Diego Gas and Electric 50.7% 56.0%367 WE Energies 44.2% 55.5%367 Minnesota Power (Allete) 39.4% 43.7%367 Pacificorp 36.0% 31.0%367 (blank) 29.7% 13.8%367 Consumers Energy 29.6% 38.8%367 PSI Energy 27.0% 25.0%367 Entergy Texas 19.2% 6.5%367 Northern States Power Wisconsin 18.8% 13.7%367 Idaho Power Company 17.0% 20.0%367 Public Service of Colorado 16.3% 12.5%367 CenterPoint Electric 14.3% 21.7%367 Kansas City Power and Light 13.1% 22.0%367 Oncor 9.9% 11.4%367 Entergy Arkansas 9.0% 6.0%367 Progress Energy Carolina 7.4% 2.3%367 Municipal Power and Light, City of Anchorage 4.3% 3.9%367 Northern States Power MN 2.2% 7.6%367 Alaska Electric Power and Light 0.0% 0.0%367 El Paso Electric Company 0.0% 0.0%367 Cleco 5.0% 6.3%367 Duke Energy Carolinas 57.0% 24.0%367 Gulf Energy 18.4%367 Otter Tail Power Company 5.0%367 Western Massachusetts Electric Company 51.4%367.1 Consumers Energy 32.8% 40.9%367.2 Upper Peninsula Power Company 11.0% 11.0%

Account 367

D-16



368 Liberty Utilities 301.1% 201.3%368 Louisville Gas and Electric 89.0% 102.0%368 Municipal Power and Light, City of Anchorage 47.3% 48.4%368 Consumers Energy 34.9% 35.3%368 Pacificorp 34.0% 18.0%368 Potomac Electric Power Company 31.9% NA

368 Capacitors Northern States Power MN 24.1% 10.5%368 Oncor 21.5% 26.1%368 Potomac Electric Power Company 20.0% 23.0%368 Minnesota Power (Allete) 19.2% 22.8%368 Texas NewMexico Power 18.3% 8.6%368 Progress Energy Carolina 15.9% 4.4%368 (blank) 13.2% 37.6%368 Upper Peninsula Power Company 11.0% 14.0%368 Sharyland 6.4% 4.7%

368 Transformers Northern States Power MN 4.9% 8.4%368 Public Service of Colorado 4.2% 11.1%368 CenterPoint Electric 4.1% 6.3%368 Entergy Arkansas 4.0% 9.0%368 PSI Energy 4.0% 8.0%368 Idaho Power Company 2.0% 1.0%368 El Paso Electric Company 0.0% 0.0%368 Northern States Power Wisconsin 0.4% 3.0%368 Entergy Texas 2.8% 4.3%368 Alaska Electric Power and Light 3.1% 2.1%368 Duke Energy Carolinas 8.0% 3.0%368 WE Energies 17.6% 11.8%368 Kansas City Power and Light 27.4% 22.7%368 Cleco 42.6% 32.7%368 Gulf Energy 31.4%368 Otter Tail Power Company 50.0%368 Western Massachusetts Electric Company 4.8%

368.01 Pacific Gas and Electric 72.0% 56.0%368.02 Pacific Gas and Electric 2.0% 1.0%368.1 San Diego Gas and Electric 79.0% 67.1%368.1 Municipal Power and Light, City of Anchorage 1.9% 5.7%368.2 San Diego Gas and Electric 72.2% 64.5%

Account 368

D-17



369 Liberty Utilities 281.9% 276.7%369 El Paso Electric Company 244.0% 16.0%369 Texas NewMexico Power 232.9% 107.3%

369 Overhead Northern States Power Wisconsin 163.3% 139.8%369 Upper Peninsula Power Company 121.0% 117.0%369 Municipal Power and Light, City of Anchorage 109.0% 82.7%369 Kansas City Power and Light 106.1% 121.5%

369 Overhead Northern States Power MN 104.8% 109.3%369 WE Energies 76.4% 86.6%369 CenterPoint Electric 73.8% 71.6%369 PSI Energy 71.0% 66.0%369 Entergy Arkansas 56.0% 34.0%369 Idaho Power Company 53.0% 47.0%369 (blank) 41.6% 42.8%369 Sharyland 41.4% 49.0%369 Progress Energy Carolina 33.0% 26.9%

369 Underground Northern States Power Wisconsin 32.4% 25.4%369 Public Service of Colorado 25.9% 38.4%369 Alaska Electric Power and Light 23.3% 33.7%369 Oncor 22.8% 19.6%369 Cleco 3.1% 2.0%

369 Underground Northern States Power MN 2.6% 3.3%369 Duke Energy Carolinas 75.0% 3.0%369 Otter Tail Power Company 150.0%369 Western Massachusetts Electric Company 79.0%

369.01 Pacific Gas and Electric 258.0% 177.0%369.02 Pacific Gas and Electric 45.0% 39.0%

Account 369

D-18



369.1 Texas NewMexico Power 295.9% 261.5%369.1 Minnesota Power (Allete) 158.2% 122.5%369.1 San Diego Gas and Electric 91.5% 87.7%

369.1 Overhead Potomac Electric Power Company 77.8% NA369.1 Consumers Energy 72.2% 65.2%369.1 Municipal Power and Light, City of Anchorage 68.6% 69.5%369.1 Pacificorp 52.0% 55.0%369.1 Entergy Texas 22.7% 9.7%369.1 Potomac Electric Power Company 47.0% 59.0%369.1 Gulf Energy 123.0%369.1 Otter Tail Power Company 20.0%369.1 Louisville Gas and Electric NA NA

369.2 Underground Potomac Electric Power Company 3397.7% NA369.2 Louisville Gas and Electric 179.0% 179.0%369.2 Potomac Electric Power Company 100.0% 57.0%369.2 Consumers Energy 62.0% 65.1%369.2 Entergy Texas 59.1% 8.1%369.2 San Diego Gas and Electric 57.7% 59.4%369.2 Pacificorp 54.0% 45.0%369.2 Minnesota Power (Allete) 17.1% 31.9%369.2 Entergy Arkansas 17.0% 15.0%369.2 Gulf Energy 20.4%369.3 Potomac Electric Power Company 404.0% 161.0%

369.3 UG Cable Potomac Electric Power Company 64.1% NA

D-19



370 Progress Energy Carolina 163.6% 19.8%370 Northern States Power Wisconsin 44.1% 37.9%370 Liberty Utilities 36.6% 22.0%370 Texas NewMexico Power 27.5% 20.8%370 Pacific Gas and Electric 16.0% 21.0%370 Sharyland 11.4% 16.7%370 (blank) 8.4% 12.4%370 Consumers Energy 6.9% 13.5%370 Entergy Texas 6.6% 4.5%370 PSI Energy 6.0% 7.0%370 Idaho Power Company 5.0% 3.0%370 Pacificorp 4.0% 4.0%370 El Paso Electric Company 2.0% 7.0%370 Potomac Electric Power Company 1.0% NA370 Minnesota Power (Allete) 0.7% 0.3%370 Alaska Electric Power and Light 0.6% 0.4%370 Municipal Power and Light, City of Anchorage 0.4% 0.0%370 WE Energies 0.0% 0.1%370 Louisville Gas and Electric 0.0% 0.0%370 Potomac Electric Power Company 0.0% 1.0%370 Public Service of Colorado 0.0% 7.8%370 Upper Peninsula Power Company 0.0% 1.0%

370 Old Northern States Power MN 0.0% NA370 CenterPoint Electric 0.1% 0.1%370 Duke Energy Carolinas 2.0% 1.0%370 Entergy Arkansas 2.0% 1.0%370 Kansas City Power and Light 11.2% 6.1%370 Cleco 18.1% 13.0%370 Gulf Energy 20.0%370 Otter Tail Power Company 0.0%370 Western Massachusetts Electric Company 29.8%370 Northern States Power MN NA 20.7%370.1 Texas NewMexico Power 163.7% 24.4%370.1 San Diego Gas and Electric 0.1% 0.2%370.1 Otter Tail Power Company 0.0%370.2 San Diego Gas and Electric 68.4% 69.5%370.2 Public Service of Colorado 0.0% 0.0%

Account 370

D-20



373 Northern States Power Wisconsin 179.2% 167.7%373 Liberty Utilities 104.4% 88.7%373 Texas NewMexico Power 91.0% 65.6%373 (blank) 90.2% 78.9%373 Northern States Power MN 74.5% 93.5%373 Potomac Electric Power Company 57.7% NA373 Upper Peninsula Power Company 54.0% 52.0%373 Minnesota Power (Allete) 49.3% 25.5%373 Pacificorp 48.0% 46.0%373 Entergy Arkansas 44.0% 30.0%

373&374 CenterPoint Electric 38.7% 44.9%373 WE Energies 34.8% 36.7%373 Consumers Energy 31.6% 30.4%373 El Paso Electric Company 31.0% 13.0%373 Oncor 28.2% 27.2%373 Municipal Power and Light, City of Anchorage 22.5% 12.3%373 Public Service of Colorado 22.2% 18.9%373 PSI Energy 6.0% 24.0%373 Entergy Texas 5.5% 5.7%373 Duke Energy Carolinas 3.0% 6.0%373 Cleco 107.9% 93.4%373 Progress Energy Carolina 138.7% 76.6%373 Kansas City Power and Light 337.7% 25.3%373 Gulf Energy 22.5%373 Otter Tail Power Company 5.0%373 Western Massachusetts Electric Company 1.2%373 Alaska Electric Power and Light NA NA

373.01 Pacific Gas and Electric 323.0% 198.0%373.02 Pacific Gas and Electric 188.0% 66.0%373.03 Pacific Gas and Electric 121.0% 68.0%373.04 Pacific Gas and Electric 194.0% 71.0%373.1 Louisville Gas and Electric 70.0% 69.0%373.1 Potomac Electric Power Company 64.0% 42.0%373.2 Potomac Electric Power Company 246.0% 132.0%373.2 Louisville Gas and Electric 133.0% 118.0%373.2 San Diego Gas and Electric 99.3% 85.1%373.2 Idaho Power Company 65.0% 57.0%373.4 Potomac Electric Power Company 26.0% 26.0%

90.7%

Account 373

D-21

D-22

Southern California Edison2015 GRC A.13-11-003

DATA REQUEST SET SCE-TURN-005

To: TURN

Dated: 08/21/2014

Question 07.b:

Exhibit Ref: TURN-10

7. On page 54, TURN uses a comparison of removal costs to “SPS”.

b. Is it TURN’s assertion that SPS is a comparable utility to Southern California Edison?

Response to Question 07.b:

For purposes of this response, TURN interprets the word “comparable” to mean an electric utility owning and operating electric generation and distribution facilities subject to the Uniform System of Accounts. Yes.

Link to unaltered response:

D-23

Appendix E

Testimony from Other Rate Cases

Diversified Utility Consultants, Inc. December 20, 2002

59

investment mix of the annual retirements. This failure to 1properly recognize investment mixes can render the historical 2data base less useful for predicting what will transpire when the 3Company retires the majority of investment in an account in 4the future.1595SCE has failed to adequately recognize, or to recognize at all in 6some cases, the likely impact of economies of scale as it retires 7a greater portion of plant on an annual basis in the future. 8

9

10

2. Incorrect Accounting for Cost as Cost of Removal 11

12

Q. DOES THE COMPANY'S HISTORICAL DATA BASE INCLUDE 13

INCORRECT AMOUNTS AS COST OF REMOVAL? 14

A. Yes. While the Company cannot provide the costs it claims are associated with 15

removal activity in conjunction with a replacement, it appears that a significant 16

amount of its cost of removal is accounted for incorrectly.16017

18

Q. WHY DO YOU BELIEVE THIS TO BE THE SITUATION? 19

A. Normally when a retirement occurs for a utility such as SCE, it is associated with the 20

replacement of plant. Situations such as a pole breaking or wire snapping requires the 21

replacement of the pole or the replacement of the broken wire in order to continue 22

providing safe and reliable service to its customers. Such work appears on a single 23

work order covering the replacement activity and all associated removal work. When 24

such replacement activities result in a retirement, the Company charges some portion 25

of the replacement work order cost to cost of removal rather than the entire cost as an 26

increase in the dollar level of addition associated with the replacement. 27

28

Q. DOES SCE FOLLOW THE USOA AS IT APPLIES TO THIS SITUATION? 29

159 For example, the Company’s reliance on data reflecting a disproportionate level of circuit breaker retirements in an account where overhead conductors make up the majority of the investment artificially increases the level of negative net salvage. See discussion for Account 356, below. 160 Company response to TURN 4-25, Part 2, g.

E-1


60

A. No, not in my opinion. The definitions to the plant instructions set forth in the USOA 1

indicate that the Company is not properly following accounting procedure for 2

replacement activity. 3

4

Q. WHAT DEFINITIONS ARE YOU REFERRING TO? 5

A. According to the USOA, replacing or replacement "means the construction or 6

installation of electric plant in place of property retired, together with the removal of 7

the property retired."161 (Emphasis added) This definition clearly notes that 8

replacement activity includes the costs associated with the removal of the property 9

retired. Therefore, when the USOA defines the cost of removal as "the cost of 10

demolishing, dismantling, tearing down, or otherwise removing electric plant 11

including cost of transportation and handling incidental thereto" it must be limited to 12

those situations where there is no associated replacement.162 The Company's net 13

salvage analysis includes cost associated with the removal of property retired, which 14

should be booked as an increase in new plant cost rather than in the accumulated 15

provision for depreciation as a cost of removal. 16

17

Q. DOES THIS TYPE OF ACCOUNTING HAVE AN IMPACT ON RATE BASE? 18

A. No. Rate base remains the same whether a $100,000 cost incurred is booked as 19

additional plant in service item or as cost of removal in the APFD. 20

21

Q. WHAT DIFFERENCE DOES THE MANNER IN WHICH SUCH COSTS ARE 22

BOOKED MAKE IN THE RATE SETTING PROCESS? 23

A. The incorrect booking of costs to cost of removal rather than as additional cost to a 24

new plant addition overstates the cost of removal and thus reduces net salvage. Since 25

the net salvage analysis relies on a very small sample in comparison to total plant in 26

service the impact is significantly magnified in the depreciation analysis. While 27

161 18 CFR Part 101, Definition 30 A.162 Therefore, when USOA Plant Instructions 10B(2) states that cost of removal shall be charged to the depreciation account, it applies to actual costs that appropriately meet the preceding definitions. The costs incurred in replacement activity are addressed in the replacement definition of the USOA. Further, the reference in instruction 10B(2) to retirement of plant “with or without replacement” appropriately applies to the retirement dollars noted in the same sentence, not to the last sentence in that instruction. This approach is also consistent with USOA Plant Instruction 2(A).

E-2


61

$100,000 of cost may have a relatively small impact if incorrectly included in rate 1

base, a $100,000 cost inappropriately recorded in a particular account as cost of 2

removal may actually result in millions of dollars of additional depreciation expense 3

being inappropriately charged to ratepayers during current periods. 4

5

Q. PLEASE EXPLAIN WHY THE REVENUE REQUIREMENT IMPACT OF 6

THE SAME $100,000 COST INCURRED IS DIFFERENT WHEN IT IS 7

HANDLED AS REDUCTION IN THE COST OF A PLANT ADDITION 8

VERSUS NET SALVAGE. 9

A. Assume that the plant account in question has an outstanding gross plant balance of 10

$100,000,000. Further, assume that the Company’s proposed level of retirements, 11

gross salvage, and cost of removal during the historical period reviewed for net 12

salvage purposes are $1,000,000, zero and $150,000, respectively. Finally, assume a 13

10-year ASL utilizing the whole life technique and no existing reserve deficiency or 14

surplus. 15

16

The net salvage relationship from the Company’s approach would be a negative 15% 17

[($0-$150,000) / $1,000,000]. The negative 15% applied to the $100,000,000 18

depreciable balance would produce a $15,000,000 total net salvage requirement, or 19

$1.5 million per year over the 10-year life. Alternatively, if the $100,000 booked as 20

cost of removal were instead booked as $100,000 of additional plant costs, the annual 21

impact would drop to only $500,500 per year, or approximately a million dollars less 22

annually.163 Since rates may not be changed for several years, the impact to 23

customers is multiplied for each year between rate cases. 24

25

Q. WHAT ADJUSTMENT HAVE YOU MADE TO THE COMPANY'S NET 26

SALVAGE ANALYSIS TO CORRECT THIS INAPPROPRIATE 27

ACCOUNTING? 28

163 Net salvage would drop to a negative 5% [($0-$50,000) / $1,000,000]. The depreciable balance would increase to $100,100,000 [$100,000,000+$100,000]. Total net salvage would equal $5,005,000 [$100,100,000 x .05]. Annual requirements would equal $500,500 [$5,005,000 / 10 years].

E-3


62

A. I have made no explicit numerical adjustment, largely because the Company contends 1

that it does not have the information to quantify the actual impact of such situation. I 2

am referencing it here to identify another problem which may result in overstating 3

cost of removal utilized for depreciation purposes. In fact, given that the Company’s 4

proposals for net salvage are the most negative or one of the most negative values for 5

many accounts compared to an industry survey, this accounting problem is very likely 6

part of the underlying cause for this situation. 7

8

Q. CAN YOU PLACE SCE’S NET SALVAGE REQUEST FOR ITS MASS 9

PROPERTY ACCOUNTS INTO PERSPECTIVE WITH THE INDUSTRY? 10

A. Yes. There are 25 mass property accounts for which SCE has proposed net salvage 11

and for which it has also calculated an industry average comparison.164 For 22 of 12

these 25 accounts, the Company proposes net salvage levels more negative or less 13

positive than its calculated industry average for the same account. That represents 14

88% of the accounts. Moreover, the Company’s proposed level equals or exceeds the 15

most extreme industry reported levels for 11, or 44%, of the accounts.165 If the 16

industry average were used to set the utility’s total net salvage level, the resulting17

figure would be $4.3 billion lower than the Company’s figure. In other words, SCE’s 18

proposal is 4.2 times the industry average level. SCE’s proposal deviates from the 19

industry average to such an extent that it requires substantial and meaningful support 20

and justification before it can be considered credible. 21

22

3. “Other Items” APFD Category 23

24

Q. HOW DOES THE COMPANY CATEGORIZE AMOUNTS IN ITS APFD? 25

A. SCE’s net salvage workpapers sets forth the categorization of accumulated provision 26

for depreciation (“APFD”) into four areas. Those four categories are retirements, cost 27

of removal, salvage, and “Other Items”.16628

29

164 SCE-8, Chapter XI, Part 1, workpaper page 19 and Part 3, various pages. 165 Id. 166 SCE-8, Chapter XI, Part 3, various pages.

E-4


Account Description Company 3 yr Avg 5 yr Avg

352 352/361 Oncor 116.8% 84.3%352 352 Duke Energy Carolinas 116.0% 54.0%352 352 Oncor 80.9% 52.3%352 352 Idaho Power Company 68.0% 31.0%352 352 Public Service of Colorado 61.7% 50.8%352 352 Kansas City Power and Light 46.0% 28.8%352 352 Pacificorp 36.0% 51.0%352 352 American Transmission Company 24.8% 26.0%352 352 SPS Texas/ SPS NM 20.9% 13.3%352 352 Northern States Power Wisconsin 16.3% 15.9%352 352 Entergy Arkansas 16.0% 0.0%352 352 Progress Energy Carolina 13.6% 18.7%352 352 Production Northern States Power Wisconsin 11.6% 11.6%352 352 Louisville Gas and Electric 5.0% 4.0%352 352 Northern States Power MN 1.2% 15.3%352 352 CenterPoint Electric 0.0% 0.0%352 352 El Paso Electric Company 0.0% 0.0%352 352 Entergy Texas 40.4% 25.1%352 352 Gulf Energy 1.7%352 352 Alaska Electric Power and Light NA NA352 352 Cleco NA NA352 352 Minnesota Power (Allete) NA NA352 352 Municipal Power and Light, City of Anchorage NA 0.0%352 352 Sharyland NA NA

352.01 352.01 Pacific Gas and Electric 382.0% 415.0%352.01 352.01 American Transmission Company 0.0% 0.0%

Account 352

E-5


353 353 Texas NewMexico Power 144.8% 134.5%353 353 Duke Energy Carolinas 63.0% 54.0%353 353 Northern States Power MN 32.8% 24.2%353 353 Public Service of Colorado 32.6% 30.1%353 353 Northern States Power Wisconsin 24.6% 26.1%353 353 Louisville Gas and Electric 24.0% 14.0%353 353 Entergy Texas 18.4% 14.4%353 353 Alaska Electric Power and Light 16.9% 16.9%353 353 Minnesota Power (Allete) 15.4% 13.1%353 353 Idaho Power Company 15.0% 9.0%353 353 PSI Energy 14.0% 11.0%353 353 Oncor 13.2% 15.5%353 353 Pacificorp 13.0% 14.0%353 353 Progress Energy Carolina 9.9% 13.4%353 353 Kansas City Power and Light 6.4% 10.4%353 353 Municipal Power and Light, City of Anchorage 5.2% 4.2%353 353 Entergy Arkansas 3.0% 5.0%353 353 CenterPoint Electric 2.6% 3.2%353 353 El Paso Electric Company 1.0% 1.0%353 353 Comm Kansas City Power and Light 0.8% 0.8%353 353 Production Northern States Power Wisconsin 0.0% 19.8%353 353 Sharyland 8.4% 112.6%353 353 Cleco 16.2% 8.8%353 353 Gulf Energy 10.5%353 353 Otter Tail Power Company 5.0%

353.01 353.01 Pacific Gas and Electric 114.0% 83.0%353.01 353.01 American Transmission Company 16.1% 21.0%353.02 353.02 American Transmission Company 25.1% 26.1%353.02 353.02 Pacific Gas and Electric 0.0% 3.0%353.03 353.03 American Transmission Company 23.5% 28.2%353.1 353.1 Public Service of Colorado 136.8% NA353.1 353.1 Minnesota Power (Allete) NA NA353.2 353.2 PSI Energy NA 5.0%

Account 353

E-6


354 354 Northern States Power Wisconsin 6432.3% 6466.6%354 354 Pacific Gas and Electric 289.0% 323.0%354 354 PSI Energy 157.0% 11.0%354 354 Entergy Arkansas 153.0% 116.0%354 354 Public Service of Colorado 144.9% 109.9%354 354 Northern States Power MN 130.5% 72.1%354 354 Louisville Gas and Electric 59.0% 59.0%354 354 Pacificorp 52.0% 35.0%354 354 Duke Energy Carolinas 46.0% 62.0%354 354 Idaho Power Company 34.0% 19.0%354 354 Entergy Texas 33.8% 136.3%354 354 Oncor 33.4% 39.9%354 354 Alaska Electric Power and Light 31.2% 31.2%354 354 Progress Energy Carolina 22.0% 19.2%354 354 American Transmission Company 18.2% 71.8%354 354 CenterPoint Electric 6.8% 10.9%354 354 Minnesota Power (Allete) 2.0% 2.0%354 354 Kansas City Power and Light 0.0% 0.0%354 354 Gulf Energy 33.9%354 354 Otter Tail Power Company 10.0%354 354 Cleco NA NA354 354 Sharyland NA NA354 354 Texas NewMexico Power NA NA354 354 (blank) NA NA

354.1 354.1 Municipal Power and Light, City of Anchorage NA NA

Account 354

E-7


355 355 Sharyland 614.7% 54.3%355 355 (blank) 484.5% 483.4%355 355 Northern States Power Wisconsin 217.5% 92.2%355 355 Kansas City Power and Light 212.1% 212.7%355 355 Public Service of Colorado 210.9% 31.6%355 355 Oncor 162.6% 228.9%355 355 Texas NewMexico Power 147.2% 110.2%355 355 Louisville Gas and Electric 138.0% 168.0%355 355 Entergy Texas 136.6% 69.0%355 355 Northern States Power MN 88.4% 101.9%355 355 Pacificorp 67.0% 39.0%355 355 Entergy Arkansas 60.0% 49.0%355 355 Idaho Power Company 57.0% 53.0%355 355 PSI Energy 55.0% 61.0%355 355 Pacific Gas and Electric 49.0% 62.0%355 355 Alaska Electric Power and Light 32.8% 47.5%355 355 CenterPoint Electric 32.3% 34.8%355 355 Cleco 32.1% 66.9%355 355 Minnesota Power (Allete) 15.8% 38.7%355 355 Municipal Power and Light, City of Anchorage 12.1% 11.2%355 355 Duke Energy Carolinas 7.0% 24.0%355 355 Progress Energy Carolina 3.7% 13.4%355 355 El Paso Electric Company 1.0% 3.0%355 355 Gulf Energy 149.1%355 355 Otter Tail Power Company 50.0%

355.1 355.01 American Transmission Company 117.3% 76.4%355.02 355.02 American Transmission Company 188.1% 135.5%355.1 355.1 Municipal Power and Light, City of Anchorage NA 0.0%

Account 355

E-8


356 356 American Transmission Company 296.4% 143.8%356 356 Texas NewMexico Power 232.2% 249.7%356 356 Kansas City Power and Light 191.6% 157.3%356 356 CenterPoint Electric 151.3% 168.5%356 356 Pacific Gas and Electric 91.0% 100.0%356 356 Oncor 90.4% 154.5%356 356 Entergy Arkansas 89.0% 82.0%356 356 PSI Energy 89.0% 40.0%356 356 Louisville Gas and Electric 83.0% 66.0%356 356 Duke Energy Carolinas 78.0% 82.0%356 356 Northern States Power Wisconsin 70.0% 35.9%356 356 Entergy Texas 61.7% 33.9%356 356 Pacificorp 50.0% 28.0%356 356 (blank) 48.2% 61.1%356 356 Idaho Power Company 48.0% 42.0%356 356 Progress Energy Carolina 38.9% 37.0%356 356 Northern States Power MN 12.9% 27.2%356 356 Municipal Power and Light, City of Anchorage 9.5% 7.4%356 356 Public Service of Colorado 7.8% 2.1%356 356 El Paso Electric Company 0.0% 0.0%356 356 Cleco 1.1% 24.0%356 356 Minnesota Power (Allete) 12.2% 9.9%356 356 Gulf Energy 24.7%356 356 Otter Tail Power Company 30.0%356 356 Alaska Electric Power and Light NA 31.7%356 356 Sharyland NA 57.3%

356.01 356.01 American Transmission Company 24.9% 22.2%356.02 356.02 American Transmission Company NA 0.0%356.03 356.03 American Transmission Company NA NA356.1 356.1 Municipal Power and Light, City of Anchorage 0.0% 0.0%356.1 356.1 Minnesota Power (Allete) NA NA

357 357 Oncor 28.8% 28.8%357 357 Northern States Power MN 0.0% 0.0%357 357 Pacific Gas and Electric 0.0% 0.0%357 357 Pacificorp 0.0% 0.0%357 357 American Transmission Company NA 33.5%357 357 CenterPoint Electric NA NA357 357 Kansas City Power and Light NA NA357 357 Municipal Power and Light, City of Anchorage NA NA357 357 Northern States Power Wisconsin NA NA357 357 Progress Energy Carolina NA NA357 357 Public Service of Colorado NA NA357 357 (blank) NA NA

Account 356

Account 357

E-9


358 358 Louisville Gas and Electric 61.0% 8.0%358 358 Oncor 48.0% 48.0%358 358 Pacific Gas and Electric 38.0% 54.0%358 358 Northern States Power Wisconsin 37.7% 37.7%358 358 American Transmission Company 23.8% 26.2%358 358 Northern States Power MN 14.9% 12.3%358 358 Pacificorp 0.0% 0.0%358 358 Otter Tail Power Company 5.0%358 358 Alaska Electric Power and Light NA 32.1%358 358 CenterPoint Electric NA NA358 358 Cleco NA NA358 358 Kansas City Power and Light NA NA358 358 Municipal Power and Light, City of Anchorage NA NA358 358 Progress Energy Carolina NA NA358 358 Public Service of Colorado NA 37.9%358 358 (blank) NA NA

359 359 Pacific Gas and Electric 180.0% 164.0%359 359 CenterPoint Electric 50.1% 64.7%359 359 Pacificorp 0.0% 0.0%359 359 American Transmission Company NA NA359 359 Cleco NA NA359 359 Minnesota Power (Allete) NA NA359 359 Northern States Power Wisconsin NA NA359 359 Progress Energy Carolina NA 0.0%359 359 Public Service of Colorado NA NA

359.1 359.1 Municipal Power and Light, City of Anchorage NA NA

Account 358

Account 359

E-10


361 361 Potomac Electric Power Company 585.0% 134.0%361 361 San Diego Gas and Electric 466.3% 384.2%361 361 PSI Energy 234.0% 307.0%361 361 Oncor 194.5% 165.5%361 361 Northern States Power MN 112.1% 109.9%361 361 Kansas City Power and Light 103.9% 70.7%361 361 Northern States Power Wisconsin 88.4% 42.3%361 361 Potomac Electric Power Company 75.4% NA361 361 Louisville Gas and Electric 55.0% 1.0%361 361 Texas NewMexico Power 39.6% 18.2%361 361 Idaho Power Company 39.0% 25.0%361 361 Minnesota Power (Allete) 36.5% 35.5%361 361 Consumers Energy 28.4% 65.5%361 361 Progress Energy Carolina 19.8% 50.5%361 361 Duke Energy Carolinas 18.0% 12.0%361 361 Public Service of Colorado 17.5% 19.9%361 361 WE Energies 15.5% 51.8%361 361 Entergy Arkansas 13.0% 12.0%361 361 Entergy Texas 11.7% 9.7%361 361 Pacificorp 6.0% 201.0%361 361 CenterPoint Electric 2.5% 4.3%361 361 Upper Peninsula Power Company 0.0% 0.0%361 361 (blank) 1.8% 17.8%361 361 Gulf Energy 49.6%361 361 Alaska Electric Power and Light NA 14.1%361 361 Cleco NA NA361 361 Liberty Utilities NA NA361 361 Municipal Power and Light, City of Anchorage NA 0.0%361 361 Sharyland NA NA

361.01 361.01 Pacific Gas and Electric 4.0% 10.0%361.02 361.02 Pacific Gas and Electric 602.0% 688.0%361.1 361.1 Consumers Energy 11.7% 8.6%

Account 361

E-11


362 362 San Diego Gas and Electric 225.2% 209.7%362 362 Potomac Electric Power Company 64.0% 97.0%362 362 Louisville Gas and Electric 55.0% 7.0%362 362 Pacific Gas and Electric 51.0% 57.0%362 362 Potomac Electric Power Company 41.1% NA362 362 Liberty Utilities 38.8% 26.2%362 362 Northern States Power MN 32.7% 26.6%362 362 Entergy Texas 26.5% 21.4%362 362 Consumers Energy 23.2% 15.3%362 362 Public Service of Colorado 20.8% 22.1%362 362 WE Energies 18.5% 15.1%362 362 (blank) 18.3% 19.1%362 362 Pacificorp 18.0% 20.0%362 362 Oncor 16.6% 15.6%362 362 Duke Energy Carolinas 16.0% 18.0%362 362 Northern States Power Wisconsin 15.5% 20.5%362 362 Alaska Electric Power and Light 14.1% 16.3%362 362 Minnesota Power (Allete) 12.7% 27.1%362 362 Municipal Power and Light, City of Anchorage 8.7% 7.9%362 362 Upper Peninsula Power Company 8.0% 6.0%362 362 Texas NewMexico Power 7.0% 12.5%362 362 El Paso Electric Company 3.0% 18.0%362 362 PSI Energy 3.0% 6.0%362 362 Idaho Power Company 2.0% 9.0%362 362 CenterPoint Electric 0.5% 5.2%362 362 Entergy Arkansas 5.0% 9.0%362 362 Sharyland 5.1% 7.1%362 362 Cleco 7.0% 3.4%362 362 Kansas City Power and Light 7.1% 8.2%362 362 Progress Energy Carolina 21.0% 8.4%362 362 Gulf Energy 11.6%362 362 Otter Tail Power Company 5.0%362 362 Western Massachusetts Electric Company 21.5%362 362 Production Northern States Power Wisconsin NA NA

362.03 362.03 Comm Kansas City Power and Light 0.9% 0.9%362.1 362.1 Consumers Energy 37.1% 32.5%362.1 362.1 Minnesota Power (Allete) 0.4% 0.4%362.7 362.7 Pacificorp 0.0% 5.0%

Account 362

E-12


364 364 Pacific Gas and Electric 785.0% 681.0%364 364 Potomac Electric Power Company 480.0% 116.0%364 364 Liberty Utilities 328.8% 246.1%364 364 Progress Energy Carolina 324.6% 276.0%364 364 Consumers Energy 233.1% 231.4%364 364 Northern States Power Wisconsin 230.8% 232.8%364 364 Louisville Gas and Electric 230.0% 232.0%364 364 Sharyland 211.3% 228.3%364 364 Minnesota Power (Allete) 206.5% 202.5%364 364 Northern States Power MN 184.8% 233.8%364 364 Pacificorp 181.0% 161.0%364 364 Kansas City Power and Light 174.2% 139.6%364 364 Texas NewMexico Power 156.7% 120.7%364 364 Potomac Electric Power Company 117.1% NA364 364 (blank) 112.3% 114.1%364 364 Upper Peninsula Power Company 103.0% 96.0%364 364 Oncor 92.6% 92.8%364 364 San Diego Gas and Electric 89.6% 89.9%364 364 Idaho Power Company 85.0% 91.0%364 364 WE Energies 58.7% 73.7%364 364 PSI Energy 54.0% 58.0%364 364 Municipal Power and Light, City of Anchorage 51.9% 32.0%364 364 Public Service of Colorado 44.3% 41.0%364 364 Cleco 37.5% 26.1%364 364 Entergy Texas 34.5% 29.2%364 364 Alaska Electric Power and Light 30.4% 160.5%364 364 Entergy Arkansas 28.0% 19.0%364 364 CenterPoint Electric 24.4% 31.8%364 364 Duke Energy Carolinas 13.0% 8.0%364 364 El Paso Electric Company 23.0% 8.0%364 364 Gulf Energy 112.7%364 364 Otter Tail Power Company 75.0%364 364 Western Massachusetts Electric Company 69.2%

364.1 364.1 Consumers Energy 1548.0% 250.6%364.2 364.2 Consumers Energy NA NA364.3 364.3 Consumers Energy 200.4% 96.6%364.4 364.4 Consumers Energy 0.0% 0.0%

Account 364

E-13


365 365 Pacific Gas and Electric 777.0% 589.0%365 365 Minnesota Power (Allete) 293.4% 295.5%365 365 Louisville Gas and Electric 219.0% 208.0%365 365 Texas NewMexico Power 185.7% 114.2%365 365 Potomac Electric Power Company 142.0% 79.0%365 365 Kansas City Power and Light 106.7% 107.6%365 365 Upper Peninsula Power Company 88.0% 87.0%365 365 Pacificorp 77.0% 68.0%365 365 San Diego Gas and Electric 74.0% 62.8%365 365 Progress Energy Carolina 68.1% 82.8%365 365 Sharyland 61.8% 63.0%365 365 Public Service of Colorado 60.1% 40.8%365 365 Oncor 58.1% 60.2%365 365 (blank) 52.8% 48.3%365 365 Municipal Power and Light, City of Anchorage 51.3% 41.1%365 365 Potomac Electric Power Company 48.2% NA365 365 Liberty Utilities 46.0% 50.8%365 365 PSI Energy 44.0% 50.0%365 365 Northern States Power Wisconsin 40.8% 37.8%365 365 Idaho Power Company 40.0% 50.0%365 365 Consumers Energy 29.9% 32.9%365 365 WE Energies 24.2% 35.8%365 365 Entergy Texas 24.1% 18.5%365 365 Northern States Power MN 22.5% 22.5%365 365 Alaska Electric Power and Light 10.8% 22.1%365 365 Entergy Arkansas 7.0% 3.0%365 365 CenterPoint Electric 3.2% 7.6%365 365 El Paso Electric Company 0.0% 0.0%365 365 Duke Energy Carolinas 8.0% 12.0%365 365 Cleco 28.4% 18.1%365 365 Gulf Energy 62.8%365 365 Otter Tail Power Company 100.0%365 365 Western Massachusetts Electric Company 158.4%

365.1 365.1 Minnesota Power (Allete) NA NA365.2 365.2 Consumers Energy 59.6% 47.8%

Account 365

E-14


366 366 Louisville Gas and Electric 384.0% 389.0%366 366 Pacific Gas and Electric 340.0% 311.0%366 366 Entergy Texas 252.9% 37.3%366 366 (blank) 250.4% 99.8%366 366 Duke Energy Carolinas 217.0% 136.0%366 366 Northern States Power Wisconsin 179.5% 155.8%366 366 Texas NewMexico Power 165.3% 107.8%366 366 Entergy Arkansas 97.0% 17.0%366 366 Oncor 80.7% 65.7%366 366 Public Service of Colorado 72.5% 45.7%366 366 San Diego Gas and Electric 59.2% 56.6%366 366 Potomac Electric Power Company 57.0% 62.0%366 366 WE Energies 49.4% 48.0%366 366 PSI Energy 49.0% 31.0%366 366 Pacificorp 43.0% 51.0%366 366 Kansas City Power and Light 34.2% 55.4%366 366 Consumers Energy 32.0% 41.8%366 366 Northern States Power MN 23.9% 36.1%366 366 Minnesota Power (Allete) 23.7% 25.9%366 366 Liberty Utilities 19.4% 776.8%366 366 Potomac Electric Power Company 17.8% NA366 366 Idaho Power Company 17.0% 14.0%366 366 CenterPoint Electric 15.7% 24.5%366 366 Progress Energy Carolina 7.1% 1.5%366 366 El Paso Electric Company 4.0% 2.0%366 366 Cleco 3.9% 3.4%366 366 Municipal Power and Light, City of Anchorage 20.7% 8.8%366 366 Western Massachusetts Electric Company 42.4%366 366 Alaska Electric Power and Light NA 44.4%

366.1 366.1 Consumers Energy NA 21.6%

Account 366

E-15


367 367 Potomac Electric Power Company 135.0% NA367 367 Potomac Electric Power Company 132.0% 96.0%367 367 Louisville Gas and Electric 129.0% 128.0%367 367 Sharyland 86.7% 91.6%367 367 Texas NewMexico Power 78.2% 45.4%367 367 Pacific Gas and Electric 66.0% 62.0%367 367 Liberty Utilities 51.0% 48.3%367 367 San Diego Gas and Electric 50.7% 56.0%367 367 WE Energies 44.2% 55.5%367 367 Minnesota Power (Allete) 39.4% 43.7%367 367 Pacificorp 36.0% 31.0%367 367 (blank) 29.7% 13.8%367 367 Consumers Energy 29.6% 38.8%367 367 PSI Energy 27.0% 25.0%367 367 Entergy Texas 19.2% 6.5%367 367 Northern States Power Wisconsin 18.8% 13.7%367 367 Idaho Power Company 17.0% 20.0%367 367 Public Service of Colorado 16.3% 12.5%367 367 CenterPoint Electric 14.3% 21.7%367 367 Kansas City Power and Light 13.1% 22.0%367 367 Oncor 9.9% 11.4%367 367 Entergy Arkansas 9.0% 6.0%367 367 Progress Energy Carolina 7.4% 2.3%367 367 Municipal Power and Light, City of Anchorage 4.3% 3.9%367 367 Northern States Power MN 2.2% 7.6%367 367 Alaska Electric Power and Light 0.0% 0.0%367 367 El Paso Electric Company 0.0% 0.0%367 367 Cleco 5.0% 6.3%367 367 Duke Energy Carolinas 57.0% 24.0%367 367 Gulf Energy 18.4%367 367 Otter Tail Power Company 5.0%367 367 Western Massachusetts Electric Company 51.4%

367.1 367.1 Consumers Energy 32.8% 40.9%367.2 367.2 Upper Peninsula Power Company 11.0% 11.0%

Account 367

E-16


368 368 Liberty Utilities 301.1% 201.3%368 368 Louisville Gas and Electric 89.0% 102.0%368 368 Municipal Power and Light, City of Anchorage 47.3% 48.4%368 368 Consumers Energy 34.9% 35.3%368 368 Pacificorp 34.0% 18.0%368 368 Potomac Electric Power Company 31.9% NA368 368 Capacitors Northern States Power MN 24.1% 10.5%368 368 Oncor 21.5% 26.1%368 368 Potomac Electric Power Company 20.0% 23.0%368 368 Minnesota Power (Allete) 19.2% 22.8%368 368 Texas NewMexico Power 18.3% 8.6%368 368 Progress Energy Carolina 15.9% 4.4%368 368 (blank) 13.2% 37.6%368 368 Upper Peninsula Power Company 11.0% 14.0%368 368 Sharyland 6.4% 4.7%368 368 Transformers Northern States Power MN 4.9% 8.4%368 368 Public Service of Colorado 4.2% 11.1%368 368 CenterPoint Electric 4.1% 6.3%368 368 Entergy Arkansas 4.0% 9.0%368 368 PSI Energy 4.0% 8.0%368 368 Idaho Power Company 2.0% 1.0%368 368 El Paso Electric Company 0.0% 0.0%368 368 Northern States Power Wisconsin 0.4% 3.0%368 368 Entergy Texas 2.8% 4.3%368 368 Alaska Electric Power and Light 3.1% 2.1%368 368 Duke Energy Carolinas 8.0% 3.0%368 368 WE Energies 17.6% 11.8%368 368 Kansas City Power and Light 27.4% 22.7%368 368 Cleco 42.6% 32.7%368 368 Gulf Energy 31.4%368 368 Otter Tail Power Company 50.0%368 368 Western Massachusetts Electric Company 4.8%

368.01 368.01 Pacific Gas and Electric 72.0% 56.0%368.02 368.02 Pacific Gas and Electric 2.0% 1.0%368.1 368.1 San Diego Gas and Electric 79.0% 67.1%368.1 368.1 Municipal Power and Light, City of Anchorage 1.9% 5.7%368.2 368.2 San Diego Gas and Electric 72.2% 64.5%

Account 368

E-17


369 369 Liberty Utilities 281.9% 276.7%369 369 El Paso Electric Company 244.0% 16.0%369 369 Texas NewMexico Power 232.9% 107.3%369 369 Overhead Northern States Power Wisconsin 163.3% 139.8%369 369 Upper Peninsula Power Company 121.0% 117.0%369 369 Municipal Power and Light, City of Anchorage 109.0% 82.7%369 369 Kansas City Power and Light 106.1% 121.5%369 369 Overhead Northern States Power MN 104.8% 109.3%369 369 WE Energies 76.4% 86.6%369 369 CenterPoint Electric 73.8% 71.6%369 369 PSI Energy 71.0% 66.0%369 369 Entergy Arkansas 56.0% 34.0%369 369 Idaho Power Company 53.0% 47.0%369 369 (blank) 41.6% 42.8%369 369 Sharyland 41.4% 49.0%369 369 Progress Energy Carolina 33.0% 26.9%369 369 Underground Northern States Power Wisconsin 32.4% 25.4%369 369 Public Service of Colorado 25.9% 38.4%369 369 Alaska Electric Power and Light 23.3% 33.7%369 369 Oncor 22.8% 19.6%369 369 Cleco 3.1% 2.0%369 369 Underground Northern States Power MN 2.6% 3.3%369 369 Duke Energy Carolinas 75.0% 3.0%369 369 Otter Tail Power Company 150.0%369 369 Western Massachusetts Electric Company 79.0%

369.01 369.01 Pacific Gas and Electric 258.0% 177.0%369.02 369.02 Pacific Gas and Electric 45.0% 39.0%

Account 369

E-18


369.1 369.1 Texas NewMexico Power 295.9% 261.5%369.1 369.1 Minnesota Power (Allete) 158.2% 122.5%369.1 369.1 San Diego Gas and Electric 91.5% 87.7%369.1 369.1 Overhead Potomac Electric Power Company 77.8% NA369.1 369.1 Consumers Energy 72.2% 65.2%369.1 369.1 Municipal Power and Light, City of Anchorage 68.6% 69.5%369.1 369.1 Pacificorp 52.0% 55.0%369.1 369.1 Entergy Texas 22.7% 9.7%369.1 369.1 Potomac Electric Power Company 47.0% 59.0%369.1 369.1 Gulf Energy 123.0%369.1 369.1 Otter Tail Power Company 20.0%369.1 369.1 Louisville Gas and Electric NA NA369.2 369.2 Underground Potomac Electric Power Company 3397.7% NA369.2 369.2 Louisville Gas and Electric 179.0% 179.0%369.2 369.2 Potomac Electric Power Company 100.0% 57.0%369.2 369.2 Consumers Energy 62.0% 65.1%369.2 369.2 Entergy Texas 59.1% 8.1%369.2 369.2 San Diego Gas and Electric 57.7% 59.4%369.2 369.2 Pacificorp 54.0% 45.0%369.2 369.2 Minnesota Power (Allete) 17.1% 31.9%369.2 369.2 Entergy Arkansas 17.0% 15.0%369.2 369.2 Gulf Energy 20.4%369.3 369.3 Potomac Electric Power Company 404.0% 161.0%369.3 369.3 UG Cable Potomac Electric Power Company 64.1% NA

E-19


370 370 Progress Energy Carolina 163.6% 19.8%370 370 Northern States Power Wisconsin 44.1% 37.9%370 370 Liberty Utilities 36.6% 22.0%370 370 Texas NewMexico Power 27.5% 20.8%370 370 Pacific Gas and Electric 16.0% 21.0%370 370 Sharyland 11.4% 16.7%370 370 (blank) 8.4% 12.4%370 370 Consumers Energy 6.9% 13.5%370 370 Entergy Texas 6.6% 4.5%370 370 PSI Energy 6.0% 7.0%370 370 Idaho Power Company 5.0% 3.0%370 370 Pacificorp 4.0% 4.0%370 370 El Paso Electric Company 2.0% 7.0%370 370 Potomac Electric Power Company 1.0% NA370 370 Minnesota Power (Allete) 0.7% 0.3%370 370 Alaska Electric Power and Light 0.6% 0.4%370 370 Municipal Power and Light, City of Anchorage 0.4% 0.0%370 370 WE Energies 0.0% 0.1%370 370 Louisville Gas and Electric 0.0% 0.0%370 370 Potomac Electric Power Company 0.0% 1.0%370 370 Public Service of Colorado 0.0% 7.8%370 370 Upper Peninsula Power Company 0.0% 1.0%370 370 Old Northern States Power MN 0.0% NA370 370 CenterPoint Electric 0.1% 0.1%370 370 Duke Energy Carolinas 2.0% 1.0%370 370 Entergy Arkansas 2.0% 1.0%370 370 Kansas City Power and Light 11.2% 6.1%370 370 Cleco 18.1% 13.0%370 370 Gulf Energy 20.0%370 370 Otter Tail Power Company 0.0%370 370 Western Massachusetts Electric Company 29.8%370 370 Northern States Power MN NA 20.7%

370.1 370.1 Texas NewMexico Power 163.7% 24.4%370.1 370.1 San Diego Gas and Electric 0.1% 0.2%370.1 370.1 Otter Tail Power Company 0.0%370.2 370.2 San Diego Gas and Electric 68.4% 69.5%370.2 370.2 Public Service of Colorado 0.0% 0.0%

Account 370

E-20


373 373 Northern States Power Wisconsin 179.2% 167.7%373 373 Liberty Utilities 104.4% 88.7%373 373 Texas NewMexico Power 91.0% 65.6%373 373 (blank) 90.2% 78.9%373 373 Northern States Power MN 74.5% 93.5%373 373 Potomac Electric Power Company 57.7% NA373 373 Upper Peninsula Power Company 54.0% 52.0%373 373 Minnesota Power (Allete) 49.3% 25.5%373 373 Pacificorp 48.0% 46.0%373 373 Entergy Arkansas 44.0% 30.0%373 373&374 CenterPoint Electric 38.7% 44.9%373 373 WE Energies 34.8% 36.7%373 373 Consumers Energy 31.6% 30.4%373 373 El Paso Electric Company 31.0% 13.0%373 373 Oncor 28.2% 27.2%373 373 Municipal Power and Light, City of Anchorage 22.5% 12.3%373 373 Public Service of Colorado 22.2% 18.9%373 373 PSI Energy 6.0% 24.0%373 373 Entergy Texas 5.5% 5.7%373 373 Duke Energy Carolinas 3.0% 6.0%373 373 Cleco 107.9% 93.4%373 373 Progress Energy Carolina 138.7% 76.6%373 373 Kansas City Power and Light 337.7% 25.3%373 373 Gulf Energy 22.5%373 373 Otter Tail Power Company 5.0%373 373 Western Massachusetts Electric Company 1.2%373 373 Alaska Electric Power and Light NA NA

373.01 373.01 Pacific Gas and Electric 323.0% 198.0%373.02 373.02 Pacific Gas and Electric 188.0% 66.0%373.03 373.03 Pacific Gas and Electric 121.0% 68.0%373.04 373.04 Pacific Gas and Electric 194.0% 71.0%373.1 373.1 Louisville Gas and Electric 70.0% 69.0%373.1 373.1 Potomac Electric Power Company 64.0% 42.0%373.2 373.2 Potomac Electric Power Company 246.0% 132.0%373.2 373.2 Louisville Gas and Electric 133.0% 118.0%373.2 373.2 San Diego Gas and Electric 99.3% 85.1%373.2 373.2 Idaho Power Company 65.0% 57.0%373.4 373.4 Potomac Electric Power Company 26.0% 26.0%

Account 373

E-21

Southern California Edison - 2006 GRC A. 04-12-014 Direct Testimony of Michael J. Majoros, Jr.

May 2005 Page 40 of 44

Alternatives to TIFCA1

Q. Are there any alternatives to TIFCA? 2

A. Yes, there are alternatives to TIFCA. Below I will discuss a “cash basis” 3

alternative, and three “accrual basis” alternatives. There are probably more 4

alternatives but these are the ones that I believe are reasonable. 5

Alternatives to TIFCA6

Cash Basis: - Expensing 7

Accrual Basis: - Normalized Net Salvage Allowance 8

- SFAS No. 143 Fair Value Approach 9

- Net Present Value Approach 10

All of these have, in one form or another, been adopted by certain other state 11

agencies.12

Cash Basis Alternative to TIFCA13

Q. What is the cash basis alternative? 14

A. The cash basis alternative removes non-legal removal costs and 15

dismantlement from the depreciation rate process. It would no longer be 16

charged to accumulated depreciation. The cash basis alternative involves 17

capitalization and/or expensing. As I discussed in my analysis of SCE’s Pole 18

Example, SCE allocates a portion of the cost of a replacement project to cost 19

of removal. The allocation, like all allocations, is at least somewhat arbitrary. 20

Thus, one component of the cash basis alternative would be to consider 21

capitalizing the entire cost of replacements to plant in service, rather than 22

E-22



allocating a portion to cost of removal. This would have the same effect on 1

rate base as the company’s current accounting and would eliminate the 2

problems created by the allocation. It would have the same effect on rate 3

base because the current accounting debits actual cost to accumulated 4

depreciation which increases rate base. 5

Q. What if the company incurs cost of removal or dismantlement which is 6

not accompanied by a replacement? 7

A. If there is not a replacement, under the cash basis alternative the cost of 8

removal and/or dismantlement would be charged to operating expense. 9

Q. Is it necessary, under the cash basis alternative, to have a combination 10

of capitalization and expensing? 11

A. No. SCE could charge all non-legal cost of removal and dismantlement to 12

operating expense. It would be eliminated from depreciation expense and 13

estimated, just as any other operating expense, in a rate case. If there are 14

concerns that SCE or its customers could unduly suffer from an over-or under-15

estimation of this expense, the CPUC could adopt balancing account 16

treatment for the actual recorded expenses, subject to reasonableness review. 17

As shown in Exhibit___(MJM-7), the cost of removal expense based on the 18

average of the last 5 years is $69.1 million per year. 19

Accrual Basis Alternatives to TIFCA20

Q. What are the accrual basis alternatives to TIFCA? 21

E-23



A. There are three accrual basis alternatives to TIFCA: the normalized net 1

salvage allowance approach, the SFAS NO. 143 ARO Fair Value approach, 2

and the net present value approach. 3

Normalized Net Salvage Allowance Accrual Approach4

Q. Please explain the normalized net salvage allowance approach. 5

A. The normalized net salvage allowance approach is similar to the cash basis 6

approach except that the annual average net salvage, which includes cost of 7

removal, is included as a specifically identifiable amount within the annual 8

depreciation accrual. In other words, a normalized net salvage amount is still 9

a component of the depreciation expense accrual and is credited to 10

accumulated depreciation and actual cost of removal continues to be charged 11

to accumulated depreciation.12

Q. Is the annual net salvage accrual a fixed amount? 13

A. The annual net salvage accrual could be either a fixed amount or a rolling five-14

year average amount. In this case, the $54.3 million five-year average net 15

salvage shown in Exhibit___(MJM-7) would be included in the annual 16

depreciation accrual and actual net salvage would continue to be charged to 17

accumulated depreciation. 18

SFAS NO. 143 Fair Value Accrual Approach19

Q. What is the SFAS No. 143 Fair Value Approach? 20

A. The SFAS No. 143 Fair Value Approach treats SCE's non-legal AROs as if 21

they were legal AROs. Exhibit___(MJM-9) contains these calculations. For 22

E-24



mass property, I used SCE’s future net salvage estimates as the future values 1

that would be estimated under SFAS No. 143 and the inflation rate and risk 2

free rates discount and accretion rates which SCE used for its legal AROs. 3

Exhibit___(MJM-9) also includes the initial accounting entries to capitalize the 4

non-legal AROs and begin accretion accounting according to the FERC’s new 5

accounts for those purposes.6

Net Present Value Accrual Approach7

Q. What is the net present value approach? 8

A. The net present value approach is much less complicated than the SFAS No. 9

143 fair value approach. The net present value approach merely discounts 10

SCE’s future cost of removal estimates back to 2003 values using the inflation 11

factor that SCE used for its ARO calculations. Since I am recommending that 12

all of the non-legal ARO be removed from accumulated depreciation, the net 13

present value amounts would form the basis of the cost of removal rates on a 14

remaining life basis. These amounts and rates are calculated on 15

Exhibit___(MJM-10). 16

Recommendations17

Q. What do you recommend? 18

A. I recommend that the regulatory liability resulting from SCE’s collection of 19

excessive non-legal ARO charges be separated from accumulated 20

depreciation and specifically recognized by the CPUC as a regulatory liability 21

for regulatory reporting, regulatory analysis and ratemaking purposes in 22

E-25



California. I recommend that the CPUC consider whether to maintain this 1

regulatory liability as a permanent rate base offset representing customer-2

provided or to amortize it back to ratepayers over some fixed period. In either 3

case, the regulatory liability would remain as a rate base offset until fully 4

amortized.5

On a going-forward basis, I recommend that non-legal ARO recovery be 6

separated from the capital recovery component of depreciation. The capital 7

recovery depreciation rates, reflecting Mr. Pierce’s life and curve requests are 8

shown on Exhibit___(MJM-11). Beyond that, I recommend that TIFCA be 9

discontinued, and that any one of the following approaches be approved: cash 10

basis, normalized net salvage allowance, or net present value basis. I do not 11

recommend the SFAS No. 143 approach because these are not legal AROs 12

and because that method is too complicated. 13

Q. Does this conclude your testimony? 14

A. Yes, it does. 15

E-26

DIRECT TESTIMONY OF WITNESS MICHAEL J. MAJOROS, JR.

ON BEHALF OFTHE UTILITY REFORM NETWORK (TURN)

California Public Utilities Commission

Southern California Edison 2009 General Rate CaseA. 07-11-011

April 2008

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i

TABLE OF CONTENTS

I. Introduction........................................................................................................... 1

II. Purpose of Testimony and Summary of Conclusions ........................................... 3

III. Summary of Adjustments and Structure of Testimony.......................................... 4

IV. General Principles Underlying Depreciation Proposals ........................................ 6

V. Current Depreciation Rates .................................................................................. 9

VI. Edison’s New Depreciation-Related Proposals .................................................. 11

VII. Mr. Fisher’s Cost of Removal Proposals ............................................................ 12

VIII. Accrual Accounting............................................................................................. 17

IX. Suspect Cost of Removal Data........................................................................... 23

X. Removing Inflation – Better Aligning Mr. Fisher’s Approach with Accrual Accounting.......................................................................................................... 25

X. Service Lives ...................................................................................................... 27

XII. Summary of Recommendations ......................................................................... 28

E-28

Southern California Edison – 2009 GRC A. 07-11-011 Direct Testimony of Michael J. Majoros, Jr.

April 2008 Page 1 of 28

I. Introduction1

Q. State your name. 2

A. Michael J. Majoros, Jr. 3

Q. Who is your employer, and what is your position? 4

A. I am Vice President of Snavely King Majoros O’Connor & Bedell, Inc. (“Snavely 5

King”), located at 1111 14th Street, N.W., Suite 300, Washington, D.C. 20005.6

Q. Describe Snavely King. 7

A. Snavely King is a progressive economic consulting firm, founded in 1970 to 8

conduct research on a consulting basis into the rates, revenues, costs and 9

economic performance of regulated firms and industries. Our clients include 10

government agencies, businesses and individuals that purchase public utility, 11

telecom and transportation services.12

In addition to consumer cost and anti-trust issues, we have provided our 13

expertise in support of a clean environment and personal damages resulting from 14

discrimination in agricultural programs. We believe in accountability, fair 15

competition and effective regulation. We seek and use new ideas and we 16

challenge traditional methods based on flawed premises. 17

The firm has a professional staff of 11 economists, accountants, engineers 18

and cost analysts. Most of our work involves the development, preparation and 19

presentation of expert witness testimony before Federal and state regulatory 20

agencies. Over the course of our 38-year history, members of the firm have 21

participated in more than 1,000 proceedings before almost all of the state 22

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commissions and all Federal commissions that regulate utilities or transportation 1

industries2

Q. Have you prepared a summary of your qualifications and experience? 3

A. Yes, I have. Appendix A is a summary of my qualifications and experience. 4

Appendix B is a tabulation of my appearances as an expert witness before state 5

and Federal regulatory agencies. 6

Q. At whose request are you appearing in this proceeding? 7

A. I am appearing at the request of The Utility Reform Network (“TURN”). 8

Q. Did you or someone under your direct supervision prepare your testimony 9

and exhibits? 10

A. I prepared my testimony; my associate and I prepared my exhibits. 11

Q. What is the subject of your testimony? 12

A. My testimony addresses depreciation. 13

Q. Do you have any specific experience in the field of public utility 14

depreciation?15

A. Yes, I do. I and other members of my firm specialize in the field of public utility 16

depreciation. We have appeared as expert witnesses on this subject before the 17

regulatory commissions of almost every state in the country. I have testified in 18

over 100 proceedings on the subject of public utility depreciation. 19

Q. Have you testified previously before the California Public Utilities 20

Commission (“CPUC”)? 21

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A. Yes, I submitted testimony to the CPUC in Southern California Edison’s 2006 1

GRC A.04-12-014, Pacific Gas and Electric Company’s 2007 GRC No. A.05-12-2

002, and the combined 2008 GRC for San Diego Gas and Electric Company (A. 3

06-12-009) and Southern California Gas Company GRC (A. 06-12-010). 4

II. Purpose of Testimony and Summary of Conclusions5

Q. Please explain the purpose of your testimony. 6

A. My testimony responds to the direct testimony submitted by Richard Fisher on 7

behalf of Southern California Edison Company (“SCE,” “Edison’” or “the 8

Company”). My client originally asked me to review Mr. Fisher’s testimony and 9

exhibits. I am to express an opinion regarding the reasonableness of Mr. 10

Fisher’s proposals and, if warranted, make alternative recommendations. Later, 11

though, TURN and I determined to limit the scope of my prepared testimony to 12

focus on treatment of future inflation in current depreciation rates.13

Q. Has Mr. Fisher proposed a change in the depreciation expense component 14

of the Company’s revenue requirement? 15

A. Yes, Mr. Fisher conducted depreciation studies based on December 31, 2006 16

plant balances. The studies result in a $92.8 million depreciation expense 17

increase for SCE.118

Q. Have you reached a conclusion regarding Mr. Fisher’s proposed change in 19

depreciation rates and expense? 20

1 Based on 12/31/2006 plant balances and recorded expense. See TURN calculation included in

Exhibit___(MJM-2). Based on SCE’s calculation, the proposed rate changes account for $75 million of the $370 million increase to TY 2009 depreciation expense. See SCE-11, Vol. 2, p. 25, Table II-5.

E-31



A. My conclusion is that SCE’s proposed depreciation expense for its 2009 test 1

year is too high. Edison’s depreciation expense should be reduced by $106.5 2

million based on December 31, 2006 plant balances. The adjustment would be 3

higher when calculated using December 31, 2008 plant balances. 4

III. Summary of Adjustments and Structure of Testimony5

Q. What adjustments are you proposing to make to the Company’s calculation 6

of depreciation expense? 7

A. I am proposing one adjustment which stems from the fundamental fact that: In 8

2009, the future removal costs to be collected in rates for the assets providing 9

service in 2009 should reflect the impact of inflation incurred in 2009, but not 10

2019, 2029 or 2039 inflation. The approach set forth in the Company’s 11

depreciation study leads it to over-recover from current ratepayers and under-12

recover from future ratepayers, amounts associated with the future cost of 13

removal of retired plant. In other words, Mr. Fisher’s approach results in an 14

intergenerational inequity. 15

Specifically, the amounts Mr. Fisher’s includes in current rates to fund the 16

future removal of retired plant do not properly match future inflation to the periods 17

it will be incurred. Instead, Mr. Fisher front-loads recovery of future inflation 18

expense such the current ratepayers are overcharged and future ratepayers are 19

undercharged, thus leading to a substantial intergenerational inequity. This 20

approach leads to excessive depreciation expense and the accumulation of 21

excessive depreciation reserves. 22

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My adjustment more appropriately matches the timing of inflation costs 1

with the period in which the related service is provided. I do so by eliminating 2

future inflation from the cost of removal component of Mr. Fisher’s current 3

depreciation rates, and charging it to the future years in which it is incurred. This 4

approach constitutes the matching assumed by accrual accounting and the 5

ratemaking concept of intergenerational equity. 6

Q. Isn’t this a more limited range of recommendations than you have made for 7

TURN in past CPUC proceedings? 8

A. Yes. There are a number of problems with the depreciation rates Edison 9

proposes in this case, and I had originally intended to address more of those 10

problems in my prepared testimony. In past cases, TURN has also relied on 11

cross-examination and hearing exhibits to develop the evidentiary record about 12

some of the problems with a utility’s proposed or existing depreciation rates, and 13

I expect that will occur again in this proceeding. 14

However, the 600-pound gorilla in the room is the inclusion of future 15

inflation costs in the depreciation rates that will be approved in the 2009 test 16

year. In order to increase the chances that the Commission will directly address 17

this critical issue, TURN has decided to limit the scope of its prepared testimony 18

on depreciation to this single subject, with a single recommendation.19

Q. How is your testimony structured? 20

A. I begin by discussing a few depreciation-related general principles that I believe 21

are not reasonably subject to dispute, but might get confused if not directly 22

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addressed. I then provide some background regarding the genesis of the 1

Company’s current depreciation rates. I summarize SCE’s proposed depreciation 2

rates. Next, I discuss my single adjustment. I explain why Mr. Fisher’s current 3

method of estimating the future cost of removing retired plant predictably front-4

loads those costs and how to adjust his resulting proposals to remove such front-5

loading.6

IV. General Principles Underlying Depreciation Proposals 7

Q. What sort of general principles do you have in mind that you wish to 8

explicitly identify and address? 9

A. There are several. First, depreciation rates are largely set based on forecasts of 10

future costs of removal that are highly suspect under the best of circumstances. 11

There is great uncertainty caused by the fact that these costs will not be incurred 12

until the plant is removed from service. The expected remaining life of the plant 13

is a forecast, the accuracy of which will not be known until the plant is removed 14

years or decades from now. The cost of removing that plant when the remaining 15

life actually ends is a similarly forecast of costs from far off in the future. If 16

Edison’s GRC is like a typical GRC, there will be substantial differences of 17

opinion over the appropriateness of forecasts of costs that will be incurred only a 18

year or two in the future. It is hard to imagine that the forecasts of removal costs 19

that will be incurred many years after the test year could be any more accurate 20

than the forecasts of costs that will actually arise during this rate case cycle. It 21

does not increase the comfort in these forecasts when the amount Edison claims 22

E-34



to have retired in the past fifteen years represents a very small proportion of the 1

total plant in service today.2

Second, as the Commission correctly recognized in PG&E’s 1999 Test 3

Year GRC, “depreciation does not affect PG&E’s ability to provide safe and 4

reliable service. Even if the proposed or current rates of depreciation are 5

reduced, shareholders will still recover their investments in plant over time.” 6

D.00-02-046 (5 Cal PUC 3d 315, 479). 7

Third, the terms “matching” and “intergenerational equity” (or inequity) 8

often arise in discussions of utility depreciation practices and rates. “Matching” 9

refers to matching costs to the periods in which they are incurred. Mr. Fisher 10

describes the “matching principle” as requiring that each expense item related to 11

revenue earned be recorded in the same accounting period as the revenue it 12

helped to earn.” SCE-11, Vol. 3, p. 2, fn. 2. 13

Intergenerational equity is similar to matching, as it encourages the 14

Commission to assign costs of providing utility service to the same “generation” 15

of ratepayers that benefited from that utility service. In depreciation discussions, 16

intergenerational equity means that the customers who took service while a plant 17

was in service pay the costs associated with that plant, including the cost of 18

removing the plant from service when it reaches the end of its useful life. 19

Assume a piece of equipment that will be in service for ten years – 20

intergenerational equity is achieved if the total costs associated with that plant, 21

including removal costs at the end of its life, are collected from ratepayers during 22

E-35



the decade the plant is in service, rather than from those taking service before or 1

after that decade. For purposes of assessing an intergenerational equity 2

argument, then, the Commission needs to know what “generation” the party has 3

in mind. The test year for a GRC, or even the entire three-year period covered 4

by the GRC-authorized revenue requirement could be viewed as a “generation.” 5

A cost recovery pattern that appears to achieve intergenerational equity from the 6

perspective of a ten-year “generation” of utility ratepayers (that is, those taking 7

service while a particular piece of equipment is in service) may not be equitable 8

when viewed from the perspective of customers who take service early during 9

that generation, yet bear costs that will not arise until much later in the ten-year 10

period.11

A third important concept is “straight-line recovery.” The concept begs the 12

question “straight-line of what?” To illustrate, assume that the Commission 13

adopts a forecast saying Edison will need to collect $10,000 between 2009 and 14

2018 to cover the net salvage costs for plant it expects will leave service in 2018. 15

Edison contends that straight-line recovery must be achieved in nominal dollar 16

amounts, that is, by collecting $1,000 per year for ten years. TURN’s position is 17

that the Commission should use “real” dollars (that is, inflation-adjusted dollars) 18

to achieve straight-line recovery. The same amount in real dollars is recovered 19

in each of the ten years, but the nominal dollars vary to match inflation for each 20

year (and are paid in dollars subject to that same level of inflation). At the end of 21

the ten-year period, the same amount of nominal dollars is recovered under each 22

E-36



of the two approaches. So any assertion that an approach achieves “straight-line 1

recovery” needs to be greeted with the inquiry “in terms of nominal or real 2

dollars?”3

V. Current Depreciation Rates4

Q. When did the CPUC approve SCE’s currently authorized depreciation 5

rates?6

A. The CPUC approved SCE’s current depreciation rates in its May 11, 2006 7

Decision No. D.06-05-016, relating to the Company’s 2006 General Rate Case.28

Q. Were you a participant in that case? 9

A. Yes, I submitted testimony on behalf of TURN. 10

Q. Please summarize your recommendations in that case. 11

A. In SCE’s 2006 GRC, A.04-12-014, I recommended that the regulatory liability 12

resulting from SCE’s collection of excessive cost of removal charges be 13

separated from accumulated depreciation and specifically recognized by the 14

CPUC as a regulatory liability for regulatory reporting, regulatory analysis and 15

ratemaking purposes in California. I also recommended that the CPUC consider 16

whether to maintain this regulatory liability as a permanent rate base offset 17

representing customer-provided capital or to amortize it back to ratepayers over 18

some fixed period. On a going-forward basis, I recommended that cost of 19

removal recovery be separated from the capital recovery component of 20

depreciation. I further recommended that the Company’s method of estimating 21

2 SCE-11, Vol. 3, page 12.

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future cost of removal, particularly its treatment of future inflation, be 1

discontinued, and one of the following approaches be approved instead: cash 2

basis, normalized net salvage allowance, or net present value basis. I did not 3

devote substantial time to reviewing SCE’s plant life proposals and therefore did 4

not recommend any changes to those proposals. 5

Q. What was the outcome? 6

A. The Commission agreed with my recommendation to recognize the cost of 7

removal regulatory liability, stating: “TURN’s request that the balance of funds 8

collected for cost of removal related to non-ARO assets be recognized as a 9

regulatory liability for ratemaking purposes is reasonable.”310

The Commission declined to adopt any of my going-forward net salvage 11

recommendations, stating that “there is insufficient evidence to support the 12

adoption of TURN’s net present value methodology for determining costs of 13

removal.”4 However, it embraced many of the points underlying TURN’s 14

recommendations: inflation is the primary reason for the significant increases in 15

historic and projected costs of removal, and variations in assumed inflation over 16

a plant asset’s life could substantially affect the cost of removal accrual over that 17

time period. It also noted that the established cost of removal methodology 18

would cause the cost of removal reserve to continue to grow beyond what had 19

been then been a reserve of $2.112 billion.520

3 Decision No. D.06-05-016, issued May 11, 2006, p. 365 4 Id., p. 366. 5 Id.

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The CPUC, however, opted for what it described as a conservative 1

approach in adjusting net salvage collections, and with the exception of accounts 2

364 and 369 adopted DRA’s recommendations which were based on a 15-year 3

historical average. For account 364 it adopted SCE’s compromise proposal of -4

190% (changed from the initially proposed -250%) and for account 369 it adopted 5

DRA’s recommendation to cap the net salvage rate at -75%.6 The CPUC’s 6

decision resulted in a $141.4 million reduction of depreciation expense from 7

SCE’s requested $934.8 million to $793.4 million.78

VI. Edison’s New Depreciation-Related Proposals9

Q. Please describe Mr. Fisher’s new depreciation proposals. 10

A. Mr. Fisher conducted statistical life studies to support his life and retirement 11

pattern recommendations for each account. Based on his analysis, he opted not 12

to propose any changes to the lives authorized in D.06-05-016.8 He also 13

conducted a “traditional” historical net salvage analysis to estimate future net 14

salvage ratios for each account, similar to the analysis SCE presented in its last 15

GRC. In this case, Mr. Fisher has increased his net salvage collections for 16

twelve of the 18 transmission and distribution accounts (Account 352-369), 17

including most of the accounts with substantial amounts of recorded plant.18

In addition, Mr. Fisher has proposed to amortize the remaining costs of 19

certain soon-to-be retired assets over their current authorized remaining lives. 20

6 Id. 7 Id., p. 185 and 379. 8 SCE-11, Vol. 3, p. 24. Note that for some amortized accounts he is proposing a life change. (p. 57)

E-39



These assets include meters replaced by Edison SmartConnect, capitalized 1

software replaced by SCE’s ERP project, and the remaining net investment of 2

the Mohave Generating Station.93

Q. Do you agree with Mr. Fisher’s new proposals? 4

A. No, Mr. Fisher’s cost of removal proposals produce depreciation rates that are 5

too high and result in excessive charges to current ratepayers because they do 6

not properly match future inflation expense to the periods in which that inflation 7

expense will be incurred. 8

VII. Mr. Fisher’s Cost of Removal Proposals9

10Q. Please explain what is meant by “cost of removal.” 11

A. The cost of providing utility service includes not only the costs of installing and 12

operating utility plant, but also removing that plant where appropriate at the end 13

of its useful life. Therefore, one of the components of a public utility depreciation 14

rate is a current estimate of future cost of removal (or negative net salvage).1015

9 Id., pp. 23-24. 10 As Edison’s depreciation study describes, the amount to be depreciated is the difference between the

original cost of the plant and the “net salvage.” SCE-11, Vol. 3, p. 68. Standard Practice U-4 illustrates “net salvage” as a positive figure, which occurs when the gross salvage value from a plant’s retirement exceeds the costs of removing the plant. As Edison notes, “In recent year removal cost has generally exceeded the gross salvage resulting in a negative net salvage,” which has the effect of increasing depreciation rates (as compared to a positive net salvage). In today’s ratemaking world, the costs of removal are a far bigger driver of the ultimate depreciation rate than the gross salvage. Therefore, I tend to describe the issue as a matter of appropriately dealing with future costs of removal. However, this is not intended to exclude similar treatment of future gross salvage values unless I specifically note that there is a reason to treat the two forecasts of future values differently.

E-40



This estimate is typically expressed as a ratio (derived from historical 1

data), that is applied to the current plant balance to provide an estimate of the 2

future cost of removal. This future cost is, in turn, charged to depreciation 3

expense on a straight-line basis over the remaining life of the plant, just as the 4

depreciation of plant investment is charged to expense. A cost of removal ratio 5

increases the overall depreciable cost base because it allocates a portion of the 6

estimated future removal cost to each year of the asset’s service life. This 7

process is, by definition, accrual accounting. 8

Q. Do you object to this process? 9

A. No, I do not object to this process if properly applied. In past cases I have 10

proposed that the Commission adopt an approach that is closer to expensing 11

current removal costs due to concerns about the accrual approach the California 12

utilities have taken. However, the Commission has made it clear it prefers an 13

accrual accounting approach, that is, one that recovers future removal costs 14

during the period the plant is in service. “Expensing” arguably defers all such 15

recovery until after the plant is removed from service. Just as important, though, 16

was the Commission’s recognition that there is a problem with future inflation in 17

cost of removal estimates. The GRC decision indicated that TURN had not 18

provided sufficient evidence to support the adoption of the net present value 19

alternative I offered in that proceeding. 20

Q. If you are not raising any objection to the general process of forecasting 21

future costs of removal or net salvage, what does your testimony address 22

E-41



and how is it different than what the utility proposes? 1

A. My testimony focuses on providing the Commission with whatever information it 2

believes it needs to address the inflation issue. To that end, my discussion 3

addresses accrual accounting, matching and intergenerational equity principles. 4

I provide a simple and straight-forward example demonstrating that the present 5

value approach is the approach most consistent with these principles because it 6

properly matches inflation expense to the periods incurred and eliminates the 7

intergenerational inequity inherent in Mr. Fisher’s approach. I do not propose 8

any variation on “expensing” or normalizing removal costs. Accepting Mr. 9

Fisher’s future cost of removal proposals at face value, I merely express them at 10

their present value so current ratepayers will not be charged for future inflation 11

that has not been incurred.12

In other words, for plant in service today that will likely be removed from 13

service twenty years from now, both TURN’s approach and Edison’s approach 14

would recover the same total amounts. TURN’s approach would achieve the 15

same straight-line pattern as Edison’s approach for recovery of the original plant 16

investment, and for recovery of the inflation-adjusted amount for the net salvage 17

costs that will be incurred in 2029. The only difference is the cost recovery 18

pattern for the future inflation costs; TURN would have the annual amounts 19

increase during the twenty-year period to reflect the effects of inflation (and 20

permit Edison customers to pay in inflated dollars), while Edison would allocate 21

the future inflation costs on a straight-line basis, an outcome that assigns a 22

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disproportionate share of those costs to current ratepayers.1

As the CPUC recognized in its prior Order, SCE’s regulatory liability for its 2

over-recovery of future cost of removal continues to grow. In SCE’s 2006 GRC, 3

the regulatory liability was $2.112 billion (as of 2004), now it is $2.230 billion.114

The $118 million increase is real money collected from ratepayers for cost of 5

removal over and above SCE’s actual expenditures for cost of removal just since 6

its last GRC. 7

Q. Are you challenging any of Mr. Fisher’s proposed lives? 8

A. No, I am not challenging any of Mr. Fisher’s proposed lives, even though I 9

believe several of them may be understated. I think it is more important at this 10

juncture to focus the Commission’s attention on how Edison’s approach treats 11

future inflation costs, and how a change to this treatment can achieve a far more 12

equitable outcome that is consistent with the matching principle, minimizes 13

intergenerational inequity, and has the added advantage of lowering the utility’s 14

depreciation rates by $106.5 million.12 15

Q. How did Mr. Fisher arrive at his net salvage or future cost of removal 16

proposals?17

A. As I mentioned above, Mr. Fisher has conducted a “traditional” historical net 18

salvage analysis to estimate future net salvage ratios for each account. This is 19

the same sort of analysis that SCE presented, and I objected to, in the 2006 20

11 Response to DRA-SCE-225-BEN #1. Note that 2007 amount reflects removal of $48.1 million in FIN-

47 ARO amounts that were not removed from the 2004 amount. 12 Based on 12/31/2006 plant balances and recorded expense – see Exhibit___(MJM-2), pages 10 – 13.

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GRC.1

Q. Why do you object to Mr. Fisher’s traditional approach? 2

A. Mr. Fisher’s approach is front-loaded in its treatment of future inflation costs. It 3

increases the current estimate of future costs of removal for a substantial amount 4

of future inflation. In other words, Mr. Fisher’s approach charges current 5

ratepayers on an undiscounted basis for future inflation. Mr. Fisher justifies this 6

approach by claiming that charging current ratepayers for un-incurred future 7

inflation is “accrual accounting.” I disagree. Accrual accounting consists of 8

matching costs to the periods in which they are incurred. Mr. Fisher’s approach 9

fails that fundamental test by front loading future inflation. That is why GAAP 10

specifically precludes his approach.11

Q. Why does Mr. Fisher’s approach result in inflated future cost of removal 12

estimates?13

A. Mr. Fisher bases his approach on the relationship of current cost of removal 14

expenditures in today’s dollars versus the original cost of the plant being retired, 15

calculating a ratio of current cost of removal (in today’s dollars) to original cost of 16

plant (in historical dollars). A substantial part of the current cost of removal 17

represents past inflation experienced during the period (often decades) between 18

when the plant was first put in service and when the removal costs were incurred. 19

He then applies that ratio to today’s plant balances to project the future cost of 20

removal. In this way, the calculation extrapolates into the future all of the past 21

inflation rather than the small portion actually experienced during the test year 22

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2009.1

Q. Does Mr. Fisher agree that his approach compares historical plant 2

retirement dollars with current cost of removal and gross salvage dollars 3

and thus results in an estimate which incorporates an assumed level of 4

future inflation? 5

A. Yes, he does agree.136

Q. What is the effect of Mr. Fisher’s approach? 7

A. Mr. Fisher’s inflated future cost of removal rates result in a $327.8 million annual 8

charge for future costs of removal versus the $166.7 million SCE incurs on 9

average.14 This type of difference is largely responsible for the $2.230 billion 10

cost of removal regulatory liability, which has increased by $118 million in the 11

time since the SCE’s 2006 GRC. In other words, SCE is reporting a regulatory 12

liability for the amounts collected but not yet spent on future cost of removal 13

activities that has grown $118 million since the Commission last reviewed the 14

issue. In other words, just since that last GRC, SCE has collected $118 million 15

more from rate payers than it has spent on actual cost of removal. This growth is 16

almost entirely attributable to future inflation costs. 17

VIII. Accrual Accounting18

Q. What is accrual accounting? 19

A. Accrual accounting recognizes or matches revenue to the periods earned and 20

13 “[V]ariation in retirement age can have a significant effect on net salvage ratios as a result of . . . the

effects of inflation on removal cost.” SCE-11, Vol. 3, p. 78. See also page 86.

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expenses to the periods incurred. Accrual accounting is the foundation of 1

generally accepted accounting principles (“GAAP”). The directives issued by the 2

Financial Accounting Standards Board (FASB), such as SFAS No. 143 and FIN 3

47 referred to in Edison’s depreciation study (pp. 70-72), set forth GAAP.4

Q. What is cash basis accounting? 5

A. Cash basis accounting recognizes revenues and expenses when received or 6

disbursed rather than when earned or incurred. 7

Q. Does Mr. Fisher’s approach constitute accrual accounting? 8

A. I do not believe it does, at least to the extent it charges current ratepayers the 9

costs of inflation that may not be incurred for years or even decades. An 10

approach more consistent with accrual accounting would match those future 11

inflation costs to the ratepayers taking utility service at the time the inflation is 12

incurred. Mr. Fisher’s approach does not match inflation costs to the periods 13

incurred.14

Q. Do the relatively recent pronouncements of the Financial Accounting 15

Standards Board provide any useful guidance on these questions? 16

A. I believe they do, even if the questions are arising here in a ratemaking 17

proceeding and the FASB pronouncements apply most directly to financial 18

reporting requirements. But the underlying principles of achieving appropriate 19

“matching” through accrual accounting do not change whether they arise in a 20

14 See Q.01 REV Att_SCE11_V3_ChV_pp_9_11 REV.xls for Fisher calculation (Grand Total line,

adjusted to reflect all Mountainview). See “DRA-SCE-234-BEN Q.1 Attachment_COR 2005-2007-1.xls” for incurred COR for 2005-2007.

E-46



ratemaking or financial reporting setting.1

Mr. Fisher is no doubt familiar with the accounting prescribed in SFAS No. 2

143 and FIN 47, which constitute GAAP. After all, he refers to them specifically 3

in his depreciation study (pp. 70-72). SFAS No. 143 was adopted to establish 4

accounting standards for recognition and measurement of a liability for an asset 5

retirement obligation and any associated asset retirement cost. (SFAS No. 143, 6

¶ 1.) For financial reporting purposes, Edison now estimates the “fair value” of its 7

estimated future retirement costs. SFAS 143 provides that where there are no 8

quoted market prices to use for such estimating purposes, a “present value” 9

technique is often the best available substitute. (SFAS No. 143, ¶ 8.) This 10

present value technique prescribed in SFAS 143 directs the discounting of the 11

estimated future cash flows using “credit-adjusted risk-free rate.”12

Edison is already arguing that the Commission should not rely on SFAS 13

No. 143 or FIN 47 for purposes of deciding ratemaking issues, even going so far 14

as to claim that “[t]he goals of ratemaking and those of FAS 143 are not 15

congruent.” SCE-11, Vol. 3, p. 72. For purposes of deciding what approach is 16

most consistent with principles of accrual accounting, however, TURN submits 17

there is no better source than FAS 143 and the other FASB pronouncements that 18

are, after all, the embodiment of GAAP. Edison begins its depreciation study 19

with a favorable reference to GAAP and, in particular, the “matching principle” 20

E-47



that Edison asserts is embodied in GAAP.15 And under FAS 143, companies are 1

not required to report the absolute future value of removal costs, but rather a 2

“present value” of those future costs. For financial reporting purposes, this better 3

enables investors to assess a company’s future asset retirement obligations, as 4

Edison says. (Id.) For ratemaking, it serves a different purpose – using a 5

present value calculation of the future costs of removal ensures that the future 6

removal cost expenditure is measured in a way that achieves a fair revenue 7

requirement to charge customers “during an accounting period.” Id. TURN’s 8

approach treats the test year as the relevant “accounting period” Edison’s 9

testimony refers to. 10

It’s important to be clear about this. Edison and the other utilities have in 11

the past characterized TURN’s approach as seeking to have the Commission 12

adopt FAS 143 for ratemaking purposes when, in fact, it was adopted for 13

financial reporting purposes. TURN is not asking the Commission to adopt FAS 14

143 for ratemaking purposes. However, for purposes of developing an 15

appropriate estimate of the amount of future removal costs to include in today’s 16

rates, the underlying principle is consistency with accrual accounting as set forth 17

in GAAP (of which FAS 143 is a part), whether the estimate is to be used for 18

financial reporting purposes or for establishing a reasonable rate under cost-of-19

service ratemaking. The amount that should be charged to the “accounting 20

15 SCE-11, Vol. 3, p. 2. According to Edison, “The matching principle states that each expense item

related to revenue earned must be recorded in the same accounting period as the revenue it helped to earn.”

E-48



period” is an appropriate share of the present value of the future obligation. The 1

Commission may choose to use something other than the “credit-adjusted risk-2

free rate” described in FAS No. 143 for calculating the present value of the future 3

obligation. But the underlying principle of accrual accounting remains -- “proper 4

depreciation principles are concerned with measuring . . . the future removal cost 5

expenditure used during an accounting period for purposes of determining a fair 6

revenue requirement to charge customers,”16 In ratemaking, the accounting 7

period is the test year, not the remaining life of the plant.8

Q. Can you demonstrate that using the present value approach constitutes 9

accrual accounting and that Mr. Fisher’s approach does not constitute 10

accrual accounting? 11

A. Yes. Exhibit___ (MJM-1) is a chart I designed to demonstrate those facts. It is a 12

simple single asset example comparing Mr. Fisher’s approach to collecting future 13

inflation versus the present value accrual approach. As you can see, both Mr. 14

Fisher’s approach and the present value approach accumulate the same total 15

amount for future removal costs by the end of the asset’s life. The difference is 16

the rate of collection for future inflation costs. My present value approach 17

matches inflation to the periods incurred. Mr. Fisher’s approach front-loads 18

future inflation costs into current periods, and by doing so overcharges 19

ratepayers in the early years and undercharges ratepayers in the later years. 20

This flies in the face of the “intergenerational equity” and accrual accounting 21

16 SCE-11, Vol. 3, p. 72.

E-49



concepts; it stands them on their heads. The front-loading element of this 1

approach is also why SCE reports a $2.230 billion regulatory liability for GAAP 2

purposes.3

Q. Is this example intended to show rate base effects? 4

A. No, the example demonstrates that accrual accounting matches inflation to the 5

periods incurred. Rate base is irrelevant to that demonstration. 6

Q. Is there any economic rationale that supports matching future inflation to 7

the periods incurred?8

A. Yes, the inflation-related portion of the future removal cost will be paid for with 9

cheaper dollars in future years. In terms of nominal dollars, the amount paid 10

appears higher, but in real (that is, inflation-adjusted) dollars, the same amount is 11

paid now and in the future, all else equal. When it comes to future inflation costs, 12

“straight-line” recovery should be measured in real dollars, not nominal dollars. 13

Q. Is Mr. Fisher’s approach required under the Uniform System of Accounts 14

(“USoA”)?15

A. No, nothing in the USoA requires depreciation rates to be based on inflated 16

future costs, or to collect from today’s ratepayers the costs of inflation that will not 17

be experienced for years or even decades to come.18

Q. Is Mr. Fisher’s approach required under the Standard Practice U-4? 19

A. No, nothing in SP U-4 explicitly requires depreciation rates based on inflated 20

future costs. The utilities have in past GRCs pointed to certain tables and argued 21

that the calculations set forth therein use nominal dollars and, therefore, should 22

E-50



be interpreted to mean that SP U-4 intended to use nominal rather than real 1

dollars for its calculations. This is conjecture at best. 2

Q. Have ratepayers been harmed by Mr. Fisher’s approach? 3

A. Yes. SCE’s ratepayers have to date paid SCE $2.230 billion more than the 4

Company’s actual cost of removal and cost of removal requirements, with a 5

substantial portion of that amount representing inflation costs that will not be 6

incurred for years or decades to come.7

IX. Suspect Cost of Removal Data8

Q. Is there any correlation between cost of removal and retirements? 9

A. There is little, if any, relationship between the cost of removal and retirements 10

amounts in Mr. Fisher’s net salvage studies.11

Q. Why is there little or no relationship between the cost of removal and the 12

retirement amounts in Mr. Fisher’s studies? 13

A. A majority of SCE’s retirements result from replacements. The Company 14

determines a need to replace assets in conjunction with its obligation to provide 15

service. When it is determined that assets should be replaced, the Company 16

estimates the entire replacement cost, and then assigns a portion of the 17

replacement cost to cost of removal. The cost of removal in Mr. Fisher’s studies 18

is a function of and derived directly from plant additions - not retirements.19

Most of the retirements in the studies are priced and posted as after-the-20

fact accounting entries, bearing little if any relationship at all to the recorded cost 21

of removal, because the amount treated as “cost of removal” is merely an 22

E-51



allocation of some portion of the total addition/replacement cost. It is doubtful 1

that the cost of removal in any given year relates in any way to the retirements 2

recorded in that year.3

Q. Are there any other reasons why the cost of removal bears little 4

relationship to retirements in Mr. Fisher’s studies? 5

A. Not only is the data sporadic in many instances, i.e., significant gaps between 6

entries, it is also subject to the control of the accounting department. Changes in 7

accounting policies and procedures can affect retirement and cost of removal 8

reporting, even if there are no changes in the way plant is actually retired or 9

removed. As I explained, significant portions of the recorded cost of removal 10

result from accounting assignments and allocations. Such assignments and 11

allocations are at least somewhat arbitrary. Consequently, it is reasonable to 12

assume that two independent estimators reviewing the same project could reach 13

different conclusions concerning the portion of a replacement project to be 14

assigned to cost of removal. 15

Q. Do you consider the amounts in Mr. Fisher’s studies to be inaccurate? 16

A. I assume SCE has accurately recorded the amounts. However, accurately 17

recorded amounts can produce inaccurate results where, for example, two 18

figures bear little relationship to each other and they are stated in mismatched 19

dollars. Mr. Fisher’s study’s comparison of the cost of removal to retirements is 20

an example of such a comparison of otherwise accurately recorded figures that 21

can produce inaccurate results. 22

E-52



X. Removing Inflation – Better Aligning Mr. Fisher’s Approach with Accrual 1

Accounting2

Q. What adjustment is necessary to correct the flaw resulting from the 3

mismatch of current removal dollars to historical retirement dollars? 4

A. In order to develop the current dollars needed to cover the future cost of removal, 5

it is necessary to calculate the present value of Mr. Fisher’s estimated future 6

costs. The estimated future costs should be discounted to their present value 7

using Mr. Fisher’s proposed remaining lives and a reasonable estimate of the 8

future inflation incorporated into his estimates. 9

Q. Would discounting Mr. Fisher’s cost of removal proposals back to present 10

value better align his proposals with accrual accounting? 11

A. Yes, it would. Ratepayers in 2009 would bear the costs of 2009 inflation, but not 12

inflation costs that will not be incurred until 2019, 2029, or even further into the 13

future.14

Q. What do you recommend? 15

A. I recommend discounting all of Mr. Fisher’s inflated future cost of removal 16

estimates to their present values. 17

Q. Did Mr. Fisher include any legitimate present value estimates in his 18

exhibits?19

A. In response to the Commission’s directives in the last GRC to make a showing 20

on the impact of inflation in Edison’s depreciation rates, Mr. Fisher included 21

certain alternative calculations in his workpapers. Mr. Fisher’s alternative 22

E-53



calculations are so bogus that they are an insult to the intelligence of the 1

Commission and every other party to this proceeding. His calculations include 2

estimates of prior addition amounts that are almost twice the amount of actual 3

past additions. His calculations show a fifteen-year cost of removal amount 4

without inflation that is more than the actual fifteen-year amount (which includes 5

substantial inflation). His calculations inflate prior cost of removal amounts that 6

already include inflation. Mr. Fisher’s alternative calculations add nothing that 7

might help the Commission analyze the impact of inflation on future net salvage 8

costs.179

Q. Have you properly calculated future net salvage ratios on a present value 10

basis?11

A. Yes, Exhibit MJM___(MJM-2) contains those calculations. I removed the 12

inflation from each of Mr. Fisher’s estimates. Using the Handy-Whitman Index 13

for the Pacific Region, I measured the inflation incurred from 1992 to 2006, i.e., 14

the 15 years Mr. Fisher included in his net salvage studies. I used the Handy 15

Whitman indication to discount his proposals. 16

Q. How does TURN propose to treat inflation that will occur between now and 17

the next time the Commission reviews SCE’s depreciation rates? 18

17 In D.06-05-016 (Conclusion of Law 34), the Commission directed SCE to include “in its next GRC . . .

as part of its account-by-account analysis, [an analysis of] the effects of past inflation on its proposed cost of removal rates and justify the implicit inflation rates reflected in its proposed rates.” It’s not clear from Edison’s depreciation study what conclusions it is asking the Commission to draw regarding “the effects of past inflation on its proposed cost of removal rates.”

E-54



A. Given the over-collected status of the Company’s regulatory liability for cost of 1

removal, the Commission could determine that no such adjustment is necessary 2

and any shortfall in the amounts collected in the next few years is already more 3

than covered by the existing reserves.4

However, if the Commission wishes to make an adjustment to reflect 5

current inflation it could do so quite easily. My understanding is that SCE files 6

depreciation schedules with the Commission on an annual basis. The 7

Commission could direct that those schedules reflect an increase consistent with 8

current inflation, and the inflation adjustment would be made annually between 9

rate cases. Edison has long demonstrated their ability to make attrition and other 10

annual wide-reaching adjustments. I am confident that they could make a similar 11

across-the-Commission adjustment to their depreciation rates in order to reflect 12

annual inflation, should the Commission choose to go that route. While this 13

might increase the costs to ratepayers each year, the increase would be 14

appropriate so long as it matches the actual inflation expected to be incurred 15

each year.16

X. Service Lives17

Q. Have you reviewed Mr. Fisher’s proposed service lives and curves? 18

A. Yes, I have. I reviewed all of Mr. Fisher’s life studies and his responses to my 19

data requests to determine if his proposed lives were reasonable, given the 20

SCE’s experience.21

Q. Do you agree with his proposed lives? 22

E-55



A. As I stated, I believe several of those lives are understated, but I am not 1

challenging them in prepared testimony. TURN may well choose to raise 2

challenges based on the full evidentiary record once hearings conclude. 3

XII. Summary of Recommendations4

Q. Have you prepared a summary of your recommendations? 5

A. Yes. Exhibit___(MJM-2) shows the calculation of my recommended 6

depreciation rates and expense. My recommended depreciation expense based 7

on plant balances as of December 31, 2006 is $720.3 million, or $106.5 million 8

less than the Company’s 2006 recorded depreciation expense of $826.9 million. 9

Using SCE’s 2009 weighted average plant balances, my recommended 2009 10

depreciation expense is $853.5 million, $272.1 million less than SCE’s proposed 11

2009 accrual of $1,126 million.1812

Q. Does this conclude your testimony? 13

A. Yes, it does. 14

18 See Exhibit___(MJM-2), pages 14-17 and SCE 11, Vol. 2, page 28, Table II-6.

E-56

Michael J. Majoros, Jr. Appendix A - Page 1 of 1

Experience

Snavely King Majoros O’Connor & Lee, Inc. Vice President and Treasurer (1988 to Present)Senior Consultant (1981-1987)

Mr. Majoros provides consultation specializing in accounting, financial, and management issues. He has testified as an expert witness or negotiated on behalf` of clients in more than one hundred thirty regulatory federal and state regulatory proceedings involving telephone, electric, gas, water, and sewerage companies. His testimony has encompassed a wide array of complex issues including taxation, divestiture accounting, revenue requirements, rate base, nuclear decommissioning, plant lives, and capital recovery. Mr. Majoros has also provided consultation to the U.S. Department of Justice and appeared before the U.S. EPA and the Maryland State Legislature on matters regarding the accounting and plant life effects of electric plant modifications and the financial capacity of public utilities to finance environmental controls. He has estimated economic damages suffered by black farmers in discrimination suits.

Van Scoyoc & Wiskup, Inc., Consultant (1978-1981)

Mr. Majoros conducted and assisted in various management and regulatory consulting projects in the public utility field, including preparation of electric system load projections for a group of municipally and cooperatively owned electric systems; preparation of a system of accounts and reporting of gas and oil pipelines to be used by a state regulatory commission; accounting system analysis and design for rate proceedings involving electric, gas, and telephone utilities. Mr. Majoros provided onsite management accounting and controllership assistance to a municipal electric and water utility. Mr. Majoros also assisted in an antitrust proceeding involving a major electric utility. He submitted expert testimony in FERC Docket No. RP79-12 (El Paso Natural Gas Company), and he co-authored a study entitled Analysis of Staff Study on Comprehensive Tax Normalization that was submitted to FERC in Docket No. RM 80-42.

Handling Equipment Sales Company, Inc. Controller/Treasurer (1976-1978)

Mr. Majoros' responsibilities included financial management, general accounting and reporting, and income taxes.

Ernst & Ernst, Auditor (1973-1976)

Mr. Majoros was a member of the audit staff where his responsibilities included auditing, supervision, business systems analysis, report preparation, and corporate income taxes.

University of Baltimore - (1971-1973)

Mr. Majoros was a full-time student in the School of Business.

During this period Mr. Majoros worked consistently on a part- time basis in the following positions: Assistant Legislative Auditor – State of Maryland, Staff Accountant – Robert M. Carney & Co., CPA’s, Staff Accountant – Naron & Wegad, CPA’s, Credit Clerk – Montgomery Wards.

Central Savings Bank, (1969-1971)

Mr. Majoros was an Assistant Branch Manager at the time he left the bank to attend college as a full-time student. During his tenure at the bank, Mr. Majoros gained experience in each department of the bank. In addition, he attended night school at the University of Baltimore.

EducationUniversity of Baltimore, School of Business, B.S. – Concentration in Accounting

Professional Affiliations American Institute of Certified Public Accountants Maryland Association of C.P.A.s Society of Depreciation Professionals

Publications, Papers, and Panels

“Analysis of Staff Study on Comprehensive Tax Normalization,” FERC Docket No. RM 80-42, 1980.

"Telephone Company Deferred Taxes and Investment Tax Credits – A Capital Loss for Ratepayers," Public Utility Fortnightly, September 27, 1984.

"The Use of Customer Discount Rates in Revenue Requirement Comparisons," Proceedings of the 25th Annual Iowa State Regulatory Conference, 1986

“The Regulatory Dilemma Created By Emerging Revenue Streams of Independent Telephone Companies,” Proceedings of NARUC 101st Annual Convention and Regulatory Symposium, 1989.

“BOC Depreciation Issues in the States,” National Association of State Utility Consumer Advocates, 1990 Mid-Year Meeting, 1990.

“Current Issues in Capital Recovery” 30th Annual Iowa State Regulatory Conference, 1991.

“Impaired Assets Under SFAS No. 121,” National Association of State Utility consumer Advocates, 1996 Mid-Year Meeting, 1996.

“What’s ‘Sunk’ Ain’t Stranded: Why Excessive Utility Depreciation is Avoidable,” with James Campbell, Public Utilities Fortnightly, April 1, 1999.“Local Exchange Carrier Depreciation Reserve Percents,” with Richard B. Lee, Journal of the Society of Depreciation Professionals, Volume 10, Number 1, 2000-2001

“Rolling Over Ratepayers,” Public Utilities Fortnightly, Volume 143, Number 11, November, 2005.

E-57

Appendix B Page 1 of 8

Michael J. Majoros, Jr.

Date Jurisdiction / Agency

Docket_____ Utility_________

Federal Courts2005 US District Court,

Northern District of AL, Northwestern Division 55/56/57/

CV 01-B-403-NW Tennessee Valley Authority

State Legislatures2006 Maryland General

Assembly 61/SB154 Maryland Healthy Air Act

2006 Maryland House of Delegates 62/

HB189 Maryland Healthy Air Act

Federal Regulatory Agencies1979 FERC-US 19/ RP79-12 El Paso Natural Gas Co. 1980 FERC-US 19/ RM80-42 Generic Tax Normalization 1996 CRTC-Canada 30/ 97-9 All Canadian Telecoms 1997 CRTC-Canada 31/ 97-11 All Canadian Telecoms 1999 FCC 32/ 98-137 (Ex Parte) All LECs 1999 FCC 32/ 98-91 (Ex Parte) All LECs 1999 FCC 32/ 98-177 (Ex Parte) All LECs 1999 FCC 32/ 98-45 (Ex Parte) All LECs 2000 EPA 35/ CAA-00-6 Tennessee Valley Authority 2003 FERC 48/ RM02-7 All Utilities2003 FCC 52/ 03-173 All LECs2003 FERC 53/ ER03-409-000,

ER03-666-000Pacific Gas and Electric Co.

State Regulatory Agencies

1982 Massachusetts 17/ DPU 557/558 Western Mass Elec. Co. 1982 Illinois 16/ ICC81-8115 Illinois Bell Telephone Co. 1983 Maryland 8/ 7574-Direct Baltimore Gas & Electric Co. 1983 Maryland 8/ 7574-Surrebuttal Baltimore Gas & Electric Co. 1983 Connecticut 15/ 810911 Woodlake Water Co. 1983 New Jersey 1/ 815-458 New Jersey Bell Tel. Co. 1983 New Jersey 14/ 8011-827 Atlantic City Sewerage Co. 1984 Dist. Of Columbia 7/ 785 Potomac Electric Power Co. 1984 Maryland 8/ 7689 Washington Gas Light Co. 1984 Dist. Of Columbia 7/ 798 C&P Tel. Co. 1984 Pennsylvania 13/ R-832316 Bell Telephone Co. of PA 1984 New Mexico 12/ 1032 Mt. States Tel. & Telegraph 1984 Idaho 18/ U-1000-70 Mt. States Tel. & Telegraph 1984 Colorado 11/ 1655 Mt. States Tel. & Telegraph

E-58



1984 Dist. Of Columbia 7/ 813 Potomac Electric Power Co. 1984 Pennsylvania 3/ R842621-R842625 Western Pa. Water Co. 1985 Maryland 8/ 7743 Potomac Edison Co. 1985 New Jersey 1/ 848-856 New Jersey Bell Tel. Co. 1985 Maryland 8/ 7851 C&P Tel. Co. 1985 California 10/ I-85-03-78 Pacific Bell Telephone Co. 1985 Pennsylvania 3/ R-850174 Phila. Suburban Water Co. 1985 Pennsylvania 3/ R850178 Pennsylvania Gas & Water Co. 1985 Pennsylvania 3/ R-850299 General Tel. Co. of PA 1986 Maryland 8/ 7899 Delmarva Power & Light Co. 1986 Maryland 8/ 7754 Chesapeake Utilities Corp. 1986 Pennsylvania 3/ R-850268 York Water Co. 1986 Maryland 8/ 7953 Southern Md. Electric Corp. 1986 Idaho 9/ U-1002-59 General Tel. Of the Northwest 1986 Maryland 8/ 7973 Baltimore Gas & Electric Co. 1987 Pennsylvania 3/ R-860350 Dauphin Cons. Water Supply 1987 Pennsylvania 3/ C-860923 Bell Telephone Co. of PA 1987 Iowa 6/ DPU-86-2 Northwestern Bell Tel. Co. 1987 Dist. Of Columbia 7/ 842 Washington Gas Light Co. 1988 Florida 4/ 880069-TL Southern Bell Telephone 1988 Iowa 6/ RPU-87-3 Iowa Public Service Company 1988 Iowa 6/ RPU-87-6 Northwestern Bell Tel. Co. 1988 Dist. Of Columbia 7/ 869 Potomac Electric Power Co. 1989 Iowa 6/ RPU-88-6 Northwestern Bell Tel. Co. 1990 New Jersey 1/ 1487-88 Morris City Transfer Station 1990 New Jersey 5/ WR 88-80967 Toms River Water Company 1990 Florida 4/ 890256-TL Southern Bell Company 1990 New Jersey 1/ ER89110912J Jersey Central Power & Light 1990 New Jersey 1/ WR90050497J Elizabethtown Water Co. 1991 Pennsylvania 3/ P900465 United Tel. Co. of Pa. 1991 West Virginia 2/ 90-564-T-D C&P Telephone Co. 1991 New Jersey 1/ 90080792J Hackensack Water Co. 1991 New Jersey 1/ WR90080884J Middlesex Water Co. 1991 Pennsylvania 3/ R-911892 Phil. Suburban Water Co. 1991 Kansas 20/ 176, 716-U Kansas Power & Light Co. 1991 Indiana 29/ 39017 Indiana Bell Telephone 1991 Nevada 21/ 91-5054 Central Tele. Co. – Nevada 1992 New Jersey 1/ EE91081428 Public Service Electric & Gas 1992 Maryland 8/ 8462 C&P Telephone Co. 1992 West Virginia 2/ 91-1037-E-D Appalachian Power Co. 1993 Maryland 8/ 8464 Potomac Electric Power Co. 1993 South Carolina 22/ 92-227-C Southern Bell Telephone 1993 Maryland 8/ 8485 Baltimore Gas & Electric Co. 1993 Georgia 23/ 4451-U Atlanta Gas Light Co. 1993 New Jersey 1/ GR93040114 New Jersey Natural Gas. Co.

E-59



1994 Iowa 6/ RPU-93-9 U.S. West – Iowa 1994 Iowa 6/ RPU-94-3 Midwest Gas1995 Delaware 24/ 94-149 Wilm. Suburban Water Corp. 1995 Connecticut 25/ 94-10-03 So. New England Telephone 1995 Connecticut 25/ 95-03-01 So. New England Telephone 1995 Pennsylvania 3/ R-00953300 Citizens Utilities Company 1995 Georgia 23/ 5503-0 Southern Bell 1996 Maryland 8/ 8715 Bell Atlantic1996 Arizona 26/ E-1032-95-417 Citizens Utilities Company 1996 New Hampshire 27/ DE 96-252 New England Telephone 1997 Iowa 6/ DPU-96-1 U S West – Iowa 1997 Ohio 28/ 96-922-TP-UNC Ameritech – Ohio 1997 Michigan 28/ U-11280 Ameritech – Michigan 1997 Michigan 28/ U-112 81 GTE North 1997 Wyoming 27/ 7000-ztr-96-323 US West – Wyoming 1997 Iowa 6/ RPU-96-9 US West – Iowa 1997 Illinois 28/ 96-0486-0569 Ameritech – Illinois 1997 Indiana 28/ 40611 Ameritech – Indiana 1997 Indiana 27/ 40734 GTE North1997 Utah 27/ 97-049-08 US West – Utah 1997 Georgia 28/ 7061-U BellSouth – Georgia 1997 Connecticut 25/ 96-04-07 So. New England Telephone 1998 Florida 28/ 960833-TP et. al. BellSouth – Florida 1998 Illinois 27/ 97-0355 GTE North/South1998 Michigan 33/ U-11726 Detroit Edison 1999 Maryland 8/ 8794 Baltimore Gas & Electric Co. 1999 Maryland 8/ 8795 Delmarva Power & Light Co. 1999 Maryland 8/ 8797 Potomac Edison Company 1999 West Virginia 2/ 98-0452-E-GI Electric Restructuring 1999 Delaware 24/ 98-98 United Water Company 1999 Pennsylvania 3/ R-00994638 Pennsylvania American Water 1999 West Virginia 2/ 98-0985-W-D West Virginia American Water 1999 Michigan 33/ U-11495 Detroit Edison 2000 Delaware 24/ 99-466 Tidewater Utilities 2000 New Mexico 34/ 3008 US WEST Communications, Inc. 2000 Florida 28/ 990649-TP BellSouth -Florida2000 New Jersey 1/ WR30174 Consumer New Jersey Water 2000 Pennsylvania 3/ R-00994868 Philadelphia Suburban Water 2000 Pennsylvania 3/ R-0005212 Pennsylvania American Sewerage 2000 Connecticut 25/ 00-07-17 Southern New England Telephone 2001 Kentucky 36/ 2000-373 Jackson Energy Cooperative 2001 Kansas 38/39/40/ 01-WSRE-436-RTS Western Resources 2001 South Carolina 22/ 2001-93-E Carolina Power & Light Co. 2001 North Dakota 37/ PU-400-00-521 Northern States Power/Xcel Energy 2001 Indiana 29/41/ 41746 Northern Indiana Power Company

E-60



2001 New Jersey 1/ GR01050328 Public Service Electric and Gas 2001 Pennsylvania 3/ R-00016236 York Water Company 2001 Pennsylvania 3/ R-00016339 Pennsylvania America Water 2001 Pennsylvania 3/ R-00016356 Wellsboro Electric Coop. 2001 Florida 4/ 010949-EL Gulf Power Company 2001 Hawaii 42/ 00-309 The Gas Company 2002 Pennsylvania 3/ R-00016750 Philadelphia Suburban 2002 Nevada 43/ 01-10001 &10002 Nevada Power Company 2002 Kentucky 36/ 2001-244 Fleming Mason Electric Coop. 2002 Nevada 43/ 01-11031 Sierra Pacific Power Company 2002 Georgia 27/ 14361-U BellSouth-Georgia 2002 Alaska 44/ U-01-34,82-87,66 Alaska Communications Systems 2002 Wisconsin 45/ 2055-TR-102 CenturyTel 2002 Wisconsin 45/ 5846-TR-102 TelUSA 2002 Vermont 46/ 6596 Citizen’s Energy Services 2002 North Dakota 37/ PU-399-02-183 Montana Dakota Utilities 2002 Kansas 40/ 02-MDWG-922-RTS Midwest Energy 2002 Kentucky 36/ 2002-00145 Columbia Gas 2002 Oklahoma 47/ 200200166 Reliant Energy ARKLA 2002 New Jersey 1/ GR02040245 Elizabethtown Gas Company 2003 New Jersey 1/ ER02050303 Public Service Electric and Gas Co. 2003 Hawaii 42/ 01-0255 Young Brothers Tug & Barge 2003 New Jersey 1/ ER02080506 Jersey Central Power & Light 2003 New Jersey 1/ ER02100724 Rockland Electric Co. 2003 Pennsylvania 3/ R-00027975 The York Water Co. 2003 Pennsylvania /3 R-00038304 Pennsylvania-American Water Co. 2003 Kansas 20/ 40/ 03-KGSG-602-RTS Kansas Gas Service 2003 Nova Scotia, CN 49/ EMO NSPI Nova Scotia Power, Inc. 2003 Kentucky 36/ 2003-00252 Union Light Heat & Power 2003 Alaska 44/ U-96-89 ACS Communications, Inc. 2003 Indiana 29/ 42359 PSI Energy, Inc. 2003 Kansas 20/ 40/ 03-ATMG-1036-RTS Atmos Energy 2003 Florida 50/ 030001-E1 Tampa Electric Company 2003 Maryland 51/ 8960 Washington Gas Light 2003 Hawaii 42/ 02-0391 Hawaiian Electric Company 2003 Illinois 28/ 02-0864 SBC Illinois 2003 Indiana 28/ 42393 SBC Indiana 2004 New Jersey 1/ ER03020110 Atlantic City Electric Co. 2004 Arizona 26/ E-01345A-03-0437 Arizona Public Service Company 2004 Michigan 27/ U-13531 SBC Michigan 2004 New Jersey 1/ GR03080683 South Jersey Gas Company 2004 Kentucky 36/ 2003-00434,00433 Kentucky Utilities, Louisville Gas &

Electric2004 Florida 50/ 54/ 031033-EI Tampa Electric Company 2004 Kentucky 36/ 2004-00067 Delta Natural Gas Company

E-61



2004 Georgia 23/ 18300, 15392, 15393 Georgia Power Company 2004 Vermont 46/ 6946, 6988 Central Vermont Public Service

Corporation2004 Delaware 24/ 04-288 Delaware Electric Cooperative 2004 Missouri 58/ ER-2004-0570 Empire District Electric Company 2005 Florida 50/ 041272-EI Progress Energy Florida, Inc. 2005 Florida 50/ 041291-EI Florida Power & Light Company 2005 California 59/ A.04-12-014 Southern California Edison Co. 2005 Kentucky 36/ 2005-00042 Union Light Heat & Power 2005 Florida 50/ 050045 & 050188-EI Florida Power & Light Co. 2005 Florida 50/ 54/ 030157-EI Progress Energy Florida 2005 Kansas 38/ 40/ 05-WSEE-981-RTS Westar Energy, Inc. 2006 Delaware 24/ 05-304 Delmarva Power & Light Company 2006 California 59/ A.05-12-002 Pacific Gas & Electric Co. 2006 New Jersey 1/ GR05100845 Public Service Electric and Gas Co. 2006 Colorado 60/ 06S-234EG Public Service Co. of Colorado 2006 Kentucky 36/ 2006-00172 Union Light, Heat & Power 2006 Kansas 40/ 06-KGSG-1209-RTS Kansas Gas Service 2006 West Virginia 2/ 06-0960-E-42T,

06-1426-E-DAllegheny Power

2006 West Virginia 2/ 05-1120-G-30C, 06-0441-G-PC, et al.

Hope Gas, Inc. and Equitable Resources, Inc.

2007 Delaware 24/ 06-284 Delmarva Power & Light Company 2007 Kentucky 36/ 2006-00464 Atmos Energy Corporation 2007 Colorado 60/ 06S-656G Public Service Co. of Colorado 2007 California 59/ A.06-12-009,

A.06-12-010San Diego Gas & Electric Co., and Southern California Gas Co.

2007 Kentucky 36/ 2007-00143 Kentucky-American Water Co. 2007 Kentucky 36/ 2007-00089 Delta Natural Gas Co. 2008 Kansas 40/ 08-ATMG-280-RTS Atmos Energy Corporation

E-62



PARTICIPATION AS NEGOTIATOR IN FCC TELEPHONE DEPRECIATION RATE REPRESCRIPTION CONFERENCES

COMPANY YEARS CLIENT

Diamond State Telephone Co. 24/ 1985 + 1988 Delaware Public Service Comm Bell Telephone of Pennsylvania 3/ 1986 + 1989 PA Consumer Advocate Chesapeake & Potomac Telephone Co. - Md. 8/ 1986 Maryland People’s Counsel Southwestern Bell Telephone – Kansas 20/ 1986 Kansas Corp. Commission Southern Bell – Florida 4/ 1986 Florida Consumer Advocate Chesapeake & Potomac Telephone Co.-W.Va. 2/ 1987 + 1990 West VA Consumer Advocate New Jersey Bell Telephone Co. 1/ 1985 + 1988 New Jersey Rate Counsel Southern Bell - South Carolina 22/ 1986 + 1989 + 1992 S. Carolina Consumer Advocate GTE-North – Pennsylvania 3/ 1989 PA Consumer Advocate

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PARTICIPATION IN PROCEEDINGS WHICH WERE SETTLED BEFORE TESTIMONY WAS SUBMITTED

STATE DOCKET NO. UTILITY

Maryland 8/ 7878 Potomac Edison Nevada 21/ 88-728 Southwest Gas New Jersey 1/ WR90090950J New Jersey American Water New Jersey 1/ WR900050497J Elizabethtown Water New Jersey 1/ WR91091483 Garden State Water West Virginia 2/ 91-1037-E Appalachian Power Co. Nevada 21/ 92-7002 Central Telephone - Nevada Pennsylvania 3/ R-00932873 Blue Mountain Water West Virginia 2/ 93-1165-E-D Potomac Edison West Virginia 2/ 94-0013-E-D Monongahela Power New Jersey 1/ WR94030059 New Jersey American Water New Jersey 1/ WR95080346 Elizabethtown Water New Jersey 1/ WR95050219 Toms River Water Co. Maryland 8/ 8796 Potomac Electric Power Co. South Carolina 22/ 1999-077-E Carolina Power & Light Co. South Carolina 22/ 1999-072-E Carolina Power & Light Co. Kentucky 36/ 2001-104 & 141 Kentucky Utilities, Louisville Gas

and Electric Kentucky 36/ 2002-485 Jackson Purchase Energy Corporation

E-64



Clients

1/ New Jersey Rate Counsel/Advocate 33/ Michigan Attorney General 2/ West Virginia Consumer Advocate 34/ New Mexico Attorney General 3/ Pennsylvania OCA 35/ Environmental Protection Agency Enforcement Staff 4/ Florida Office of Public Advocate 36/ Kentucky Attorney General 5/ Toms River Fire Commissioner’s 37/ North Dakota Public Service Commission 6/ Iowa Office of Consumer Advocate 38/ Kansas Industrial Group 7/ D.C. People’s Counsel 39/ City of Witchita 8/ Maryland’s People’s Counsel 40/ Kansas Citizens’ Utility Rate Board 9/ Idaho Public Service Commission 41/ NIPSCO Industrial Group 10/ Western Burglar and Fire Alarm 42/ Hawaii Division of Consumer Advocacy 11/ U.S. Dept. of Defense 43/ Nevada Bureau of Consumer Protection 12/ N.M. State Corporation Comm. 44/ GCI 13/ City of Philadelphia 45/ Wisc. Citizens’ Utility Rate Board 14/ Resorts International 46/ Vermont Department of Public Service 15/ Woodlake Condominium Association 47/ Oklahoma Corporation Commission 16/ Illinois Attorney General 48/ National Assn. of State Utility Consumer Advocates 17/ Mass Coalition of Municipalities 49/ Nova Scotia Utility and Review Board 18/ U.S. Department of Energy 50/ Florida Office of Public Counsel 19/ Arizona Electric Power Corp. 51/ Maryland Public Service Commission 20/ Kansas Corporation Commission 52/ MCI 21/ Public Service Comm. – Nevada 53/ Transmission Agency of Northern California 22/ SC Dept. of Consumer Affairs 54/ Florida Industrial Power Users Group 23/ Georgia Public Service Comm. 55/ Sierra Club 24/ Delaware Public Service Comm. 56/ Our Children’s Earth Foundation 25/ Conn. Ofc. Of Consumer Counsel 57/ National Parks Conservation Association, Inc. 26/ Arizona Corp. Commission 58/ Missouri Office of the Public Counsel 27/ AT&T 59/ The Utility Reform Network 28/ AT&T/MCI 60/ Colorado Office of Consumer Counsel 29/ IN Office of Utility Consumer Counselor

61/ MD State Senator Paul G. Pinsky

30/ Unitel (AT&T – Canada) 62/ MD Speaker of the House Michael Busch 31/ Public Interest Advocacy Centre 32/ U.S. General Services Administration

E-65

EXHIBITS TO DIRECT TESTIMONY OF WITNESS

MICHAEL J. MAJOROS, JR. ON BEHALF OF

THE UTILITY REFORM NETWORK (TURN)

California Public Utilities Commission

Southern California Edison 2009 General Rate Case A. 07-11-011

April 2008

Exhibit MJM-1 and MJM-2

E-66

Exh

ibit_

__(M

JM-1

)P

age

1 of

3

Com

paris

on o

f Inf

latio

n Ex

pens

e Pa

ttern

s

$0

$500

$1,0

00

$1,5

00

$2,0

00

$2,5

00

$3,0

00

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

$000

Acc

rual

Bas

isFi

sher

Ove

rcha

rge

Und

erch

arge

E-67

Exh

ibit_

__(M

JM-1

)P

age

2 of

3

Sout

hern

Cal

iforn

ia E

diso

nC

ompa

rison

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al A

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sent

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t Per

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ssum

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ing

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00

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00

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26

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00

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2009

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00

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.00

31

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9

12

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2010

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00$3

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Stra

ight

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e R

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of O

rigin

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V of

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ure

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oval

In

flatio

n to

Orig

inal

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t of F

utur

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alA

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l Exp

ense

E-68

Exh

ibit_

__(M

JM-1

)P

age

3 of

3

Acc

rual

Bas

isFi

sher

Year

Ann

ual I

nfla

tion

Ann

ual I

nfla

tion

2000

$1,0

00.0

0$1

,653

.30

2001

1,05

0.00

1,65

3.30

2002

1,10

2.50

1,65

3.30

2003

1,15

7.63

1,65

3.30

2004

1,21

5.51

1,65

3.30

2005

1,27

6.28

1,65

3.30

2006

1,34

0.10

1,65

3.30

2007

1,40

7.10

1,65

3.30

2008

1,47

7.46

1,65

3.30

2009

1,55

1.33

1,65

3.30

2010

1,62

8.89

1,65

3.30

2011

1,71

0.34

1,65

3.30

2012

1,79

5.86

1,65

3.30

2013

1,88

5.65

1,65

3.30

2014

1,97

9.93

1,65

3.30

2015

2,07

8.93

1,65

3.30

2016

2,18

2.87

1,65

3.30

2017

2,29

2.02

1,65

3.30

2018

2,40

6.62

1,65

3.30

2019

2,52

6.95

1,65

3.30

Com

paris

on o

f Inf

latio

n Ex

pens

e Pa

ttern

s

E-69

Exh

ibit_

__(M

JM-2

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1 of

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DE

PR

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1/1/

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1/07

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AL

PLA

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*(1

)(2

)(3

)=(1

)*(2

)(4

)(5

)=(1

)-(3)

-(4)

(6)

(7)

(8)

(9)=

(5)/(

8)(1

2)=(

9)/(1

)ST

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PR

OD

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N --

MO

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truct

ures

and

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33,8

76,8

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0.

0%-

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(6

,928

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)

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n45

9.5

(729

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ler P

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ipm

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l Moh

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%

STEA

M P

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-- F

OU

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OR

NER

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1S

truct

ures

and

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ents

17,0

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0.

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)

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ler P

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ipm

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62

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31

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tal S

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duct

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53

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ctric

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ipm

ent

176,

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17

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cens

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7

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er P

lant

Equ

ipm

ent

117,

569,

906

0.

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14

7,32

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1

(2

9,75

9,11

4)

Li

cens

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To

tal P

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GS

Pro

duct

ion

1,68

0,52

6,15

9

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1,

463,

582,

345

21

6,94

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18

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182

Des

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Bas

is D

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tion

7,77

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8

0.0%

-

6,75

6,64

7

1,01

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1

Lice

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19.1

53,3

10

18

2D

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red

Deb

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0.0%

-

16,0

99,3

26

2,67

5,44

3

Lice

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19.1

140,

390

Tota

l PV

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S D

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& D

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26,5

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57

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19

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Tota

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S P

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1,70

7,07

3,51

6

-

1,

486,

438,

318

22

0,63

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8

11

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PR

ES

EN

T V

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E

Sout

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diso

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Rat

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UR

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ased

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PR

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DE

PR

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RU

AL

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*(1

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PR

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RO

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330.

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4

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84,5

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9,99

6

Lice

nse

38.2

112,

101

3.33

%

331

Stru

ctur

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nd Im

prov

emen

ts10

4,45

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2

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14

69,6

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13

Lice

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38.9

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7

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9

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190,

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251

Lice

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40.0

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7

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ater

Whe

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Tur

bine

s &

Gen

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112,

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326

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48

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65

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Li

cens

e39

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479

1.

64%

334

Acc

esso

ry E

lect

ric E

quip

men

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0,58

9,30

1

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8,20

9)

15

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95

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Li

cens

e34

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171,

073

3.

15%

335

Mis

c. P

ower

Pla

nt E

quip

men

t11

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%(1

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4,97

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1

Lice

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7

Lice

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Tota

l Hyd

ro E

lect

ric P

rodu

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3

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303)

303,

704,

331

470,

611,

416

14,0

44,1

15

1.

87%

Tota

l Hyd

ro E

lect

ric

755,

286,

988

(2

2,39

3,30

3)

30

3,78

8,87

9

47

3,89

1,41

2

14

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1.87

%

OTH

ER P

RO

DU

CTI

ON

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LY B

EAC

H34

1S

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ures

and

Impr

ovem

ents

1,47

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1

Life

Spa

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24.7

52,3

88

34

2Fu

el H

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s &

Acc

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460

Li

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pan

4524

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343

Prim

e M

over

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1

13,9

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56

Life

Spa

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24.7

561,

983

344

Gen

erat

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8,24

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4

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2,43

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6

5,81

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8

Life

Spa

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906

345

Acc

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ry E

lect

ric E

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484

Li

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4524

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346

Mis

c. P

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59

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5

Li

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Dec

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Li

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Tota

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ER P

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341

Stru

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Li

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Life

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PR

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118,

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Tota

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,903

97

6,65

3,06

3

Sou

rces

:

Col

. (2)

from

Exh

ibit_

__(M

JM-2

), pa

ges

1-5.

1/ A

ccru

al c

alcu

late

d us

ing

SC

E11

_V2_

ChI

I_p

44-5

1.xl

s.

Col

. (1)

= 2

009

wei

ghte

d av

erag

e pl

ant a

mou

nts

from

SC

E11

_V2_

ChI

I wor

kpap

ers,

pag

es 1

6-12

3 (E

xcel

file

s pr

ovid

ed in

resp

onse

to S

CE

-024

, Q. 9

).

E-86

E-87

E-88

E-89

E-90

E-91

E-92

E-93

Appendix F

Rate Base

Exhibit SCE-26 – Results of Operations (R/O)

Volume 2 – Plant, Taxes, Depreciation Expense and Reserve, and Rate Base

Appendix F Documents

Document Page

SCE Response to TURN-SCE-021, Question 08 F-1

SCE Response to TURN-SCE-021, Question 17 F-3

SCE Response to TURN-SCE-021, Question 23 [Confidential] F-4

SCE Response to TURN-SCE-021, Question 35 [Confidential] F-5

ORA Response to SCE-DRA-034-GIE, Question 1 F-7

TURN Response to SCE-TURN-014, Question 1 F-10

Southern California Edison 2015 GRC A.13-11-003

DATA REQUEST SET TURN-SCE-021

To: TURN

Prepared by: Stephen DIxon Title: Financial Analyst

Dated: 03/17/2014


Question 08: Originator: Bob Finkelstein All page references are to the workpapers for SCE-10, v. 2, ch. V unless otherwise specified. 8. Please provide Materials and Supplies by Function monthly from 2008-2011 and 2013 recorded (i.e., same information as Workpapers 32-33). Response to Question 08: See the attachment for recorded Materials & Supplies data for the years 2008 through 2011 and 2013 (Note: recorded balances were adjusted to remove SONGS and Four Corners Generating Station). The 2013 recorded data being provided is preliminary and subject to change. This data will not become final until SCE files its 2013 FERC FORM 1.

TURN

SCE0

21(Que

stion

8)

Mate

rials

& Su

pplie

s:20

13 M

onthl

y Bala

nces

2013

Dec-1

2Jan

-13Fe

b-13

Mar-1

3Ap

r-13

May

-13Ju

n-13

Jul-13

Aug-1

3Se

p-13

Oct-1

3No

v-13

Dec-1

3W

eighte

d Avg

Tran

sm. &

Dist

ributi

on10

4,568

,295

10

5,384

,558

11

0,575

,219

11

5,139

,402

11

8,079

,603

12

3,739

,586

12

7,684

,199

13

0,479

,613

13

2,042

,188

13

2,562

,188

13

4,924

,873

13

5,466

,871

13

7,756

,742

12

3,936

,735

Palo

Verde

25,28

6,503

26,18

7,768

26,70

8,776

27,09

1,080

26,25

9,836

26,13

3,392

26,57

7,916

26,71

0,798

26,79

2,664

26,92

5,546

26,92

5,546

26,92

5,546

26,92

5,546

26,61

2,074

Hydro

3,027

,625

3,050

,387

3,054

,132

3,059

,746

3,059

,432

3,056

,696

3,348

,037

3,346

,182

3,355

,756

3,361

,295

3,279

,095

3,156

,935

3,380

,022

3,194

,293

Mou

ntainv

iew4,6

18,45

3

4,6

54,27

1

4,6

50,96

0

4,6

11,21

1

4,5

57,45

5

4,6

07,39

0

4,6

23,34

7

4,6

37,28

7

4,6

60,88

4

4,6

83,46

2

4,5

53,28

6

4,4

49,04

0

4,5

19,70

6

4,6

04,80

6

Pe

akers

832,2

18

831,5

86

836,6

18

836,0

54

851,0

67

851,8

35

854,0

31

854,9

02

854,9

24

840,2

98

841,1

82

870,6

91

870,8

26

847,8

93

Solar

79,41

1

79

,411

79,41

1

79

,411

79,41

1

79

,411

79,41

1

79

,411

79,41

1

79

,411

79,41

1

79

,411

79,41

1

79

,411

Powe

r Gen

/Prod

uctio

n33

,844,2

11

34

,803,4

22

35

,329,8

97

35

,677,5

01

34

,807,2

01

34

,728,7

23

35

,482,7

42

35

,628,5

81

35

,743,6

39

35

,890,0

11

3 5

,678,5

20

35

,481,6

22

35

,775,5

11

35

,338,4

77

Info T

ech. (

Excl.

Non

utility

)7,5

72,71

6

7,5

25,87

4

7,5

19,76

0

7,4

44,03

5

7,5

04,56

6

7,3

54,18

5

7,3

80,75

9

8,0

24,61

5

7,8

12,31

9

7,8

85,38

8

8,0

15,23

8

8,0

30,05

9

7,8

60,01

8

7,6

84,43

0

Tr

ansp

ortati

on Se

rvice

s28

3,678

27

2,414

26

3,692

28

0,090

28

5,804

28

3,005

28

0,949

29

0,812

29

9,758

27

8,287

31

4,853

30

6,292

29

7,612

28

7,217

Ge

nera

l 7,8

56,39

3

7,7

98,28

8

7,7

83,45

1

7,7

24,12

6

7,7

90,37

0

7,6

37,18

9

7,6

61,70

9

8,3

15,42

7

8,1

12,07

7

8,1

63,67

5

8,3

30,09

0

8,3

36,35

1

8,1

57,63

0

7,9

71,64

7

Total

M&S

146,2

68,89

9

147,9

86,26

8

153,6

88,56

7

158,5

41,02

9

160,6

77,17

4

166,1

05,49

7

170,8

28,65

0

174,4

23,62

1

175,8

97,90

3

176,6

15,87

4

178,9

33,48

3

179,2

84,84

3

181,6

89,88

2

167,2

46,85

8

Sales

Tax

Adju

stmen

ts(4,

444,3

57)

(501,4

64)

(1,

033,2

75)

(1,45

8,237

)

(1,

251,5

62)

(1,80

1,579

)

(1,

666,0

12)

(2,56

7,410

)

(1,

866,6

91)

(2,93

4,868

)

(2,

475,0

91)

(2,72

2,002

)

(4,

194,6

48)

(2,04

9,808

)

Un

paid

Adjus

tmen

t(10

,044,4

99)

(10,11

2,255

)

(10

,542,4

29)

(10,91

3,562

)

(11

,159,9

28)

(11,62

1,109

)

(11

,976,3

40)

(12,26

3,778

)

(12

,379,3

83)

(12,42

7,959

)

(12

,620,3

78)

(12,64

9,549

)

(12

,849,2

26)

(11,67

6,128

)

Ac

coun

ting A

djustm

ents

(14,48

8,855

)

(10

,613,7

19)

(11,57

5,705

)

(12

,371,7

98)

(12,41

1,489

)

(13

,422,6

88)

(13,64

2,352

)

(14

,831,1

88)

(14,24

6,074

)

(15

,362,8

28)

(15,09

5,468

)

(15

,371,5

51)

(17,04

3,875

)

(13

,725,9

35)

Total

Adju

sted M

&S13

1,780

,043

13

7,372

,549

14

2,112

,862

14

6,169

,231

14

8,265

,685

15

2,682

,809

15

7,186

,298

15

9,592

,433

16

1,651

,830

16

1,253

,046

16

3,838

,015

16

3,913

,292

16

4,646

,008

15

3,520

,923

Southern California Edison 2015 GRC A.13-11-003

DATA REQUEST SET TURN-SCE-021

To: TURN

Prepared by: John Carrillo Title: Project Manager

Dated: 03/17/2014


Question 17: Originator: Bob Finkelstein

All page references are to the workpapers for SCE-10, v. 2, ch. V unless otherwise specified.

17. Are any costs for Non-Tariffed Products and Services included in either Other Accounts Receivable, the Provision for Doubtful Accounts (Accrual) and Doubtful Accounts (Write-off)? If so please quantify the annual amounts related to NTP&S at the end of 2007, 2008, and 2009 and monthly figures for 2010-2013 recorded.

Response to Question 17: Subsequent to the Application filing, SCE identified that it inadvertently included NTP&S amounts (2012 recorded) in the OAR balances of its 2015 GRC Operational Cash requirement. SCE did not include any OAR amounts for 2007, 2008, and 2009 since the 2012 recorded amounts are used for its 2015 GRC. In addition, 2010, 2011, 2013 NTP&S receivable balances are not readily available as this would require a special detailed study to be performed for those years. However, these amounts are irrelevant due to the fact that SCE will be removing NTP&S amounts from it 2012 recorded amounts that are the basis for its 2015 GRC requirement. SCE did not include any NTP&S related amounts in the Provision for Doubtful Accounts balances. However, SCE also noted that certain OAR related Provision for Doubtful Account balances had been excluded as well. SCE will make corrections associated with the above errors in a future filing at the appropriate time. The attachment below provides the corrected workpapers for 2012 recorded balances and 2013 - 2017 forecast balances which are adjusted to exclude NTP&S amounts and to include the missing Provision for Doubtful Accounts balances.

See Appendix In Confidential Version of This Volume Of Testimony

F-4 through F-6

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 26, 2014 Response Date: August 19, 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: Godson Ezekwo Phone: (415)703-5881 Email: [email protected] Data Request No: SCE-DRA-034-GIE Exhibit Reference: ORA-24 Subject: Calculation of the Percentage Adjustment of M & S Inventory 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: Contained within the ORA-24 Rate Base Workpaper is a calculation of the

percentage adjustment ORA proposes to be made to SCE’s 2015 T&D M&S inventory. Please explain the result obtained by ORA from the following calculation, found on line 22 of the workpaper: (55-40)/40 = 0.2727

The calculation as stated above appears to be in error because it does not result in a factor of .2727 as stated. The calculation as stated results in a factor of .3750 instead. Please clarify the correct calculation or result intended.

A.1: The calculation of the percentage adjustment of M & S inventory on line 22 of ORA workpapers is wrong due to a typographical error. The correct calculation is: (55-40)/55=0.2727.

South

ern Ca

liforni

a Edis

on Co

mpan

yW

orking

Cash

Capit

alOp

eratio

nal C

ash Re

quire

ment

Othe

r Acco

unts

Recei

vable

Accou

ntAc

count

Descr

iption

Forec

astDe

cember

-11Ja

nuary

-12Fe

bruary

-12Ma

rch-12

April

-12Ma

y-12

June

-12Ju

ly-12

Augu

st-12

Septe

mber-

12Oc

tober-

12No

vember

-12De

cember

-12Av

erage

115101

0Ot

her A

ccoun

ts Re

ceiva

ble - R

econc

iliatio

n Acco

unt

Non-L

abor

Comp

osite

9,671,

346

9,035,

616

12,298

,386

10,774

,329

13,558

,984

12,491

,437

14,586

,051

14,920

,897

13,306

,082

24,313

,306

18,196

,973

19,406

,763

31,346

,356

15,283

,140

115108

5Ac

coun

ts Re

ceiva

ble - D

amage

Claim

s Reco

nNo

n-Lab

or Co

mpos

ite18,

988,24

0

19,

233,63

6

19,

152,60

0

21,

803,04

5

20,

265,37

4

18,

773,87

0

12,

998,41

4

21,

761,14

5

20,

751,08

3

18,

392,04

6

17,

588,65

2

17,

431,38

7

17,

544,43

4

18,

868,13

2

115

1177

Cal C

DP Tr

ust R

eceiva

bleNo

n-Lab

or Co

mpos

ite-

878,66

6

-

-

-

-

-

-

-

1,8

05,089

1,0

36,845

-

466,05

9

329,46

9

115120

0HC

RA Tr

ust R

eceiva

ble - P

rior Y

earMe

dical

-

521

,135

826

,636

116

,548

218

,222

238

,700

6,2

70

4,8

65

(43

5,410)

(82

0,236)

(1,

405)

(1,405

)

(0)

56,

160

115

1205

DCRA

Trus

t Rece

ivable

- Prio

r Year

Non-L

abor

Comp

osite

-

252

,021

1,0

71,821

188

,551

286

,166

188

,440

10,

221

10,

221

(12

0,262)

(37

4,527)

-

-

-

126,05

4

115122

0PB

OP Tr

ust R

eimbu

rseme

nt Re

ceiva

ble*

Medic

al14,

851,66

5

20,

126,66

5

25,

401,66

5

30,

903,14

7

21,

957,19

5

27,

232,19

5

32,

507,19

5

37,

782,19

5

42,

941,34

5

48,

216,34

5

53,

491,34

5

58,

766,34

5

64,

041,34

5

36,

564,34

5

115

1225

Emplo

yee T

ools/

Safety

Recei

vable

Non-L

abor

Comp

osite

107,25

0

102,06

0

90,381

92,644

84,991

79,042

72,010

64,717

59,410

53,625

46,717

44,752

38,484

71,935

115123

5Me

dicare

RX Re

imburs

emen

tsMe

dical

1,337,

991

1,837,

991

1,837,

991

2,391,

406

2,694,

530

2,671,

990

2,747,

590

2,137,

900

2,637,

900

2,698,

989

2,874,

869

2,913,

931

747,21

5

2,373,

974

115125

0Pe

nsion

Plan

Trus

teeNo

n-Lab

or Co

mpos

ite1,6

74,371

1,3

01,572

1,8

26,982

1,6

82,121

1,7

57,782

1,0

04,010

734

,183

1,2

04,733

1,2

86,543

730

,582

1,3

04,460

1,0

20,936

940

,079

1,2

63,427

115

1260

OAR -

North

ern Tr

ust -

VEBA

Non-L

abor

Comp

osite

420,17

4

363,64

1

504,33

0

349,58

6

354,77

0

546,15

6

271,91

5

361,83

8

220,63

5

388,67

7

470,96

3

147,41

7

346,18

1

363,59

2

Total

Othe

r Acco

unts

Recei

vable

47,051

,037

53,653

,002

63,010

,790

68,301

,378

61,178

,014

63,225

,841

63,933

,849

78,248

,511

80,647

,326

95,403

,894

95,009

,419

99,730

,127

115,47

0,153

75,300

,229

Allow

ance

for Un

collec

tibles

115302

0Pro

vision

for D

oubtf

ul Ac

coun

ts - C

RENo

n-Lab

or Co

mpos

ite(3,

608,34

0)

(3,

608,34

0)

(3,

576,86

3)

(3,

459,07

4)

(3,

427,51

2)

(3,

427,51

2)

(3,

927,51

2)

(3,

927,51

2)

(3,

927,51

2)

(4,

727,51

2)

(3,

162,71

5)

(3,

161,51

6)

(4,

343,47

4)

(3,

692,45

7)

115

3040

Provis

ion fo

r Dou

btful

Acco

unts

- PW

RDNo

n-Lab

or Co

mpos

ite(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

270,18

7)

(1,

120,18

7)

(1,

263,93

7)

115

3080

Provis

ion fo

r Dou

btful

Acco

unts

- PMO

Non-L

abor

Comp

osite

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(272,2

08)

(339,5

32)

(275,0

14)

115309

0Pro

vision

for D

oubtf

ul Ac

coun

ts - C

atalina

Islan

dNo

n-Lab

or Co

mpos

ite(12

,688)

(12

,688)

(12

,688)

(12

,688)

(12

,688)

(12

,688)

(12

,688)

(1,9

68)

(1,

968)

(1,968

)

(1,

968)

(1,968

)

(1,9

68)

(7,

775)

115310

0Pro

vision

for D

oubtf

ul Ac

coun

ts - D

amage

Claim

sNo

n-Lab

or Co

mpos

ite(11

,645,8

84)

(11

,924,1

09)

(11

,894,9

36)

(12

,849,0

96)

(12

,295,5

35)

(12

,145,8

03)

(10

,788,2

20)

(11

,103,7

64)

(10

,740,1

42)

(6,

621,13

6)

(6,

331,91

5)

(6,

275,29

9)

(6,

315,99

6)

(10

,162,5

75)

115

3110

Provis

ion fo

r Dou

btful

Acco

unts

- Accr

uals

Non-L

abor

Comp

osite

(134,4

74,405

)

(13

6,971,

116)

(139,2

57,507

)

(14

1,728,

867)

(144,0

03,007

)

(14

6,478,

596)

(149,3

18,165

)

(15

2,583,

967)

(156,8

63,880

)

(16

0,616,

408)

(164,0

93,139

)

(16

6,496,

282)

(168,9

76,997

)

(15

0,844,

720)

115315

0Pro

vision

for D

oubtf

ul Ac

coun

ts - W

rite Of

fNo

n-Lab

or Co

mpos

ite92,

440,82

5

94,

817,74

2

97,

263,01

8

99,

902,11

7

103

,038,5

25

105

,712,0

69

107

,747,1

84

109

,362,1

51

112

,969,6

57

115

,343,8

67

117

,381,8

09

119

,408,5

28

121

,792,9

83

107

,505,2

98

Ta

x Adju

stmen

t (40.3

09%)

23,719

,156

23,879

,595

23,791

,101

24,060

,622

23,477

,189

23,337

,039

23,315

,623

24,103

,936

24,228

,405

23,446

,127

23,278

,751

23,407

,180

23,905

,499

23,678

,158

Total

Allow

ance

for Un

collec

tibles

(35,12

3,731)

(35,36

1,312)

(35,23

0,269)

(35,62

9,380)

(34,76

5,422)

(34,55

7,885)

(34,52

6,173)

(35,69

3,520)

(35,87

7,836)

(34,71

9,425)

(34,47

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(34,66

1,752)

(35,39

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(35,06

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Gran

d Tota

l11

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06

18

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91

27

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20

32

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97

26

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91

28

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55

29

,407,6

76

42

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92

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*PBO

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7

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232,19

5

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507,19

5

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782,19

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65

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1151

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370

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1151

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PBO

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52,4

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1151

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71,9

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1151

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1151

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Pens

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Plan

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281,

273

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5

1,

336,

196

1,37

0,41

9

1,

403,

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1151

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592

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394,

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(1,4

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98,3

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56,0

59,5

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63,6

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11

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for D

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697,

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11

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119,

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410

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x Adj

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24

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6,27

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082,

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(38,

945,

566)

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d To

tal

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37,2

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60,4

64

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($00

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,237

42,3

60

45

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53

,122

57,2

97

For

ecas

ted

DATA REQUEST SCE-TURN-014 Southern California Edison TY 2015 GRC Date: August 21, 2014

Responses Due: Responses Provided:

September 5, 2014 September 5, 2014

To: William B. Marcus

Originated by: John Carrillo Project Manager Southern California Edison Company 2244 Walnut Grove Avenue Rosemead, CA 91770 [email protected] (626) 302-5624

Data Request No: SCE-TURN-014 Please provide the following items: Exhibit Ref: TURN-05 Marcus Public Workpapers, Ch XII, TURN OAR workpapers starting with 21-17.xlsx 1. In the above referenced workpaper, workbook tab OAR forecast, the proposed TURN 2015

Trust Reimbursement Receivable balance is calculated as $30,353,678. However, the amount listed for this adjustment in TURN-05 on p.128 is $30,537,000. Please confirm which number is the correct proposed TURN 2015 balance for this item.

Response The $30,353,678 figure is correct, and will be changed in errata to $30,354,000 using the testimony convention of rounding figures to the nearest $1,000.