2021 General Rate Case Rebuttal Testimony › PublishedDocs › SupDoc › A...11 Ninety percent of SCE’s proposal is designed to remedy the pace of under-collection for T&D net

Application No.: A.19-08-013 Exhibit No.: SCE-18 Vol. 03 Witnesses: D. Gunn

J. Rankin R. White

(U 338-E)

2021 General Rate Case Rebuttal Testimony

Depreciation Study, Hydro and Other

Decommissioning, Other Generation

Before the

Public Utilities Commission of the State of California

Rosemead, California June 12, 2020

SCE-18, Vol. 03: Rebuttal Testimony on Depreciation Study, Hydro and Other Decommissioning, Other Generation

Table Of Contents

Section Page Witness

-i-

I. INTRODUCTION .............................................................................................1 D. Gunn

II. T&D NET SALVAGE .......................................................................................3

A. TURN’s And Cal Advocates’ Positions ................................................4

B. SCE’s Rebuttal .......................................................................................5

1. SCE’s Depreciation Rate History Gives Context For The Need To Increase Net Salvage Rates ..................................5

a) Historically, The Commission Has Accepted Longer Service Lives .....................................................5

b) Lengthening Service Lives Has A Simultaneous Effect On Net Salvage Accruals .........................................................................7

c) TURN’s Net Salvage Proposals, When Considered With Its Life Proposals, Take Us Backwards, Not Even Gradually Forwards ...................9

d) Compared To The Other Large IOUs in California, There Is Room For—And A Need For—Progress .......................................................9

2. SCE’s Proposal Is Already Gradual .........................................11

a) SCE’s Proposals Are Conservative In That They Only Achieve Accruals At The Level Of Cost SCE Currently Incurs .....................................11

b) Not Adopting Increases Now Will Worsen SCE’s Reserve Position ...............................................12

3. Under-Collections Lead To Higher Rate Base ........................13

III. T&D AVERAGE SERVICE LIVES ...............................................................14

A. Comparison Of Proposals ....................................................................14

B. Testimony Of Dr. Ronald E. White In Response To TURN’s T&D Service Life Proposals .................................................15 R. White


Table Of Contents (Continued)


-ii-

1. Burden Of Proof .......................................................................16

2. Estimation Of Service-Life Statistics.......................................17

C. Account 370: Engineering Considerations Support Retaining Currently Authorized Service Life ......................................27 D. Gunn

1. TURN’s Position ......................................................................27

2. SCE’s Rebuttal .........................................................................27

D. Accounts 369 And 370: Industry Data Does Not Support TURN’s Recommendations .................................................................28

IV. HYDRO DECOMMISSIONING ....................................................................30

A. TURN’s And Cal Advocates’ Positions ..............................................30

B. SCE’s Rebuttal .....................................................................................30 J. Rankin

1. Continued Deferral Of Recovery Places A Burden On Future Customers ...............................................................32 D. Gunn

2. Broad Group Depreciation Provides A Common Reserve For All Hydro Assets .................................................33

3. Customers Are Protected From Over/Under-Collection .................................................................................33

V. GENERATION DECOMMISSIONING .........................................................34

A. TURN’s Position ..................................................................................34

B. SCE’s Rebuttal .....................................................................................34

VI. PERRIS DECOMMISSIONING .....................................................................39

A. TURN’s Position ..................................................................................39

B. SCE’s Rebuttal .....................................................................................40 J. Rankin

1. TURN Uses Hindsight To Claim That The Early Retirement Of Perris Was Foreseeable From The Start ..........................................................................................41


Table Of Contents (Continued)


-iii-

a) TURN Impermissibly Relies On Hindsight .................41

b) SCE’s Investment Decisions Were Prudent .................43

(1) The Lease Terms Regarding Removal Of The Panels Were Consistent With The Terms That Could Be Reasonably Expected For A Commercial Lease ........................................44

(2) SCE Acted Prudently In Decommissioning The Perris SVPV Facility .............................................................45

2. Treating Perris As Mass Property Is Consistent With Standard Practice U-4 .....................................................45 D. Gunn

3. TURN’s Proposal Penalizes SCE’s Investors After Customers Reaped Enduring Benefits From The SPVP Program .........................................................................47

VII. OTHER GENERATION .................................................................................49

A. Palo Verde Interim Retirements ...........................................................49

1. TURN’s Position ......................................................................49

2. SCE’s Rebuttal .........................................................................49

B. Fuel Cell Generation ............................................................................50

1. TURN’s Position ......................................................................50

2. SCE’s Rebuttal .........................................................................50

a) Decommissioning Both Facilities Is Likely .................51

b) 35% Contingency Is Appropriate For Preliminary Cost Estimates ..........................................51

Appendix A Select Data Request Responses

Appendix B Workpapers in Support of SCE’s Rebuttal Testimony

1

I. 1

INTRODUCTION 2

For this 2021 GRC, SCE proposes a $226 million increase in depreciation expense based on the 3

results of a comprehensive depreciation study. As in prior rate cases, the majority of the requested 4

increase is to recover the future cost of removal (hereinafter net salvage) for transmission and 5

distribution (T&D) assets. The currently adopted net salvage rates have been in place for two GRC 6

cycles and are stale. They have not kept pace with the level of costs SCE currently incurs, so making an 7

adjustment to net salvage rates for at least a handful of accounts where current accruals are significantly 8

below today’s level of cost should not be delayed one more cycle. Also included in this rate case is a 9

new proposal to begin recovering $30 million of annual depreciation expense for future 10

decommissioning of small hydro facilities. The remainder of SCE’s depreciation request reflects more 11

modest refinements to estimated service lives and cost of removal estimates for generation assets. Table 12

I-1, below, summarizes each party’s proposed changes from the currently authorized depreciation rates. 13

Table I-1 Depreciation Proposal Comparison

Annual Depreciation Expense based on YE 2018 CPUC Plant Balances (in millions of dollars)

TURN proposes to reduce T&D net salvage to limit the customer bill impact by deferring net 14

salvage to future rate cases, consistent with the concept of “gradualism.” Cal Advocates takes a similar 15

approach, but provides additional evidence for two accounts. Chapter II of SCE’s rebuttal testimony 16

addresses why its T&D net salvage proposal achieves the proper balance between being mindful of 17

Line SCE CalPA ∆ from TURN ∆ from Rebuttal

No. Item Proposed Proposed SCE Proposed SCE Chapter

A B C D E=D‐C F G=F‐C H

1. Authorized Depreciation Expense $1,604 $1,604 ‐‐ $1,604 ‐‐

2. T&D Net Salvage 199 60 (139) 50 (149) II3. T&D Life (15) (15) ‐‐ (59) (43) III4. Hydro Decommissioning 30 7 (23) 10 (19) IV5. Other Generation 2 2 ‐‐ (0) (2) V-VII6. General and Intangible 12 12 ‐‐ 12 ‐‐

7. Total Proposed 1,830 1,669 (162) 1,617 (214)

8. Change from Authorized 227 65 (162) 13 (214)

2

abrupt rate increases while still making progress towards setting more fair and accurate net salvage rates 1

so that we are not overburdening future generations of customers. 2

TURN alone also proposes a number of T&D service life extensions, but they go too far given 3

what the data show. SCE’s life proposal in this rate case continues life-lengthening proposals in the prior 4

two rate cases for T&D assets, resulting in a decrease in depreciation expense; going further than that is 5

not warranted. Critiques of TURN’s service life proposals are presented in Chapter III by Dr. Ronald E. 6

White with supplemental testimony on engineering insights and industry comparison data presented by 7

SCE. 8

SCE’s rebuttal to TURN and Cal Advocates’ hydro decommissioning proposals benefits from 9

additional testimony from SCE’s generation experts that can be found in Chapter IV, part B. 10

Similarly, Chapters VI and VII benefit from additional testimony from SCE’s generation experts for 11

TURN’s Perris and fuel cell decommissioning proposals.12

3

II. 1

T&D NET SALVAGE 2

SCE’s detailed net salvage analysis reveals that, for many accounts, the currently authorized net 3

salvage rates are insufficient to collect removal costs at the level SCE incurs today. As a threshold 4

matter, net salvage rates should be sufficient to collect future cost of removal when the assets have 5

retired years and decades from now. As the Commission stated in SCE’s 2009 GRC, “The net salvage 6

includes the cost of removal of the asset at the end of its useful life as well as any salvage value the asset 7

may have at that time.”1 SCE’s data shows that the current net salvage rates fail to accrue enough to 8

cover retirement of the assets on today’s books even at today’s level of costs, i.e., not even accounting 9

for inevitable cost increases for future removal. This is not a tenable or responsible trajectory. 10

Ninety percent of SCE’s proposal is designed to remedy the pace of under-collection for T&D net 11

salvage. Specifically, for accounts 365 to 368, SCE’s recommended $179 million increase closes the gap 12

between the authorized levels and the level of current removal costs. SCE recognizes that its requested 13

net salvage increase is significant, but adopting net salvage rates lower than SCE’s proposal would result 14

in exacerbating the troubling pattern of under-collections. These under-collections will inevitably need 15

to be paid by future customers. Delaying for yet another GRC amplifies this problem and makes 16

progress even more difficult. Table II-2, below, summarizes SCE, TURN, and Cal Advocates’ proposals 17

on an account-by-account basis. 18

1 D.09-03-025, p. 175.

4

Table II-2 T&D Net Salvage Proposals Change in Present Accruals

(in $ millions)

A. TURN’s And Cal Advocates’ Positions 1

TURN does not offer an alternative net salvage analysis based on evidence or data about the 2

future cost of removal. Its expert depreciation witness agrees with SCE’s expert witness that “[t]he data 3

provided by the Company indicate that the net salvage rates for the 11 accounts at issue should 4

increase.”2 Without financial analysis or bill impact testimony, TURN’s witness proposes to adopt only 5

25% of SCE’s net salvage proposal in order to “help mitigate the economic impact to customers in light 6

of a potential rate increase while not financially harming the Company.”3 The 25% cap on the proposed 7

increase appears to be based on the same formula the Commission adopted in PG&E’s 2014 GRC.4 8

2 Exhibit TURN-09, p. 42, lines 5-8.

3 Id., p. 43, lines 3-4.

4 Id., p. 41, lines 9-14.

FERC

Acct Description Auth. SCE CalPA TURN SCE CalPA ∆ from SCE TURN ∆ from SCE

A B C D E F=C+25%(D‐C) G H I=H‐G J K=J‐G

Transmission

352 Structures & Improvements ‐35% ‐35% ‐35% ‐35% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

353 Station Equipment ‐15% ‐15% ‐15% ‐15% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

354 Towers & Fixtures ‐60% ‐80% ‐80% ‐65% 0.3 0.3 ‐‐ 0.1 ‐0.2

355 Poles & Fixtures ‐72% ‐90% ‐90% ‐77% 3.3 3.3 ‐‐ 0.9 ‐2.5

356 OH Conductors & Devices ‐80% ‐100% ‐100% ‐85% 1.4 1.4 ‐‐ 0.3 ‐1.1

357 UG Conduit 0% 0% 0% 0% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

358 UG Conductors & Devices ‐15% ‐30% ‐30% ‐19% 1.3 1.3 ‐‐ 0.3 ‐0.9

359 Roads & Trails 0% 0% 0% 0% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

Distribution

361 Structures & Improvements ‐25% ‐40% ‐40% ‐29% 2.2 2.2 ‐‐ 0.6 ‐1.7

362 Station Equipment ‐25% ‐40% ‐40% ‐29% 7.4 7.4 ‐‐ 1.6 ‐5.7

364 Poles, Towers & Fixtures ‐210% ‐210% ‐210% ‐210% 0.0 0.0 ‐‐ ‐‐ ‐‐

365 OH Conductors & Devices ‐115% ‐190% ‐130% ‐134% 29.8 5.9 ‐24.0 7.6 ‐22.3

366 UG Conduit ‐30% ‐80% ‐45% ‐43% 26.0 7.9 ‐18.2 6.0 ‐20.1

367 UG Conductors & Devices ‐60% ‐100% ‐70% ‐70% 68.1 16.9 ‐51.2 16.9 ‐51.2

368 Line Transformers ‐20% ‐50% ‐25% ‐28% 54.8 9.3 ‐45.6 14.8 ‐40.1

369 Services ‐100% ‐100% ‐100% ‐100% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

370 Meters ‐5% ‐5% ‐5% ‐5% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

371 Install on Customer Premises ‐100% ‐100% ‐100% ‐100% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

373 Street Lighting ‐30% ‐50% ‐50% ‐35% 4.4 4.4 ‐‐ 1.1 ‐3.3

General Buildings

390 Structures & Improvements ‐10% ‐10% ‐10% ‐10% ‐‐ ‐‐ ‐‐ ‐‐ ‐‐

Total Proposed 199.2 60.2 ‐138.9 50.1 ‐149.1

Net Salvage Rates ∆ to Present Accruals

5

Cal Advocates recommends a similar reduction from SCE’s proposed increase, also in the name of 1

gradualism, but offers various formulas as the basis of their recommendation. 2

B. SCE’s Rebuttal 3

$179 million of SCE’s requested increase is concentrated in just four accounts, representing 90% 4

of the overall requested increase in depreciation expense. SCE’s proposal in these accounts already 5

reflects a gradual increase towards the level of net salvage SCE will incur in the future. That is because 6

not adopting SCE’s requested increase results in customers paying at a rate that would be insufficient to 7

pay for cost of removal even at today’s costs. Over the course of several rate case cycles, the adopted net 8

salvage rates have been set below the levels justified in corresponding depreciation studies, leading SCE 9

to an unenviable position of having to request material increases in its depreciation expense for net 10

salvage just to be able to allocate costs at a level consistent with what it is incurring today. 11

1. SCE’s Depreciation Rate History Gives Context For The Need To Increase Net 12

Salvage Rates 13

Although this chapter is focused primarily on SCE’s net salvage proposal, it is important 14

to consider net salvage rates together with average service lives to get a fuller picture of the amount of 15

depreciation expense customers ultimately pay. SCE’s current composite depreciation rate proposal 16

(inclusive of its net salvage and average service life proposals) is 4.14%. This rate is approximately the 17

same as what the Commission authorized rates in the 2006 and 2009 GRCs (4.16% and 4.19%, 18

respectively). Since the 2009 GRC, the overall depreciation rates have decreased, to the point where the 19

3.52% rate adopted in the 2018 GRC brought SCE to the lowest point in at least 20 years. This data 20

alone is concerning, especially given TURN’s expert witness’s acknowledgement that “increasing labor 21

costs associated with asset removal combined with the fact that original costs remain the same have 22

contributed to increasing negative net salvage over time.”5 23

a) Historically, The Commission Has Accepted Longer Service Lives 24

The Commission has been willing to accept the additional evidence presented by 25

SCE and intervenors in support of longer average service lives over the last few GRCs which, all other 26

things equal, has reduced depreciation expense. However, the Commission has been reluctant to adopt 27

correspondingly more negative net salvage rates. Some of the factors on which the Commission has 28

5 Exhibit TURN-08, p. 40, line 8-11.

6

relied include economic/rate impact considerations,6 requests for evidence presented in a way that relies 1

more on data than judgment,7 and, most recently, the opposite concern.8 Even for other IOUs, the 2

Commission invokes gradualism to moderate increases that are otherwise justifiable in order to limit the 3

impact of this change on current customer rates. For example, in D.14-08-032 from PG&E’s 2014 GRC, 4

the Commission concluded that “in evaluating whether a proposed increase reflects gradualism . . . we 5

believe the more appropriate measure is how the change affects customer retail rates.”9 6

The effect of adopting longer service life proposals—but looking skeptically at 7

proposed increases to net salvage rates—together have had the perhaps unintended consequence of 8

lowering overall (composite) depreciation rates even if a gradual aggregate increase was warranted. 9

6 D.09-03-025. See also 2012 GRC, D.12-11-051(acknowledging that “[i]n SCE’s 2009 GRC, the Commission

agreed with DRA that retaining previously adopted NSR[s] would keep customer rates lower at a time of economic downturn, without impacting safe and reliable service” and concluding, in part, in the 2012 GRC that (a) “due to the large dollars at stake, and the wide range of possibilities, we prefer to be conservative in adjusting net salvage ratios, rates or accruals” and “We review SCE’s proposed salvage rates for reasonableness, as well as the resulting impact on revenue requirement.”) (Emphasis added.)

7 D.15-11-021. “…we direct SCE to provide considerably more detail in support of its net salvage proposals.” p. 398.

8 D.19-05-020. “Notably missing from this explanation is that expert judgement is a required element of the traditional analysis, Standard Practice U-4.” pp. 318-319.

9 D.14-08-032. p. 598.

7

Figure II-1 Depreciation Rates Have Declined Over Time10

2006 to 2018 GRC

b) Lengthening Service Lives Has A Simultaneous Effect On Net Salvage 1

Accruals 2

When considering the amount of depreciation rate increases to adopt, it is helpful 3

to understand the interrelated effect of simultaneously lengthening service lives while leaving net 4

salvage rates unchanged. When net salvage rates are negative, average service life extensions result in 5

even more significant reductions to depreciation expense. This is because both the original cost to install 6

the asset and the future cost to remove it are allocated over the average service life. A 10 percent 7

increase in the service life results in a more than 10 percent reduction in depreciation expense. If the 8

goal of depreciation were just to recover the original investment, then lengthening the service lives 9

would reduce annual depreciation expense by about the same proportion that the service life is changed. 10

But because the goal of depreciation is to also accrue for the future cost of removal, extensions to 11

average service life reduce accruals for net salvage unless there is a corresponding increase to net 12

salvage rates. TURN’s witness alludes to this by stating, “Increasing labor costs associated with asset 13

removal combined with the fact that original costs remain the same have contributed to increasing 14

10 See Appendix B, “SCE, Cal Advocates, and TURN T&D Depreciation Proposals,” pp. B11 to B14.

Depreciation Rate4.68% 4.70%

4.50%

4.22%

3.95%4.14%

4.16% 4.19%

3.77% 3.73%

3.52%

2006 GRC 2009 GRC 2012 GRC 2015 GRC 2018 GRC 2021 GRC

SCE Proposed GRC Authorized

3.50% ‐ TURN

3.68% ‐ Cal Advocates

‐ SCE

8

negative net salvage over time.”11 In other words, as assets age and service lives lengthen, more negative 1

net salvage rates (and higher depreciation expense) can be expected. As the Commission noted, “we find 2

that increasing the [average service life] of assets decreases the annual depreciation expense accrual in 3

the sense that costs are stretched out over a longer period of time. However, this also increases 4

depreciation expense because the longer end of life results in [more negative net salvage].”12 In a rate 5

case where the Commission adopts longer service lives, there is a key opportunity to apply the reduction 6

in depreciation expense to narrow the gap in under-collected net salvage. In other words, the last few 7

rate cases presented opportunities where the Commission could have adopted more significant increases 8

in net salvage rates as it adopted longer service lives, all without significantly impacting overall rates. 9

Instead, as shown in Figure II-2, below, Commission paired adoption of longer 10

service lives (generally in line with what SCE proposed) with adoption of stagnated net salvage rates, 11

leading to a growing and distressing gap between recorded costs and GRC-authorized costs for net 12

salvage. 13

Figure II-2 Adopted Changes in Average Service Lives and Net Salvage Rates13

2006 to 2018 GRC

To make meaningful progress that would lead to an upturned curve in Figure II-1 14

and a smaller disparity in Figure II-2, the Commission in this GRC should adopt SCE’s net salvage rate 15

proposals. 16


12 SDG&E 2019 GRC Decision, D.19-09-051, pp. 621-622.

13 See Appendix B, “SCE’s Authorized and Proposed T&D Lives and Net Salvage,” pp. B15 to B16.

Average Service Lives Net Salvage Rates

‐51% ‐51% ‐53%‐62% ‐62%

‐80%‐92%

‐108%

‐133%

‐149%

‐66%‐66% ‐58%

‐72% ‐76%‐87%


GRC Authorized 10‐yr Avg. Recorded SCE Proposed

38

43

4850

39 3941

44

49


9

c) TURN’s Net Salvage Proposals, When Considered With Its Life Proposals, 1

Take Us Backwards, Not Even Gradually Forwards 2

By contrast, although TURN’s witness refers to gradualism as though at least 3

some progress were being made in the right direction,14 the aggregate effect of TURN’s proposal would 4

keep SCE on a downward trajectory of composite depreciation rates. That is, when considered at an 5

aggregate level, TURN proposes increases to average service lives while simultaneously stopping short 6

of adopting more negative net salvage rates despite what the data show. The combined effect is to 7

decrease SCE’s overall depreciation expense, not “gradually” move towards an increase. TURN’s 8

recommended T&D service life extensions result in an overall reduction of $58 million of depreciation 9

expense. By selectively invoking gradualism, TURN’s T&D net salvage recommendation results in only 10

a $50 million increase in depreciation expense.15 Combining the two, TURN’s proposal results in an 11

overall $8 million decrease in depreciation expense. Given the gap between SCE’s currently authorized 12

net salvage rates and the level of costs SCE current incurs, a gradual proposal should achieve at least the 13

same level of depreciation expense that is currently authorized. Even that would be unsupported by the 14

data because, by TURN’s expert’s own admission, the net salvage rates should be more negative.16 15

If TURN had proposed a gradualism cap of 30% for net salvage, for example, 16

versus the 25% it proposed, the overall composite depreciation rate would have stayed at approximately 17

the same level as currently authorized. Proposing a gradualism cap of 50% would make even more 18

meaningful progress towards net salvage rates that result in intergenerational equity, with a fairly 19

modest increase of approximately $40 million when combined with TURN’s service life proposals.17 20

d) Compared To The Other Large IOUs in California, There Is Room For—21

And A Need For—Progress 22

For reference purposes, and to place SCE’s request within a broader context, 23

below is a comparison of the authorized depreciation rates of the California IOUs and the proposals 24

presented in this rate case. SCE’s authorized rates are the lowest in the state, and TURN’s and Cal 25

14 Exhibit TURN-08, p. 43.

15 See Appendix B, “Alternative Gradualism Scenarios for Net Salvage,” pp. B5 to B10.

16 Exhibit TURN-08, pg. 42, lines 7-8 (“The data provided by the Company indicate that the net salvage rates for the 11 accounts should increase.”).

17 See Appendix B, “Alternative Gradualism Scenarios for Net Salvage,” pp. B5 to B10.

10

Advocates’ proposals continue to keep SCE from making significant progress towards rate levels that 1

collect the increasing costs of removal. 2

Figure II-3 Comparison of California IOU Composite Depreciation Rates

Currently Authorized/Pending Authorization18

As shown in Figure II-3, above, SCE currently has the lowest authorized T&D 3

composite depreciation rate among the three California IOUs. The gap between the rates is significant. 4

Moving from SCE’s currently authorized composite rate to one that is closer to the other IOUs’ would 5

require collection of approximately $100 million19 of annual depreciation expense that could help 6

address SCE’s current under-accruals for future net salvage. 7

18 The PG&E bar is the composite rate proposed in a pending Article 12 settling. See Appendix B, “PG&E and

SDG&E Authorized/Pending Authorization Depreciation Rates,” pp. B17 to B19.

19 See Appendix B, “Comparison of California IOU Authorized Depreciation Rates,” pp. B20 to B21.

3.52%

3.83%

3.88%

SCE SDG&E PG&E

(2018 GRC) (2019 GRC) (2020 GRC)

11

2. SCE’s Proposal Is Already Gradual 1

a) SCE’s Proposals Are Conservative In That They Only Achieve Accruals At 2

The Level Of Cost SCE Currently Incurs 3

SCE’s net salvage requests for FERC Accounts 365-368 are large, but necessary 4

to get to approximately the level of costs at which SCE experiences in today’s dollars, as shown in Table 5

II-3, below. 6

Table II-3 Unit Cost Comparison Table

(in dollars)

As shown in Table II-3 above, SCE recently incurred $4.38 to remove each foot 7

of conductor in Account 365 – Overhead Conductor. However, SCE’s currently authorized rate 8

of -115% would accrue only $2.68 per foot of conductor for future net salvage over the service life. 9

Leaving net salvage rates unchanged would leave SCE $1.70 shy of its removal costs for each of the 10

millions of feet of conductor that are currently in service. SCE’s current proposal of -190% for this 11

account will collect $4.42 per foot of conductor by the time the asset retires from service. Based on 12

Standard Practice U-4, the $4.32 will fall short of the future removal costs of these assets due to 13

inflation, but the proposal at least recovers amounts at or close to the level SCE experiences today. 14

The same circumstances as discussed above also drive the recommendations SCE 15

is making for accounts 366-368. That is, adopting SCE’s proposal for these accounts sets accruals at 16

levels approximately the same as the level SCE experiences today, and hopes to avoid consequences 17

365 366 367 368

OH Conductor Conduit UG Conductor Transformer

Authorized COR $2.68 $3.36 $7.07 $772

Recent Cost to Remove $4.38 $10.68 $12.68 $1,609

Difference ($1.70) ($7.32) ($5.61) ($837)

TURN Proposed $3.12 $4.82 $8.25 $1,081


Difference ($1.26) ($5.86) ($4.43) ($528)

SCE Proposed $4.42 $8.96 $11.79 $1,931


Difference $0.04 ($1.72) ($0.89) $322

12

resulting from the large gap currently authorized. Problems with large under-accruals are most apparent 1

in Account 368 - Line Transformers which is discussed in further detail, below. 2

b) Not Adopting Increases Now Will Worsen SCE’s Reserve Position 3

If increases in net salvage accruals continue to be deferred to future rate cases, 4

SCE’s overall reserve position will continue to worsen. Account 368 – Line Transformers – 5

demonstrates this issue most clearly. In a typical asset life cycle, SCE would collect depreciation 6

expense to cover the cost of the future retirement of the asset and the reserve would show a positive 7

balance. However, Account 368 has a negative reserve balance, meaning that SCE has spent more to 8

remove assets than it has recovered in rates. Future accruals need to recover amounts for future recovery 9

as well as for assets that have already been retired. TURN and Cal Advocates’ gradualism proposals 10

would exacerbate this problem by creating an even more negative reserve balance at the end of the 11

current rate case cycle, as shown in Table II-4, below. 12

Table II-420 Comparison of 2024 Cost of Removal Reserve Balances

Account 368 – Line Transformers (in millions)

SCE’s proposal takes the current negative reserve balance into consideration and 13

makes progress towards a less negative balance. SCE does not oppose the use of gradualism, however 14

the change to the authorized rate should make progress toward a reserve that has collected for the future 15

instead of borrowing against it. Although under-accruals are most apparent in this account due to the 16

negative reserve balance, this issue exists in the accounts that contain SCE’s major net salvage 17

proposals. If rates continue to be set below the level that SCE is currently incurring to remove its assets, 18

then the gap between SCE’s recorded reserve balances and where the reserve balance should be will 19

continue to grow. 20

20 See Appendix B, “Account 368 Debit Reserve Forecast,” pp. B22 to B23.

PartyRecorded YE 2018

Proposed YE 2024

∆ in Reserve

TURN (150) (221) (71)CalPA (150) (243) (93)SCE (150) (59) 91

13

3. Under-Collections Lead To Higher Rate Base 1

If depreciation rates continue to be set too low, the overall level of rate base is higher 2

than it otherwise would have been. For multiple rate cases, SCE’s proposed net salvage rate increases 3

have been delayed for policy or other reasons. The cumulative effect of these reductions to SCE’s 4

proposal now sets depreciation rates 16% below the level that was authorized as recently as SCE’s 2009 5

GRC. Each year the depreciation expense rates are set at a level lower than is otherwise justified, the 6

rate base inherited by future customers is higher than it otherwise would have been. That is, because 7

depreciation expense is simultaneously charged to expense and accumulated depreciation, the level of 8

depreciation has a direct impact on the level of rate base as shown in Table II-5, below. 9

Table II-5 Depreciation Expense Impact on Rate Base and Revenue Requirement

Decisions about the overall level of net salvage increases should take into account the 10

longer-term consequences to rate base, the return on rate base, and associated income tax expense. 11

Long-term deferrals of higher net salvage accruals will not only push the burden to collect these costs to 12

future customers, but will also be more difficult to make up in future periods because of the higher rate 13

base. SCE’s proposal strikes the right balance between the need to increase the accrual for future net 14

salvage on one hand, and being mindful of customer rates on the other and should be adopted. 15

14

III. 1

T&D AVERAGE SERVICE LIVES 2

A. Comparison Of Proposals 3

Cal Advocates does not dispute any of SCE’s T&D average service life proposals. This chapter 4

presents SCE’s rebuttal to TURN’s Average Service Life proposals for T&D assets. Section B is 5

presented by Dr. Ronald E. White. 6

For T&D average service lives, the Commission is largely being asked to decide between SCE’s 7

disciplined hazard rate-driven actuarial life analysis provided by Dr. Ronald E. White, and the more 8

rudimentary visual curve fitting performed by TURN’s witness. For accounts 369 and 370, TURN 9

proposes the largest change with the least compelling evidence, so SCE provides additional testimony in 10

Section C describing engineering judgment and industry data to defend its proposals. 11

15

Table III-6 T&D Service Life Proposals Change in Present Accruals

(in $ millions)

B. Testimony Of Dr. Ronald E. White In Response To TURN’s T&D Service Life Proposals 1

Q. PLEASE SUMMARIZE YOUR RESPONSE TO MR. GARRETT’S 2

TESTIMONY ADDRESSING THE 2019 SERVICE–LIFE STUDY 3

CONDUCTED BY FOSTER ASSOCIATES FOR SCE. 4

A. The recurring theme throughout Mr. Garrett’s testimony addressing service lives for eight plant 5

accounts is: “… the Company has [not] met its burden of proof by making a convincing showing 6

FERC

Acct Description SCE TURN ∆ from SCE

A B F G H = F‐G

Transmission

352 Structures & Improvements L 1.0 55 L 1.0 55 L 0.5 58 0.0 ‐0.5 ‐0.6

353 Station Equipment R 0.5 45 L 0.5 45 L 0.5 45 0.3 0.3 ‐‐

354 Towers & Fixtures R 5.0 65 R 5.0 65 R 5.0 69 0.0 ‐0.1 ‐0.1

355 Poles & Fixtures SC 65 SC 65 SC 65 1.3 1.3 ‐‐

356 OH Conductors & Devices R 3.0 61 R 3.0 61 R 3.0 65 0.2 ‐0.5 ‐0.7

357 UG Conduit R 3.0 55 R 3.0 55 R 3.0 55 0.1 0.1 ‐‐

358 UG Conductors & Devices S 1.0 45 S 1.0 45 S 1.0 45 0.5 0.5 ‐‐

359 Roads & Trails R 5.0 60 R 5.0 60 R 5.0 60 0.0 0.0 ‐‐

Distribution

361 Structures & Improvements L 0.5 50 L 0.5 55 L 0 58 ‐1.5 ‐2.6 ‐1.2

362 Station Equipment L 0.5 65 S ‐0.5 65 L 0 67 ‐0.5 ‐2.7 ‐2.2

364 Poles, Towers & Fixtures R 1.0 55 R 1.0 55 R 1.0 55 0.9 0.9 ‐‐

365 OH Conductors & Devices R 0.5 55 R 0.5 55 R 0.5 55 3.1 3.1 ‐‐

366 UG Conduit R 3.0 59 R 3.0 59 R 2.5 64 1.7 ‐4.3 ‐6.0

367 UG Conductors & Devices R 1.5 43 L 1.0 47 L 1.0 47 ‐16.9 ‐16.9 ‐‐

368 Line Transformers S 1.5 33 S 1.5 33 S 1.5 33 0.4 0.4 ‐‐

369 Services R 1.5 55 R 1.5 55 R 1.5 60 0.7 ‐4.5 ‐5.2

370 Meters R 3.0 20 R 3.0 20 R 3.0 30 ‐1.8 ‐29.0 ‐27.2

371 Install on Customer Premises R 1.5 55 R 1.5 55 R 1.5 55 ‐0.1 ‐0.1 ‐‐

373 Street Lighting L 1.0 48 L 0.5 50 L 0.5 50 ‐1.1 ‐1.1 ‐‐

General Buildings

390 Structures & Improvements R 0.5 45 SC 50 SC 50 ‐2.8 ‐2.8 ‐‐

Total Proposed ‐15.3 ‐58.5 ‐43.2

∆ to Present Accruals

Auth.

C

SCE

D

TURN

E

Life Parameters

16

that its proposed depreciation rates are not excessive.”21 It is illogical for Mr. Garrett to claim if a 1

company cannot prove its rates are not excessive, then his lengthened service lives are correct 2

and should be approved. 3

After creating his own “burden of proof” standard, Mr. Garrett attempts to discredit the 2019 4

service life study conducted for SCE by showing graphs of survivor curves fitted to irregular 5

datapoints and claiming his selected curves fit the observed data better for every account than 6

curves derived in the 2019 study.22 7

It will be demonstrated in this rebuttal testimony that Mr. Garrett is ill-equipped to challenge 8

the discipline and reasoning presented in the 2019 service life study supporting recommended 9

service life statistics. Service lives recommended in the 2019 study are reasonable and well 10

supported by narratives and rigorous analyses. 11

1. Burden Of Proof 12

Q. WHAT IS THE “BURDEN OF PROOF” STANDARD CLAIMED BY MR. 13

GARRETT AS THE “STANDARD BY WHICH REGULATED UTILITIES 14

ARE ALLOWED TO RECOVER DEPRECIATION EXPENSE”?23 15

A. According to Mr. Garrett, the standard was enunciated by the Supreme Court in Lindheimer v. 16

Illinois Bell Telephone Co. as follows: 17

[T]he Company has the burden of proof of making a convincing showing that the 18 amounts it has charged to operating expenses for depreciation have not been 19 excessive. That burden is not sustained by proof that its general accounting system 20 has been correct. The calculations are mathematical, but the predictions underlying 21 them are essentially matters of opinion.24 22

21 Exhibit TURN-08 (Garrett Direct Testimony) at p. 2, l. 14-17; p. 6, l. 14-16; p. 19, l. 12-13; p. 34–l. 9 ff; p.

44, l. 2–5.

22 Id. at p. 12, l. 1–3.

23 Id. at p. 6, l. 1–2.

24 Id. at p. 6, l. 9–13.

17

Q. IS THIS YOUR UNDERSTANDING OF THE BURDEN A REGULATED 1

UTILITY MUST SUSTAIN BEFORE BEING ALLOWED TO RECOVER 2

DEPRECIATION EXPENSE?25 3

A. No. It is my understanding that Lindheimer v. Illinois Bell Telephone Co., 292 U.S. 151, 169 4

(1934) was a case arising from an initial appeal of an Illinois Commerce Commission service 5

rate order that Illinois Bell claimed would be confiscatory if enforced. The opening phrase of the 6

language omitted by Mr. Garrett in his quotation from the case reads: 7

Confiscation being the issue, the Company has the burden of proof making a 8 convincing showing that the amounts it has charged to operating expenses for 9 depreciation have not been excessive. (Emphasis added). 10

Confiscation is neither an issue here nor was it considered in the estimation of service lives 11

recommend in the 2019 service life study. 12

The Court decreed that amounts charged to operating expense and credited to the 13

depreciation reserve are “excessive” to the extent that ratepayers are required to provide capital 14

contributions for additional plant and equipment upon which a utility expects a return. The Court 15

did not create a new standard “… by which regulated utilities are allowed to recover depreciation 16

expense” nor did the Court decree that “… the Company bears the burden to show that its 17

proposed depreciation rates are not excessive, and in turn, that its service lives are not 18

underestimated.”26 No regulated utility could meet such a standard. 19

2. Estimation Of Service-Life Statistics 20

Q. WHAT IS YOUR UNDERSTANDING OF MR. GARRETT’S CRITICISM OF 21

SERVICE LIFE STATISTICS RECOMMENDED IN THE 2019 SCE 22

SERVICE LIFE STUDY? 23

A. According to Mr. Garrett, “… for every account [to which he proposes service life adjustments] 24

the Iowa curves proposed by the Company fit the data so poorly that the Iowa curves [he 25

25 The testimony below reflects Dr. White’s opinion about the import of the Lindheimer case. In legal briefing,

SCE will set forth the CPUC’s longstanding burden of proof for applicants in rate cases, preponderance of evidence.

26 Id. at p. 19, l. 12–13.

18

proposes] provide a better fit to the observed data for every account, no matter which portion of 1

the OLT curve is analyzed.”27 2

Q. HOW DID MR. GARRETT ESTIMATE SERVICE LIVES FOR THESE 3

ACCOUNTS? 4

A. First, contrary to his terminology, Mr. Garrett did not use “… an actuarial life analysis method 5

called the retirement rate method.”28 The retirement rate method is one of at least five available 6

methods for constructing an observed life table. Statistical life analysis techniques are used to 7

graduate or smooth sample estimates of probabilities derived in an observed life table from 8

which service-life descriptors of the parent population can be inferred. The retirement rate 9

method is not an “actuarial method” of life analysis; it is a method for constructing a life table 10

against which actuarial techniques are applied. 11

In his analysis of each of the eight disputed plant accounts, Mr. Garrett provides a graph 12

showing: a) observed proportions surviving; b) his recommended Iowa curve fitted to the 13

observed data points; and c) the curve recommended in the 2019 depreciation study. From a 14

visual comparison of the fitted curves, Mr. Garrett reports that his selected curves appear to 15

provide a better fit to the observed data points. Mr. Garrett then claims to have confirmed his 16

visual inspection with “mathematical” curve fitting. The “mathematical” method used by Mr. 17

Garrett is nothing more, however, than a computerized version of his visual curve fitting 18

technique. 19

Q. PLEASE EXPLAIN THE ORIGIN OF VISUAL CURVE FITTING. 20

A. Visual curve-fitting was employed long before the advent of computers. Prior to the availability 21

of mechanized systems, a series of survivor proportions obtained from an observed life table was 22

typically plotted on graph paper and overlaid with correspondingly scaled graphs of survivor 23

curves such as the Iowa-type curves. The type curves were drawn with various average service 24

lives such that both the dispersion and average service life of the observed proportion surviving 25

could be selected from a visual inspection of which curve appeared to best “fit” the data. 26

27 Id. at p. 11, l. 19 ff.

28 Id. at p. 9, l. 6–7.

19

Computerized versions of the same procedure have since replaced manual plotting of points 1

and fitting to survivor curves. Type curves (e.g., Iowa) used in such an analysis can be scaled to 2

any average service life, thereby providing a description of both the dispersion (i.e., distribution 3

of retirements over time) and average service life exhibited by the fitted data. The “best fitting” 4

curve, however, remains decided by a visual inspection of which curve seems to fit the data 5

points best. 6

Visual curve fitting is an application of descriptive statistics used to summarize and describe 7

data through numerical calculations, graphs or tables. It is not an actuarial method of life 8

analysis. 9

Q. WHAT METHOD DOES FOSTER ASSOCIATES USE IN CONDUCTING 10

STATISTICAL SERVICE-LIFE STUDIES? 11

A. The statistical method used by Foster Associates is an application of inferential statistics. Hazard 12

rates are graduated or smoothed rather than “visually” fitting data points to a survivor curve. This 13

method draws inferences and predictions about population service-life parameters based on an 14

analysis of samples drawn from the parent population. 15

Projection lives and projection curves are population parameters “inferred” from a statistical 16

analysis of the underlying forces of retirement described by probability distributions. 17

A projection life is an estimate of mean service-life of the population from which retirements are 18

observed as a random sample. Probability distributions used in estimating service-life statistics 19

are called survival functions. The four survival functions are depicted in Figure III-4, below. 20

The associated probabilities are defined as follows: 21

1. Probability Density Function: The probability that a unit of property will be 22

retired between ages t1 and t2. 23

2. Cumulative Distribution Function: The probability that a unit of property is 24

retired before age t. 25

3. Survivorship Function: The probability that a unit of property remains in service 26

beyond age t. 27

4. Hazard Function: The probability of nearly immediate retirement from service for 28

a unit of property known to be in service at age t. 29

20

Figure III-4 Survival Functions

The fundamental probability distribution of interest in estimating the service life of 1

industrial property is the hazard function. This function, which is also used in reliability theory, 2

describes the conditional probability of retirement (called a hazard rate) during an age interval 3

given survival to the beginning of the interval. So, for example, the probability that plant that has 4

been in service, say for 5 years, will be retired during the 6th year is a conditional probability of 5

retirement. In other words, the probability is conditioned upon having achieved an age of 5 years. 6

The objective of a statistical analysis of plant retirements is to identify the form of an 7

equation that best describes the conditional probabilities of retirement, where the form of the 8

equation is dictated by the underlying forces of retirement. 9

Polynomials are used to estimate the conditional probabilities of a hazard function. 10

A polynomial can then be transformed into a survivorship function and numerically integrated to 11

obtain an estimate of the projection life of a plant category. Observed proportions surviving are 12

then fitted by a weighted least-squares procedure to the Iowa-curve family—using the projection 13

21

life derived from the polynomial hazard function—to obtain a mathematical description or 1

classification of the dispersion characteristics of the data. The only purpose of fitting to Iowa 2

curves using the estimated projection life is to describe forces of retirement with survivor curves 3

more familiar to users of Iowa–type curves than curves described by the coefficients of a 4

polynomial. Absent an understanding of the probabilities associated with survival functions, 5

fitting data points to survivor curves becomes an exercise in finding the best looking graph. 6

Q. ARE THERE OTHER REASONS TO PREFER THE STATISTICAL 7

TECHNIQUES USED BY FOSTER ASSOCIATES OVER THE CURVE 8

FITTING USED BY MR. GARRETT? 9

A. Apart from a difference in the objective (i.e., descriptive vs inferential statistics), the analysis 10

techniques used by Foster Associates overcome a “chaining” problem with curve fitting to 11

observed proportions surviving. Each successive point (i.e., proportion surviving) plotted against 12

a survivor curve is dependent upon the points plotted for prior age-intervals. One or more 13

anomalous or irregular retirements, therefore, will dictate the value of points plotted for 14

subsequent age–intervals. Hazard rates are not “chained.” Survivor curves fitted to observed 15

proportions surviving will often produce misleading estimates of projections lives and inaccurate 16

descriptions of the underlying forces of mortality. 17

In short, the statistical methods used in the 2019 SCE study maximize the informational 18

content of the data and minimize the influence of extraneous events by analyzing the underlying 19

forces of retirement at the level of independent hazard rates.29 This is not to suggest that an 20

analyst must be highly trained in actuarial statistics to conduct a depreciation study. Absent an 21

understanding and use of more powerful statistical techniques, however, life analysis simply 22

becomes an exercise in trying to fit a curve to an oddly shaped array of data points. 23

The statistical techniques used by Foster Associates to conduct technically rigorous 24

depreciation studies are not the same as the “visual curve fitting” employed by Mr. Garrett to 25

lengthen service lives and reduce depreciation rates. 26

29 Although some correlation can be found in the conditional proportion retired, the covariance between the

hazard rates in two age intervals is asymptotically zero. This property has permitted the development of various methods of weighting that reflect serial independence of the disturbance term.

22

Q. HOW DOES THE SCOPE OF THE 2019 SERVICE-LIFE STUDY COMPARE 1

WITH THE SCOPE OF MR. GARRETT’S ANALYSIS? 2

A. Table III-7, below provides a comparison of the activities undertaken in conducting the 2019 3

study compared with the activity performed by Mr. Garrett. 4

Table III-7 Scope of Study

If the Commission is persuaded that Mr. Garrett has uncovered serious flaws in the 2019 5

Service-life study, SCE should be directed to abandon actuarial statistics and conduct future 6

studies using only Mr. Garrett’s “visual/mathematical” curve fitting. 7

Q. SUPPOSE FOSTER ASSOCIATES HAD DERIVED SERVICE LIVES BY 8

MINIMIZING SUM OF SQUARED DIFFERENCES OF CURVES FITTED 9

TO TRUNCATED (T-CUT) OBSERVED PROPORTIONS SURVIVING. 10

WOULD THIS CONFIRM THAT MR. GARRETT SELECTED CURVES 11

AND SERVICE LIVES THAT MINIMIZE SUM OF SQUARED 12

DIFFERENCES? 13

A. No. Table III-8 below provides a comparison between SCE and TURN service lives, curves, and 14

sum of squared (SSQ) differences using T-Cuts reported by Mr. Garrett. 15

23

Table III-8 Fit to Truncated Observed Portions Surviving

It can be observed that SSQ (Column E) is smaller for each account than Mr. Garrett derived 1

(Column H). Service lives and curves are also quite different from his selections. Mr. Garrett did 2

not derive service lives and curves that jointly minimize sum of squared differences. 3

Q. HOW COULD MR. GARRETT EXPLAIN THESE DIFFERENCES? 4

A. He would need to acknowledge that curves and service lives were selected independently. 5

Different parameters would be derived, depending upon the order in which they were selected 6

(i.e., which parameter was selected first). A joint derivation of parameters necessitates first 7

finding a service life for each Iowa curve that minimizes SSQ and then identifying the life/curve 8

combination that produces the smallest SSQ. Mr. Garrett’s method will produce any result he 9

desires to obtain. 10

24

Q. ACCORDING TO MR. GARRETT, WEIGHTING BY EXPOSURES WAS 1

ACHIEVED BY NARROWING THE FOCUS OF HIS CALCULATIONS TO 2

CONSIDER THE TOP 99 PERCENT OF THE EXPOSURES AND TO 3

ELIMINATE THE TAIL END OF THE CURVE REPRESENTING THE 4

BOTTOM 1 PERCENT OF EXPOSURES FOR SOME ACCOUNTS. IS “… 5

FITTING IOWA CURVES TO THE MOST SIGNIFICANT PART OF THE 6

OLT [OBSERVED LIFE TABLE] CURVE”30 EQUIVALENT TO EXPOSURE 7

WEIGHTING? 8

A. No. Exposure weighting is used in a regression of hazard rates to reduce increasing variances of 9

residuals (i.e., heteroscedasticity). Exposures can be used as a proxy for the inverse of the 10

residual variances, as was used in the 2019 service life study. 11

Consider, for example, Account 352 (Structures and Improvements) in which Mr. Garrett 12

claims: “The fact that SCE’s selected Iowa curve provides a better fit through the first 20 age 13

intervals does not mean it provides a better fit overall.”31 The objective of a life study is not to 14

find the best overall fit of data points to a survivor curve. The objective is to statistically estimate 15

population parameters based on an analysis of samples drawn from parent populations. It is the 16

weighing of hazard rates to reduce the variance of residuals that correctly gives less weight to 17

hazard rates that progressively increase to a value of 1.00. This is why it is important to 18

understand the statistical properties of hazard rates (i.e., variances and covariances) and why a 19

life study may give the appearance of a better visual fit through the first 20 age intervals. 20

In summary, Mr. Garrett’s critique of the 2019 service life study evidences a misplaced view 21

of the objective of a statistical life study and the importance of probability distributions used in 22

estimating population service–life parameters. 23

Q. WITH FURTHER REFERENCE TO ACCOUNT 352.00, MR. GARRETT 24

CLAIMS “DR. WHITE DOES NOT SHOW WHY … RETIREMENT 25

ACTIVITY [IN THIS ACCOUNT] IS ANOMALOUS NOR DOES HE MAKE 26

30 Id. at p. 11, l. 5–19.

31 Id. at p. 14, l. 4–6.

25

ANY QUANTITATIVE CONNECTION BETWEEN THIS RETIREMENT 1

AND HIS PROPOSED SERVICE LIFE.”32 IS THIS A VALID CRITICISM? 2

A. No. The context of Mr. Garrett’s criticism is the following: 3

Statistical service life indications for the full account are derived from unlikely 4 recurring retirement activity. Retirements of $22.4M reported in 2009 (58.5 percent 5 of total adjusted retirements over the 17-year study period) were primarily related to 6 the retirement of equipment at the Sylmar substation.33 7

In my opinion, 58.5 percent of retirements associated with a single retirement is “unlikely 8

recurring retirement activity.” 9

This account also illustrates why it is important to examine hazard rates and banding 10

analyses in conducting a statistical life study. Had Mr. Garrett examined the rolling and 11

shrinking band analyses contained in the workpapers for this account, he would have observed 12

the quantitative impact of the 2009 retirement activity. Average service-life indications 13

exceeding 90 years for post-2009 activity years are significantly longer than pre-2009 activity 14

years, ranging between the mid-30s and mid-50s. Removing 2009 retirement activity from the 15

observed life table reduces hazard rates at varying ages prior to age 36.5 years, thereby 16

producing average service-life indications comparable to the banding analyses. This is why the 17

following was reported for this account in the 2019 service-life study: 18

Based mainly on first-degree statistical service-life indications and discounting 19 origin-modal dispersions in which chance is a more pervasive force of retirement, a 20 retention of the currently approved 55−L1 projection life-curve is recommended for 21 this account. This recommendation reflects a lack of evidence for adjusting the 22 service life estimates given the single retirement underlying a significant percentage 23 of the retirement history. 24

Mr. Garrett cannot claim that Dr. White did not “make any quantitative connection between 25

this retirement and his proposed service life.” 26

Q. DOES ACCOUNT 352.00 ALSO ILLUSTRATE HOW MR. GARRETT 27

CONCLUDES THAT, FOR EACH ACCOUNT, “… THE COMPANY’S 28

PROPOSED SERVICE LIFE, AS ESTIMATED THROUGH IOWA CURVES, 29

32 Id. at p. 15, l. 14–17.

33 SCE–07, Vol.3, Appendix A, p. A–10.

26

IS TOO SHORT TO ACCURATELY DESCRIBE THE MORTALITY 1

CHARACTERISTICS OF THE ACCOUNT”34? 2

A. Yes. Account 352.00 illustrates how Mr. Garrett attempts, for each of his adjusted accounts, to 3

force fit a survivor curve to observed proportions surviving by using T-cuts and visual 4

comparisons to lengthen service lives and reduce depreciation rates. 5

Q. ACCORDING TO MR. GARRETT, “DR. WHITE SIMPLY DEFERRED TO 6

COMPANY PERSONNEL FOR HIS PROPOSALS ON SEVERAL OF THESE 7

ACCOUNTS, WHICH DOES NOT SATISFY THE COMPANY’S BURDEN 8

TO MAKE A CONVINCING SHOWING THAT ITS PROPOSED 9

DEPRECIATION RATES ARE NOT EXCESSIVE.”35 IS THIS A VALID 10

CRITICISM OF THE 2019 SERVICE LIFE STUDY? 11

A. No. First, as discussed earlier, the Court did not decree in Lindheimer v. Illinois Bell Telephone 12

Co. that “… the Company bears the burden to show that its proposed depreciation rates are not 13

excessive, and in turn, that its service lives are not underestimated.”36 No regulated utility could 14

meet this standard. 15

Furthermore, his accusation that Dr. White simply deferred to Company personnel for 16

several of his proposals is blatantly false. In those instances in which insufficient evidence was 17

obtained from statistical analyses to warrant an adjustment to currently approved service lives, 18

Foster Associates sought guidance from the Company before recommending retention of 19

currently approved services lives as reasonable and appropriate for life estimation. 20

Factors evaluated by SCE included operational, accounting and ratemaking considerations. 21

Contrary to Mr. Garrett’s unfounded accusations, SCE did not direct Fosters Associates to 22

propose service lives that would lead to higher depreciation rates or directly impact cashflows. 23

Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY? 24

A. Yes, it does. 25

34 Exhibit TURN-11 at p. 12, l. 6–8.

35 Id. at p. 44, l. 2–5.

36 Id. at p. 19, l. 12–13.

27

C. Account 370: Engineering Considerations Support Retaining Currently Authorized Service 1

Life 2

1. TURN’s Position 3

TURN proposes to extend the authorized service life for Account 370 Meters from 20 4

years to 30. TURN bases its proposal on limited retirement data and the fact that some equipment within 5

the account has survived longer than its proposed 30-year average life. TURN’s proposal results in a 6

reduction of $27.2 million relative to the currently authorized average service life. 7

2. SCE’s Rebuttal 8

SCE’s proposed average service life is conservative compared to industry averages and 9

given engineering considerations. TURN’s basis for the 30-year life lacks evidentiary support as the 10

survivor curves are highly censored, which means that there is very little available retirement experience 11

from which to draw conclusions about average service lives. Additionally, the portion of the account 12

that TURN cites as lasting more than 30 years makes up only 1.8% of the account population. Current 13

analysis results in highly censored stub curves in part because SCE’s initial roll-out of the smart meter 14

program had generous warranties than what is currently in place. SCE accounts for meters as cradle to 15

grave assets, meaning they are capitalized upon purchase and retired the final time they are removed. 16

In the early years of the program, failed units were sent to the manufacturer and replaced under 17

warranty. In these cases, no units were retired as SCE was furnished with a replacement unit to be put 18

back into service. As SCE moved forward with the program, approximately 90% of the existing units are 19

no longer under warranty and failures will result in retirements. 20

These units are subject to the same type of harsh environmental conditions experienced 21

by the prior generation of electro-mechanical meters which had a commission-authorized 20-year 22

average service life. In addition, AMI meters contain electronics memory that requires frequent update 23

and can become outdated. Though the units can continue to operate, they are vulnerable to these issues 24

that can no longer be remedied with a firmware update from the manufacturer. Other electronic 25

hardware can also present a challenge because the technology is rapidly changing, and because 26

availability of parts can be a problem. For these reasons, AMI meters are likely to have shorter average 27

service lives than what was authorized for the prior generation of electro-mechanical meters. 28

TURN states that in order for the service life SCE proposes to be accurate, there would 29

have to be a significant ramp-up in the number of failures in the near future. It is reasonable to expect 30

28

that this will be the case. Unlike the recent past, SCE engineers expect approximately 90% of these 1

replacements to result in final retirements in the future. 2

D. Accounts 369 And 370: Industry Data Does Not Support TURN’s Recommendations 3

As stated by Dr. White, “the statistical service life analysis for [Account 369] is based on highly 4

censored (52-88 percent) samples producing unreliable service-life indications for the majority of 5

trials.”37 The same is true for account 370 which indicates 98.8 percent38 censoring. Given such limited 6

statistics from which to draw conclusions, industry data provides context and a comparison to what 7

TURN is proposing. As shown in Figure III-5 below, TURN’s proposal exceeds the average service life 8

adopted by the Commission for California utilities as well as the nation as a whole. 9

Figure III-5 Account 369 and 370 Average Service Lives

As show in Figure III-5 above, SCE’s 55-year service life for account 369 is already the longest 10

of the California Investor-Owned Utilities (IOUs) and is well above the industry average of 48 years. 11

TURN’s proposal of 60 years is already longer than both the California and industry average and given 12

the high degree of censoring, it would be unreasonable to adopt an extension that would place SCE well 13

37 Exhibit SCE-07, Vol. 3, Appendix A p. A-39.

38 Id. p. A-41.

Account 369

Account 370

SCE (55) TURN (60)

SDG&E (54)

PG&E (51)Industry

Average (48)

SCE &PG&E(20) TURN (30)

SDG&E (16)

Industry Average (23)

29

above both the California IOU and industry average. Similarly, for account 370, TURN’s proposal is 1

eleven years longer than the California IOUs’ average and seven years longer than the industry average. 2

TURN’s proposal would be a 30% increase in service life compared to the industry average, which is 3

unreasonable given the high censoring and the significant new forces of retirement from the advanced 4

technology. 5

In summary, TURN’s proposal lacks evidentiary support. In light of the limited retirement 6

history, it is reasonable to rely on engineering and industry data to form conclusions about the likely 7

average service lives.8

30

IV. 1

HYDRO DECOMMISSIONING 2

A. TURN’s And Cal Advocates’ Positions 3

TURN and Cal Advocates propose to limit SCE’s requested increase in hydro decommissioning 4

accruals to only Rush Creek (Agnew) and Borel. In addition, TURN recommends applying $31 million 5

of anticipated receipts from the Army Corps of Engineers as a reduction to the total cost of 6

decommissioning, an adjustment based on a recent data request transmitted after service of Cal 7

Advocates’ testimony. Without the benefit of that data, Cal Advocates had recommended that Borel’s 8

estimate be reduced by 50 percent for potential receipts by the Army Corps of Engineers. 9

TURN proposes approval of $10.1 million of decommissioning expense for small hydro. 10

Table IV-9 Comparison of Hydro Decommissioning Proposals

(in $ millions)


SCE appreciates the analysis from TURN and Cal Advocates regarding SCE’s hydro 12

decommissioning proposal and is glad to see a common understanding that small hydro plants face 13

significant challenges to remain economically viable. However, SCE does not agree that 14

decommissioning accruals should be limited to Borel and Rush Creek. 15

Before addressing points specific to the various hydro plants, SCE wishes to reiterate the general 16

principles behind its proposed approach to collection for future decommissioning costs. With some 17

exceptions (e.g., Borel) it is difficult to know with full certainty which plants will be decommissioned 18

and when. However, the combined forces of decreased energy market value and the high costs 19

SCE TURN ∆ from SCE CalPA ∆ from SCE

A B C D=C‐B E F=E‐B

Proposed Small Hydro Future

Decommissioning Estimate$446.2 $147.3 ($298.9) $101.9 ($344.3)

Proposed Annual Depreciation for

Small Hydro Decommissioning$29.6 $10.1 ($19.5) $6.8 ($22.8)

*TURN's $19.5 proposed reduction includes the $5.2 impact attributable to

stripping out future inflation shown on Table V‐10 in Chapter V of this testimony.

31

associated with relicensing and/or major repairs mean that decommissioning of at least some small 1

hydro plants is likely a matter of when, not if. As demonstrated by the decommissioning cost estimates 2

SCE provided, the location and nature of the extensive footprints of hydro plants in remote mountain 3

terrain can lead to substantial removal costs. By recovering hydro decommissioning on a collective basis 4

across the entire small hydro portfolio, SCE’s proposal addresses timing uncertainty, is designed to 5

collect now from customers who benefit from the plants while they are operational, and is designed to 6

avoid a “rate shock” effect that would otherwise occur in the future if SCE were to collect those high 7

future costs within a compressed period of time. 8

Regarding Kaweah, TURN states that “the Kaweah plant is actively being relicensed ($3.2 9

million request from 2019-2023), so that funding relicensing and decommissioning as if both will occur 10

in the mid-2020s appears not to make sense.”39 To clarify, the $3.2 million forecast is to relicense 11

Kaweah 1 and Kaweah 2, to which SCE assigned a decommissioning probability of 10%. Kaweah 3 is 12

not included in the $3.2 million, and requires a separate effort to renew its Special Use Permit (SUP) 13

from the National Forest Service, which expires in 2026. As SCE described in testimony, the uncertainty 14

of the terms, conditions, and costs of SUP renewal are sufficiently uncertain that SCE assigned a 15

decommissioning probability of 50% to the Kaweah 3 powerhouse and ancillary structures. It is 16

reasonable and appropriate to begin collecting decommissioning accruals at the 10% and 50% rates for 17

the respective Kaweah projects. 18

TURN and Cal Advocates do not specifically state the reasons for proposing the elimination of 19

decommissioning collection for Tule, which SCE assigned a 50% decommissioning probability level 20

along with Kaweah 3 and the Gem Lake portion of the Rush Creek system. SCE reiterates the 21

reasonableness and appropriateness to begin collection for Tule at the 50% level, which is based on the 22

plant’s current inoperable state due to a 2017 fire. As SCE described in testimony,40 the high cost to 23

repair the plant raises significant questions about its economic viability, especially when compared to 24

the potential decommissioning cost. The future operation of Tule is far from certain, and it is appropriate 25

to begin recovery for decommissioning. 26

TURN states that “Edison is spending $3.3 million at the Gem Lake dam to increase its ability to 27

discharge water under high water conditions, even though the safety concerns were a part of the 28

39 Exhibit TURN-09, pg. 33, line 1.

40 Exhibit SCE-05, Vol. 1, pp. 119-120.

32

rationale for decommissioning.”41 As SCE described, this project will support public safety by 1

increasing the dam’s ability to safely discharge water during high water years, and will meet 2

expectations of both state and federal safety regulators (FERC and California Division of Safety of 3

Dams). The Gem Lake dam can provide water to the powerhouse independently of the other two dams 4

in the Rush Creek system (Agnew and Rush Meadows), and as such SCE assigned a lower probability 5

for its decommissioning (50% versus 90%, respectively). 6

Finally, TURN states that “The plants with 10% decommissioning probability in Edison’s 7

analysis are entirely speculative and should not be funded until more is known. … intergenerational 8

equity is not a reasonable argument in favor of starting the collection now rather than later.”42 9

SCE recognizes that, when looking individually at the plants that are classified at a 10% 10

decommissioning probability, it may not seem ripe to initiate collection due to the low probability. 11

However, the large number of plants at the 10% level (twelve total, including Kaweah 1-2) means that it 12

is likely that at least one will be decommissioned (i.e., the individual probability is low but the number 13

of occurrences increases the chance that at least one will materialize). For reasons described above 14

related to the challenging economics facing small hydro plants, it is appropriate to begin 15

decommissioning collection now, instead of delaying the inevitable and seeking a potentially much 16

larger portion from customers in the future. 17

1. Continued Deferral Of Recovery Places A Burden On Future Customers 18

Continuing to defer recovery places burden on future generations of customers rather 19

than on those receiving the benefit of these assets. It is important to begin some level of accrual even 20

where probabilities of decommissioning may be 50% or less. The probability-adjusted accruals will 21

begin to provide a reserve balance that will be available to offset decommissioning if any of these plants 22

should progress to that point. The low probability provides an opportunity for a modest start towards 23

recovery, rather than placing the cost burden on later customers. Because the reserve is held for the 24

entire group of Hydro assets, available funds will begin to accumulate and offset whichever plant 25

ultimately is decommissioned. We now know that these plants won’t last forever, so even low 26

probability plants should start recovering for decommissioning so future customers aren’t left with the 27

majority of the costs. 28


42 Id., lines 6-10.

33

2. Broad Group Depreciation Provides A Common Reserve For All Hydro Assets 1

SCE utilizes group depreciation procedures that treat the Hydro portfolio as a single 2

group of assets, which helps produce reasonably stable depreciation accruals over time. This means that 3

although there are 24 individual hydro facilities, the group of assets share a common depreciation 4

reserve which can be used to offset decommissioning costs of any hydro facility. SCE’s accruals being 5

proposed in this case are calculated using specific assumptions about specific plants, but the reserve to 6

be collected will be there to offset decommissioning costs regardless of which plant proceeds with that 7

activity. 8

3. Customers Are Protected From Over/Under-Collection 9

Customers are also protected if the ultimate costs SCE realizes are lower than expected. 10

A good example of this is TURN’s proposal to offset SCE’s accruals for Borel with the $31 million in 11

proceeds that are to be received from the US Bureau of Reclamation. SCE agrees with this proposal as 12

these funds received will offset funds needed from customers and SCE’s accruals should be adjusted 13

accordingly. As time goes on, these decommissioning estimates and probabilities will be revisited in 14

each successive rate case and the recommended future accrual levels will be adjusted to match the new 15

expectations. SCE will only seek to recover necessary funding and any excess will be returned to 16

customers. Conversely, if conditions change, it may also be necessary to increase the annual accrual at a 17

point in time. In either case, the customer will only be funding the necessary levels to fund future 18

decommissioning activities. 19

Due to the challenging economics facing small hydro plants, it is reasonable and 20

appropriate to begin decommissioning collection now. Although there is a range of probabilities for 21

individual plants, the use of probability-adjusted decommissioning estimates to set accruals begins 22

working towards assigning costs to customers currently receiving the benefits from these facilities.23

34

V. 1

GENERATION DECOMMISSIONING 2

Table V-10 Comparison of Generation Decommissioning Proposals

(in $ millions)

A. TURN’s Position 3

TURN recommends reductions to SCE’s proposed decommissioning to remove inflation beyond 4

2023 (one year before the end of the current rate case).43 Alternatively, TURN proposes including 5

inflation to the decommissioning year, but with a revised historical Handy-Whitman inflation factor 6

(four percent per year). TURN justifies its proposal by claiming that “it is not reasonable to charge 7

today’s ratepayers the same number of nominal dollars as future ratepayers who will be paying in 8

cheaper nominal dollars.”44 9


SCE’s proposed decommissioning estimates are escalated to the year of retirement based on 11

guidance from Standard Practice U-4 and CPUC decisions predating the anomalous result in SCE’s 12

2018 GRC. TURN’s recommendation to defer inflation to the end year of the current rate case cycle, 13

which was authorized for the first time in the 2018 GRC with very little analysis, results in excessive 14

deferral to future customers. TURN’s criticism of the straight-line method is premised on the 15

assumption that increases in decommissioning accruals should grow at the same rate as inflation to 16

43 Cal Advocates applied the same approach to hydro decommissioning.


Facility SCE TURN ∆ SCE TURN ∆

A B C D=C‐B E F G=F‐E

Mountainview Units 3&4 $18.6 $13.3 ($5.3) $0.7 $0.4 ($0.3)

Solar Photovoltaic 81.4 70.5 (10.9) 4.7 3.8 (0.9)

Peakers 14.8 10.0 (4.8) 0.5 0.3 (0.2)

Hydro* 446.2 365.7 (80.4) 29.6 24.4 (5.2)

Total 561.0 459.5 (101.4) 35.4 28.9 (6.5)

*TURN's Hydro proposal above includes only the impact from stripping out future inflation.

Refer to Chapter IV for SCE's rebuttal to TURN's probability adjustments.

Proposed Decomm Annual Accruals

35

ensure that current customers are not asked to pay more than future customers. In reality, the method 1

proposed by TURN fails to accomplish this objective and instead will result in future customers bearing 2

disproportionate costs. 3

TURN’s proposal is a deferral method that does not appropriately allocate decommissioning 4

costs over the life of the asset. As SCE stated in its direct testimony, 5

The required increases using [TURN’s] approach are not linear. Instead, as the 6 escalation costs are deferred and the remaining life of the facility is shortened, net 7 salvage accruals must increase faster than inflation and future customers bear 8 increasingly larger portions of the deferred cost over increasingly shorter periods. To 9 prevent this inequitable distribution of service value, [SCE’s] decommissioning 10 proposals…adhere to the SP U-4 approach of valuing the estimated future net salvage 11 costs at the time of retirement and amortizing them straight-line over the remaining 12 life.45 13

The pitfalls of TURN’s approach are better understood with an illustrative example shown in Table V-14

11, below. Both methods, whether straight-line or inflation-deferred, will collect $100,000 after 20 15

years. Under straight-line, the collection is ratable, or even, year over year. Under the inflation-deferred 16

method, the amount to be collected early in the 20-year period is small and grows modestly, but then the 17

amount grows exponentially to catch up on the uncollected inflation from earlier periods. 18

45 Exhibit SCE-07, Vol. 03, p. 77.

36

Table V-11 Comparison of Straight-Line (U-4) Versus Inflation-Deferred (TURN)46

The Accrual Growth Rate column of Table V-11, above, shows an example of the growth rate of 1

accruals that would occur under TURN’s proposal. In the years close to the asset’s retirement, the 2

accruals in TURN’s proposal grow at many times the rate of inflation to make up the shortfall that was 3

created by only including inflation through the current rate case cycle. 4

In Figure V-6 below, three different accrual patterns are shown. TURN’s proposal, reflected by 5

the dashed “Inflation Deferred” line, shows large increases in accruals are needed towards the end of the 6

46 See Appendix B, “Straight-Line vs. Inflation Deferred Method,” pp. B24 to B25.

Straight Inflation AccrualYear Line Deferred Growth Rate

1 $5,000 $2,3732 5,000 2,473 4.2%3 5,000 2,583 4.4%4 5,000 2,704 4.7%5 5,000 2,837 4.9%6 5,000 2,985 5.2%7 5,000 3,150 5.5%8 5,000 3,335 5.9%9 5,000 3,543 6.2%10 5,000 3,779 6.7%11 5,000 4,050 7.2%12 5,000 4,362 7.7%13 5,000 4,727 8.4%14 5,000 5,161 9.2%15 5,000 5,688 10.2%16 5,000 6,346 11.6%17 5,000 7,201 13.5%18 5,000 8,386 16.5%19 5,000 10,235 22.1%20 5,000 14,081 37.6%

Total $100,000 $100,000

Early Accruals grow at approximately the same rate as inflation.

But accruals towards the end of the service life grow much faster than inflation to catch up.

37

asset’s life for the reasons described above. The dotted line (i.e., “inflation matched”) is not TURN’s 1

proposal, but one may mistake TURN’s proposal for it so we are showing it for completeness to avoid 2

doubt about the true impact of TURN’s proposal. It shows the pattern of accruals when increases to 3

decommissioning estimates from inflation are allocated to the period in which inflation is realized. 4

In other words, under “inflation-matched,” customers pay for only their proportional share of inflation 5

experienced over that period. The solid line (i.e., straight-line) shows the even pattern of accruals that 6

results when using the straight-line, remaining life method described in SP U-4. 7

Figure V-6 Comparison of Accrual Methods

As shown in Figure V-6 above, the straight-line method and “inflation matched” methods result 8

in similar relative levels of accruals over the asset’s life. By contrast, TURN’s proposal results in much 9

lower accruals early in the asset’s life that are made up for with much higher accruals at the end of the 10

asset’s life. This is due to TURN’s proposal including only a sliver of the realized inflation in the 11

depreciation accrual, while the remainder of inflation is left to future periods. TURN offers no testimony 12

for why future customers, especially those on fixed incomes, would have the ability to bear that abrupt 13

cost increase even if the dollar is worth less at that time. 14

SCE’s proposal follows the straight-line, remaining life method described in SP U-4. 15

When using the straight-line, remaining life method, decommissioning estimates should include 16

inflation to the year of retirement so that an even accrual (i.e., a straight-line) is achieved. This method is 17

38

straight-forward and ensures that each generation of customers pays for their proportional share of the 1

cost to decommission the unit, as is demonstrated in Figure V-6, above. 2

TURN makes an alternative proposal that includes inflation to the decommissioning year but 3

revises the historical escalation factors.47 This proposal is less troublesome than TURN’s primary 4

recommendation because it recognizes the need to include inflation to the decommissioning year. 5

However, SCE does not believe there is sufficient evidence to justify a departure from the industry 6

standard Handy-Whitman index at this time. 7

Finally, TURN recommends that SCE conduct additional decommissioning studies for its 8

Peakers, Mountainview and Solar units. SCE agrees to revise the decommissioning estimates of the 9

following plants in the next GRC. 10

47 Exhibit TURN-09, pg. 36, lines 10-15.

39

VI. 1

PERRIS48 DECOMMISSIONING 2

SCE decommissioned the Perris solar rooftop generating facility seven years after it was 3

installed. Consistent with Standard Practice U-4, SCE proposes to recover the undepreciated cost of the 4

investment, plus the return, over the 10.7-year remaining life of the overall group of solar rooftop assets. 5

In total, SCE proposes to collect $2,537,000 in depreciation expense49 for the next 10.7 years to recover 6

the cost of the investment, the cost of decommissioning, plus the return and taxes. 7

A. TURN’s Position 8

TURN recommends that the cost (net book value plus decommissioning) of the Perris solar 9

photovoltaic generating facility be recovered over six years instead, and that SCE be barred from 10

earning a return on its capital investment. TURN states that its proposal will result in SCE’s 11

shareholders bearing approximately 20% of the project’s cost, a result it sees as justified because in its 12

view the early retirement was a foreseeable event at the time of installation.50 13

48 TURN refers inadvertently to this as the “Ferris” facility.

49 Note, this figure is calculated based on the $6.5 million decommissioning estimate included in SCE’s original proposal. The decommissioning project is ongoing, and as such, the final cost of decommissioning is not available. Regardless of the outcome, the figure above, and those in Table VI-12, below, should be trued up to reflect the actual costs at the conclusion of the project.

50 Exhibit TURN-09, p. 37-39.

40

Table VI-12 Perris Decommissioning51

(in $ thousands)


In June 2019, SCE began decommissioning of the 10.2 megawatt (MW) Dexus solar site in 2

Perris, California. The facility originally went into operation in 2012 as part of SCE’s Solar Photovoltaic 3

Program (SPVP) initially authorized by the Commission in D.09-06-049 with an objective to expand the 4

renewable energy market, and help bridge the gap between the two predominant solar installation 5

categories at the time--residential solar rooftops and utility-scale solar installations.52 The SPVP 6

program was subsequently scaled down in D.12-02-035 and again in D.13-05-033 in part because less 7

SCE-owned solar generation ultimately was needed to achieve the desired market transformation 8

effects.53 9

TURN’s proposal that SCE should be penalized by disallowing a return on the Perris investment 10

because its early retirement was a foreseeable event is unfounded for several reasons. First, TURN has 11

not sufficiently explained why in 2011 it was unreasonable for SCE to project a possible 20-year life for 12

this facility. Instead, TURN relies on an incorrect review standard based on hindsight knowledge of 13

51 See Appendix B, “Perris Decommissioning Impact Table,” pp. B26 to B27. TURN’s testimony had not

quantified the depreciation expense that would result from its proposal, so SCE is filling in those numbers here based on its understanding of TURN’s proposal.

52 See Exhibit SCE-05, Vol. 1, pp. 18-19 for additional information on the Solar PV program.

53 D.13-05-033 Decision Partially Granting SCE Petition for Modification of D.12-02-035 (Solar Photovoltaic Program).

Line No. Description SCE TURN ∆ from SCE1. Jan. 1, 2021 Net Book Value 20,541 20,541 --2. Decomm Expenditures 6,500 6,500 --

3.=1+2 Total Unrecovered Perris Capital 27,041 27,041 --

4. 2021 Remaining Life 10.7 6.0 (4.7)

5.=3/4 Proposed Depreciation Expense 2,537 4,507 1,970 6. Pre-Tax Return on Rate Base 2,544 - (2,544)

7.=5+6 Total Revenue Requirement 5,081 4,507 (574)

41

subsequent events that were not known when the installation occurred—at a time when the Commission 1

enthusiastically welcomed these facilities and the impact they were expected to have on stimulating 2

solar generation. Under the correct review standard, SCE’s actions and decision making in connection 3

with the Perris SPVP facility were reasonable at the time they occurred. Second, SCE’s proposal to use 4

mass asset accounting treatment is consistent with Standard Practice U-4, which would prohibit cherry-5

picking one prematurely retired asset and barring investors from earning a return on it. This is especially 6

true given that in two consecutive GRCs, the Commission has treated SCE’s rooftop solar facilities as 7

one group of assets subject to one average service life and one decommissioning estimate. 8

Third, TURN’s proposal is fundamentally one-sided because it asks SCE’s investors to forego a return 9

after their capital was used to deliver benefits that will extend beyond the return they have been 10

provided thus far. 11

1. TURN Uses Hindsight To Claim That The Early Retirement Of Perris Was 12

Foreseeable From The Start 13

TURN justifies its proposal to deny SCE’s investors a return on their investment by 14

arguing that the early retirement of the Perris SPVP facility was a foreseeable event from the start. 15

This conclusion relies on information and events not available at the start of the project, and reflects a 16

lack of understanding of the marketplace in 2011 for leasing rooftops of buildings with large 17

commercial and industrial tenants. Commission decisions provide that perfect utility foresight is not 18

required. Rather, the Commission has consistently held that: (1) a utility’s actions “may be found to be 19

reasonable and prudent, if the utility shows that its decision making process was sound, . . . even if it 20

turns out not to have led to the best outcome;”54 (2) the reasonableness of a particular management action 21

does not depend on “how the decision holds up in the light of future developments;”55 and (3) a 22

reasonable and prudent act can include “a spectrum of possible acts.”56 23

a) TURN Impermissibly Relies On Hindsight 24

In regard to the Perris SPVP facility, any assertion by TURN that the events 25

requiring an early retirement were foreseeable at the time the project was evaluated and commissioned is 26

54 D.05-08-037 at 10-11. See also D.18-10-010, p. 31 (“The Commission reviews the reasonableness of a

utility’s actions based on what the utility knew or should have known at the time the utility took the actions[.]”)

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

56 Id. at p. 9.

42

based on impermissible hindsight. Indeed, as TURN points out, the independent roofing consultant 1

determined in 2011 that: 2

[T]he roof system has been constructed per industry standards for a system capable of 3 delivering 20 years of effective service. The building is currently 4 to 5 years old, 4 which would translate into a remaining service life ability of approximately 15 to 16 5 years of additional service. Also, the installation of a solar panel system would afford 6 UV 1 protection to the existing roof membrane which could extend the service life of 7 this system to meet Southern California Edison’s 20-year service life requirements.57 8

Similar language is included in many of the roof reports from SCE’s other Solar 9

PV installations. At all these sites, the independent roofing consultant concluded that, “we would 10

recommend the installation of the solar panel system on this building.”58 This recommendation was 11

made based on a number of factors. As the consultant confirmed, there was limited availability of 12

buildings at that time that met necessary criteria such as roof size and type, and location near a 13

distribution grid with capacity to handle the PV system. SCE reasonably relied on the recommendations 14

of the independent roofing consultant, who inspected dozens of other roofs at SCE’s request. In sum, the 15

information available at the time SCE made its decision supported the reasonableness of that decision. 16

Subsequent intervening events may have differed among the facilities, but that cannot affect the 17

evaluation of the reasonableness of the original decisions to proceed with these facilities. 18

TURN attempts to use the independent roofing consultant’s report in a faulty way. 19

TURN relies on the independent roofing consultant’s mathematical calculation that there were at least 20

15 to 16 years of additional service left, and then uses this calculation to argue the consultant predicted 21

the premature failure of the roof.59 In making this argument, TURN uses hindsight of what subsequently 22

occurred to convert the consultant’s general observations regarding the condition of the roof and 23

estimated lifespan into a red flag that SCE should have abandoned the project at the outset. 24

This argument is faulty, because it does not consider actions taken to extend the lifespan of the roof. 25

When the building owner repaired the defects before SCE’s lease commenced, the expected service life 26

of the roof membrane was extended. In addition, it was reasonable to consider that the installation of the 27

panels, which would block harmful UV radiation, could further extend the expected lifetime of the roof. 28

57 TURN-SCE-062 08 02110317 Dexus Final Roof Inspection.pdf Page 7 Section 4.01 (A).

58 TURN-SCE-062 08 02110317 Dexus Final Roof Inspection.pdf Page 8 Sections 4.02.


43

The combination of repairs and UV protection extended the expected service life to 15-20 years at the 1

time SCE committed to build the facility. 2

TURN’s focus on the “foreseeability” of roofing repairs during a 20-year period 3

also misses the point. The possibility that a roof would need repair at some point during the 20-year 4

period did not make SCE’s actions imprudent. The possible need to repair or replace a roof is an 5

obvious, inherent risk for any type of structure placed on a rooftop. The measure of life expectancy of a 6

roof is driven by factors almost universally outside of SCE’s control, such as rain, wind, heat, humidity, 7

defects in other roof appurtenances (such as skylights or HVAC systems), wear and tear due to 8

inspections or other maintenance, etc. TURN has established that roof repair may likely over the course 9

of 20 years, but that is a reality for every roof. TURN fails to show that as of 2011, there were realistic 10

expectations that the likely repairs on the Perris facility roof specifically would be early enough and 11

severe enough to prompt the building owner to request removal of the project to allow for re-roofing. 12

As with most assets, some rooftops (whether a house or commercial building) sometimes require 13

repairs/replacement earlier than anticipated. Conversely, many roofs outlive or outpace their useful life, 14

and accordingly customers are likely to benefit from those life extensions when applied to the SPVP 15

program at large. 16

b) SCE’s Investment Decisions Were Prudent 17

TURN claims that because the terms of the lease agreement for the Perris facility 18

made returning the solar panels to service uneconomic after roof repairs or replacement, then “assigning 19

the total cost of this mistake to customers is not warranted.”60 Again here, TURN’s argument relies on 20

the benefit of hindsight, an impermissible review standard, if it means by “mistake” an action that was 21

unreasonable at the time it was taken. Changes in the Solar PV market are largely responsible for 22

making the cost of reinstalling the assets uneconomic, not the terms of the lease agreement itself. 23

Under the Commission’s correct review standard, which determines a utility’s prudency based upon 24

what SCE knew at the time it made its decisions, SCE’s actions committing to the Perris facility were 25

reasonable – both when it installed the facility and when it decommissioned the facility. 26


44

(1) The Lease Terms Regarding Removal Of The Panels Were Consistent 1

With The Terms That Could Be Reasonably Expected For A 2

Commercial Lease 3

TURN criticizes the lease terms that required SCE to remove the system at 4

its cost at the request of the property owner/lessor. As SCE described in Data Request Set TURN-SCE-5

062, Question 10, when SCE initiated the SPVP, the concept of leasing roof space for PV panel 6

installations was novel, and there was resistance from property owners/lessors to allow a third party to 7

install electrical equipment on their roofs.61 The property owners expressed concerns regarding how the 8

equipment would affect the structural integrity of the roofs and buildings, operations and activities 9

within the buildings, and other tenants.62 It also should be noted that a number of these buildings house 10

large commercial and industrial tenants, and a number of the buildings are designed to serve as 11

distribution facilities for large manufacturers, vendors, and other retailers. The revenue generated by 12

building owners from SCE’s lease was insignificant compared to the revenue generated from ground 13

occupants/tenants. In light of these concerns, it would have been commercially unreasonable for SCE or 14

any leasing party to expect a property owner/lessor to bear the cost of removal and re-installation of the 15

panels, unless the original lease cost was significantly higher to compensate the property owner/lessor 16

for this cost.63 17

Even without these concerns, it is customary that a tenant (SCE) utilizing 18

ancillary building space (the roof) would ordinarily be exclusively responsible for any improvements 19

made by the tenant in a commercial lease agreement. Any other expectation is inconsistent with 20

customary landlord-tenant commercial leasing terms. It is reasonable that the Perris SPVP property 21

owner/lessor would retain the right to make roofing and other structural building repairs necessary to 22

protect the integrity of the building, without incurring costs to remove structures, fixtures, etc. added by 23

SCE as the lessee. 24

Although SCE could not reasonably avoid lease terms requiring the SPVP 25

system to be removed at the request of the property owner/lessor, SCE negotiated lease terms that 26

provided an option for SCE to re-install the system and extend the lease term (hence extending benefits 27

61 TURN-SCE-062, Q.10.

62 Id.

63 Id.

45

of the SPVP program), in the event the property required SCE to remove the panels. This was based on 1

the prevailing understanding at the time that, once removed, the equipment would still have sufficient 2

value that it would be economic for SCE to re-install it. 3

(2) SCE Acted Prudently In Decommissioning The Perris SVPV Facility 4

The property owner of the building utilized for the Perris SPVP facility 5

ultimately decided to repair the rooftop, requiring SCE to remove the panels to allow the repairs to go 6

forward. SCE decided to decommission the facility only after the property owner made this decision. 7

The rooftop lease for the Perris project included a provision to restart the 20-year lease if a reroof project 8

was deemed necessary by the property owner. However, after considering the condition of the solar 9

panels, the terms of the lease agreement, and the market potential for the solar energy produced, SCE 10

determined that it was not in its customers’ best interest to exercise its option to reinstall the existing 11

panels and/or extend the lease agreement.64 In particular, due to the rapidly evolving solar technology 12

and dropping prices, the equipment had little residual value left after it was removed.65 SCE ultimately 13

sold the panels to a third-party, which prudently avoided significant costs associated with their disposal, 14

a decommissioning cost that otherwise would have been borne by customers. 15

2. Treating Perris As Mass Property Is Consistent With Standard Practice U-4 16

SCE owns and operates twenty-five solar generating plants with a combined total 17

capacity of 91 MW of Solar Photovoltaic Generation and a variety of installation types (i.e., rooftop, 18

ground-mount, etc.). For the last three GRC cycles, SCE has proposed, accounted for, and been 19

authorized depreciation rates based on the service life and net salvage expectations of the entire fleet of 20

these Solar assets. Accordingly, SCE proposes the same treatment in this GRC. When assets are grouped 21

together like this, Standard Practice U-4 instructs: 22

64 Refer to WP SCE-05, Vol. 1, Book B, p. 244 – Dexus Roof Removal - Economic Analysis.

65 Based on the circumstances that led to the decommissioning of the Perris facility, SCE also notes that additional sites in the SPVP program could experience circumstances in which the building owner exercises lease provisions to request SCE to remove the system. If these circumstances materialize, the developments in the economics for solar energy mentioned above could lead to the outcome that it would not be in customer’s best interests to re-install the system.

46

In group accounting all units having like mortality characteristics or all units of an 1 account are considered together. Accruals for the group are based on composite or 2 weighted average values of … service life expectancy. …. A deficiency due to early 3 retirement of a unit is made up through greater accruals on a unit which outlives the 4 average.66 5

For mass assets, like Solar PV, any under-collection resulting from the unexpected early 6

retirement can be expected to be made up over the remaining life of the group of solar facilities. This is 7

in contrast to unit accounting, which treats the uncollected cost of the asset as an expense at the time it 8

retires. Again, Standard Practice U-4 instructs: 9

Unit accounting (sometimes item accounting) requires a specific record… for each 10 individual item of property. A service life and salvage estimate are applied and an 11 individual accrual for the unit is determined. … If the unit is retired ahead of its 12 expectancy, the deficiency in accruals is charged to depreciation expense that year.67 13

Standard Practice U-4 supports SCE’s use of group accounting for assets such as the 14

Perris Solar PV, noting that “because of greater simplicity in maintaining records, the group basis is 15

more feasible for most classes of utility property where large numbers of units are involved.”68 16

TURN’s proposal to break with past treatment of these solar assets as a “group” and 17

instead propose to expense a single unit among the solar arrays over an unexplained six-year period, and 18

without a return, falls into neither group accounting or unit accounting. Even if it were appropriate for 19

TURN to separate this unit from the group as a whole, then the unrecovered costs should be expensed 20

immediately and be recovered from SCE’s customers in a single period. This approach, however, would 21

accelerate the assignment of costs to SCE’s customers. Instead, the Commission should continue 22

allocating the cost of the asset over the remaining life of the group of Solar PV assets, as it did for 23

several prior GRCs, consistent with the currently authorized treatment, including the return 24

component.69 25

TURN recommends that SCE should aggressively pursue any legitimate claims against 26

the building owner and credit 95% of the proceeds to customers. Consideration of such legal action is 27

66 See Appendix B, “STANDARD PRACTICE U-4”, pp. B28 to B29 (emphasis added).

67 Id.

68 Id.

69 When a utility’s costs are allocated in rates over a period of time, the initial cost is fronted by SCE’s investors. As a result, SCE incurs financing costs until capital recovery is completed. That is the long-standing basis for treating the return on capital as a cost of service for a regulated utility.

47

beyond the scope of this rebuttal testimony. However, in the event that SCE’s proposals for the Perris 1

facility are adopted, SCE agrees to return 100% of all proceeds that may be recovered from legal action 2

to customers. 3

3. TURN’s Proposal Penalizes SCE’s Investors After Customers Reaped Enduring 4

Benefits From The SPVP Program 5

TURN’s proposal is fundamentally one-sided because it asks SCE’s investors to forego a 6

return after their capital was used to deliver benefits that extend, and continue to extend, beyond the 7

return they have been provided. As outlined in D.13-05-033, the four initial goals of SPVP included: 8

“1) market transformation 2) improved processes, 3) development of a PV installation workforce, and 9

4) advancement of PV industry knowledge.”70 These program benefits extend beyond the return on 10

investment afforded to SCE’s investors and apply more broadly to the market as a whole. The 11

Commission has already recognized that. In D.13-05-033, the Commission found: 12

The SPVP has achieved significant success in meeting its programmatic goals, 13 playing an important role in the transformation of the Solar PV market. Since its 14 inception, thousands of MWs of Solar PV has been installed on both the customer and 15 utility side of the meter, with an even larger amount contracted for and slated to come 16 online over the next few years. A technology initially considered far too expensive to 17 be a significant part of the IOUs’ RPS portfolios has achieved a marked reduction in 18 price that now allows it to effectively compete in the renewable energy procurement 19 market.71 20

Despite these long-term benefits recognized by the Commission, SCE’s investors earn a 21

return only on the capital provided. Moreover, in response to the market changes, SCE petitioned to 22

reduce the return opportunity for its investors. After seeing that the market changes were taking effect, 23

SCE petitioned the Commission to allocate a greater portion of the Solar PV installations to Independent 24

Power Producers (IPPs), citing that it was now more cost effective to let IPPs bring online the additional 25

MWs. The successful petitions reduced the amount of SCE’s investment in utility-owned generation 26

(UOG) from the 250 MW initially authorized to 91 MW authorized in D.13-05-033. Absent these 27

petitions, SCE’s rate base and return to investors would have been higher. 28

Notwithstanding the role SCE played in advancing the Commission’s clean energy goals, 29

TURN seeks to strip SCE of the “return” portion of its cost of service. Should an early retirement like 30

70 D.13-05-033, p. 5.

71 D.13-05-033, pp. 8-9.

48

this one occur for reasons beyond SCE’s control (e.g., if a vehicle knocks down a distribution pole), 1

investors normally continue to earn the Commission-authorized return on capital expenditures because 2

the original investment was prudent. Here, the investment was not only prudent, but it was undertaken in 3

service of environmental and market-transformation goals. Adopting TURN’s proposal to disallow a 4

return for SCE’s investors risks sending the wrong message about future investments in similar 5

technologies such as Transportation Electrification and distributed energy resources. 6

The SPVP program should be considered a success. Early retirement of the Perris facility 7

should not disturb the important balance between upholding the Commission’s objectives and SCE’s 8

investors’ right to a fair return on their investment. Because the Perris project was only one part of 9

SCE’s investment support for this Commission initiative that has fulfilled its overall purpose and SCE’s 10

investment decisions were prudent, TURN’s proposal should be denied. 11

49

VII. 1

OTHER GENERATION 2

A. Palo Verde Interim Retirements 3


TURN recommends using a 7-year average versus SCE’s use of a 10-year average for 5

computation of interim net salvage rates for Palo Verde, which it says is reasonable to avoid a large 6

2010 interim retirement prompted by Arizona Public Service (an operator and co-owner of Palo Verde). 7


SCE’s selection of a 10-year band is more appropriate than TURN’s reliance on a 7-year 9

average. In making its proposal, SCE relied on all of the data that was available for this account. 10

TURN’s proposal ignores relevant retirement data and conveniently selects the 7-year band, which 11

drives to the lowest annual accrual amount and retirement rate, as shown in Table VII-13, below. 12

Table VII-13 Historical Interim Retirement Rate Averages & Accrual Impacts

TURN’s conjecture that the APS retirement from 2010 was anomalous is belied by 13

reasonable going-forward estimates. As SCE mentioned in its response to data request TURN-SCE-69, 14

Question 18, 15

APS indicates that in the next ten years three evaporative pond liners will require 16 replacement at a cost of approximately $30 million each. SCE notes, despite the 17 effect 2011 has on the historical analysis, a 0.55% weighted average interim 18 retirement rate produces a reasonable estimate. At 0.55% per year, the average life of 19 each component is approximately 90 years, with a maximum life of 180 years 20 (i.e., 1/0.55% = ~180), far exceeding the license-driven remaining life of 25 years. 21

As the plant continues to age, significant replacements are likely to occur. SCE believes 22

the use of the ten-year average interim retirement net salvage rate is a more appropriate and 23

comprehensive estimate of the future service life characteristics of the surviving plant. 24

TURN SCE

3‐Year 5‐Year 7‐Year 10‐Year

Interim Retirement Rate 0.10% 0.16% 0.20% 0.55%

Interim Net Salvage Rate ‐113% ‐62% ‐40% ‐24%

Annual Accrual ($M) 18.3 18.3 18.0 19.8

50

B. Fuel Cell Generation 1

Table VII-14 Fuel Cell Decommissioning Proposals

(in $ thousands)


TURN recommends reducing the Fuel Cell decommissioning cost by 50 percent due to 3

uncertainty about whether decommissioning will be necessary. TURN also recommends reducing SCE’s 4

contingency in the decommissioning estimates from 25% to 15%. 5


SCE proposes to begin collecting decommissioning costs for its two fuel cell 7

installations. This is the last GRC cycle before the expiration of the lease at the university campuses and, 8

as such, may represent the last opportunity to begin accruals for decommissioning before the units are 9

taken out of service. Recent discussions lead SCE to believe that decommissioning is likely, and it is 10

reasonable to begin collecting removal for 100% of the potential decommissioning, including 11

contingency, in this GRC. 12

TURN argues that customers would rather “keep the money in their pockets until it is 13

clear that the cost is needed for the stated purpose.”72 TURN’s argument ignores which generation of 14

customers bear the cost of the decommissioning. Waiting until the next GRC means to allow recovery of 15

72 Exhibit TURN-09, pg. 41, lines 8-9.

SCE TURN ImpactEstimated CostCost 2,299 2,299 - Contingency* 701 317 (384) Probability - (1,308) (1,308) Total 3,000 1,308 (1,692)

Depreciation ExpenseCost 766 766 - Contingency 234 106 (128) Probability - (436) (436) Total 1,000 436 (564)

*Includes corrections to reflect 15% contingency

51

the decommissioning costs means that customers in the future may bear the cost to decommission an 1

asset that is already out of service. SCE does not find it prudent or reasonable to willingly defer this 2

recovery to that generation of customers given the likelihood of decommissioning discussed below, and 3

the relatively small cost of collecting in the current rate case. 4

a) Decommissioning Both Facilities Is Likely 5

Per SCE’s response to TURN-SCE-062, Question 18, SCE has not received 6

formal communications from the University of Santa Barbara (UCSB) or California State University, 7

San Bernardino (CSUSB) regarding their desire to take ownership of the facilities at the end of the lease 8

agreement. However, other considerations lead SCE to believe that decommissioning will be required at 9

the end of the leases. 10

In 2018 UCSB backed out of discussion with SCE to relocate the fuel cell unit 11

after learning that relocations prior to the end of the lease would be their responsibility, but waiting until 12

the lease expiration would transfer the removal obligation to SCE. Given the university’s desire to 13

repurpose the land used by the fuel cell, SCE believes the possibility of ownership transfer is remote. 14

CSUSB is exploring options to meet current and future energy needs. One option 15

includes continued use of the fuel cell unit to avoid impacts of grid outage events (i.e., from PSPS). 16

However, there are significant modifications required for the fuel cell to provide energy to the 17

university. For example, the unit would have to transition from serving the overall grid to the university 18

which entails additional investment to island the unit and ensure there is energy storage and backup 19

power supply for the fuel cell to be reliable during long outages. In addition, the fuel cell is too small to 20

provide all CSUSB’s electrical energy requirements. The significant costs it requires to keep in service a 21

fuel cell unit with insufficient capacity leads SCE to believe that decommissioning is the most likely 22

outcome. 23

SCE therefore recommends that the Commission accepts SCE’s original 24

decommissioning funding request. 25

b) 35% Contingency Is Appropriate For Preliminary Cost Estimates 26

TURN has included a recommendation to reduce SCE’s contingency from 25% to 27

15% with comparisons to PG&E’s approach to fossil decommissioning estimates. As stated in response 28

to data request TURN-SCE-069, Question 16: 29

52

Contingency is routinely added to a base cost estimate to account for lack of precision 1 about inevitable costs that are expected to arise. SCE commonly applies contingency 2 consistent with its SCE Unit Cost Guide on the CAISO website. This guide describes 3 35% contingency as a commonly used contingency percentage for preliminary 4 estimates at SCE and in previous regulatory filings. In this case, a 35% contingency 5 was applied, but only to the contract services portion of the estimate. Note the Santa 6 Barbara estimate contingency value is understated due to a formula error that didn’t 7 include the full range of contract services. Although it would be reasonable to update 8 in errata, SCE proposes retaining the same estimate as a conservative approach. 9

SCE has developed a standard contingency application for preliminary cost 10

estimates using 35%. This application was developed considering guidelines from the Association for 11

the Advancement of Cost Engineering, which describe contingency in general terms but are not 12

prescriptive on specific percentages. Given the scope definition and the preliminary nature of these 13

estimates, SCE believes that 35% contingency is appropriate, and TURN’s proposal should be rejected. 14

Also, the comparison to PG&E’s fossil decommissioning estimates is not reasonable as one can’t 15

compare these different estimates without first understanding the details and scope definition of each 16

individual estimate. This notion of comparing this estimate to PG&E should also be rejected. 17

Appendix A

Select Data Request Responses


Appendix A

A1

Index

Data Request Pages

TURN-SCE-062, Question 08 A2 - A26

TURN-SCE-062, Question 10 A27 - A28

TURN-SCE-062, Question 18 A29



Southern California Edison

A.19-08-013 – SCE 2021 General Rate Case

DATA REQUEST SET T U R N - S C E - 0 6 2

To: TURN Prepared by: Juliet Zabasajja

Job Title: Sr. Advisor Received Date: 4/10/2020

Response Date: 4/22/2020

Question 08: Provide a copy of the report for the Perris site prepared by the independent roofing consultant referenced on page 165. Response to Question 08: Please find in attachment TURN-SCE-062-08 20110317 Dexus Final Roof Inspection, the report for the Perris site prepared by the independent roofing consultant (Independent Roofing Consultants) referenced on page 165 of SCE-05 V.01. were performed,

A2

A3

A4

A5

A6

A7

A8

A9

A10

A11

A12

A13

A14

A15

A16

A17

A18

A19

A20

A21

A22

A23

A24

A25

A26




To: TURN Prepared by: Juliet Zabasajja



Question 10: Why was it reasonable for SCE to execute a contract that required removal of the PV system entirely at SCE’s cost in the event that the building owner decided to re-roof the structure at any point during the lease term? Response to Question 10: The lease contract and terms, including those associated with the removal of the PV system, are reasonable for several reasons. First, the CPUC approved SCE’s Solar Photovoltaic Program (SPVP) in Decision (D.) 09-06-049 (SPVP Decision) in an effort to advance the market for commercial rooftop solar, which at that time was not well developed but viewed as having potential. D.09-06-049 required SCE to submit recorded capital expenditures, annual O&M, and lease costs for reasonableness reviews in SCE’s subsequent GRCs. See D.09-06-049, pp. 44-45. The CPUC has subsequently reviewed and approved all SPVP capital expenditure costs as reasonable, with zero disallowances. See D.12-11-051, p. 84 and D.15-11-021, p.30. The CPUC also has reviewed and approved all SPVP O&M expenses and lease costs as reasonable, with the sole exception of costs SCE incurred to terminate a solar-panel supply contract. See D.15-11-021, p. 30 (approving 2008-2012 O&M costs) and D.19-05-020, p. 379 (approving 2013-2014 O&M costs). In particular, the approved capital expenditures, O&M expenses, and lease costs include those incurred in connection with the Perris facility that is the subject of this request. Based on the regulatory history and prior CPUC decisions, the CPUC has determined that it was reasonable for SCE to execute the lease contract for the Perris facility SPVP installation, and to date has found all lease costs associated with that contract to be reasonable. Second, the SPVP Decision and subsequent GRC decisions approved the proposed structure of the SPVP, which involved the installation of solar facilities on the leased roof tops of large commercial buildings owned and controlled by third-party property owners/lessors. As such, the SPVP necessarily involved SCE’s entering into leases that would be subject to costs typically borne by a lessee, such as the costs to remove structures, fixtures, etc. installed by the lessee. It is further reasonable to expect that a property owner/lessor would retain the right to make roofing and other structural building repairs necessary to protect the integrity of the building, without incurring costs to remove structures, fixtures, etc. added by the lessee. Further to this point, it is also important to recognize that when SCE initiated the SPVP, the concept of leasing roof space for PV panel installations was novel. There was resistance from property owners/lessors to allow a third party to install electrical equipment on their roofs, and concern regarding how the equipment would affect the structural integrity of the roofs and buildings, operations and activities within the buildings, and A27

TURN‐SCE‐062: 10 Page 2 of 2

other tenants. Thus, the lease terms that were made available to SCE by Dexus Perris CA Inc. reasonably allowed Whirlpool Corporation (as the property owner/lessor) to make necessary repairs to the roof of its buildings without incurring costs to remove structures, fixtures, etc. added by SCE. It would have been unreasonable for SCE or any leasing party to expect a property owner/lessor to bear the cost of removal and re-installation of the panels, unless the original lease cost was significantly higher to compensate the property owner/lessor for this cost. In such a scenario, the resultant annual costs associated with the leases would have been much higher and substantially less cost-effective to SCE customers. Third, SCE took reasonable actions to assess the risk regarding whether it would have to remove solar panels due to a roof needing to be repaired. Prior to SPV installation, the Dexus rooftop membrane was inspected and determined to have at least 20-years of remaining life in alignment with the SPV panel life expectancy. (See response to TURN-SCE-062 Q08, “20110317 Dexus Final Roof Inspection.pdf” for a copy of the Dexus roof report). Given the estimated 20-year remaining rooftop membrane life expectancy, the contract terms were determined to be reasonable and acceptable.

A28




To: TURN Prepared by: Serge Handschin

Job Title: Senior Advisor Received Date: 4/10/2020


Question 18: Please provide any written communications between UCSB and CSUSB regarding whether they will (a) retain the assets; (b) ask SCE to continue to operate the assets; or (c) request removal of the assets beyond the terms of their contracts in 2022 and 2023 respectively. Response to Question 18: SCE regularly communicates with large institutional customers such as the universities regarding their energy needs and billing issues. While the topic of the fuel cells has come up informally, SCE nor UCSB and CSUSB have exchanged written communications regarding future options beyond the terms of their contracts.

A29




To: TURN Prepared by: David Gunn



Question 16: Why is there a 25% contingency on the removal of fuel cells ($106,750 versus a cost before contingency of $424,920 for Santa Barbara, and similar for San Bernardino)? Response to Question 16: Contingency is routinely added to a base cost estimate to account for lack of precision about inevitable costs that are expected to arise. SCE commonly applies contingency consistent with its SCE Unit Cost Guide on the CAISO website. This guide describes 35% as a commonly used contingency percentage for preliminary estimates at SCE and in previous regulatory filings.

In this case, 35% contingency was applied, but only to the contract services portion of the estimate. Note the Santa Barbara estimate contingency value is understated due to a formula error that didn’t include the full range of contract services. Although it would be reasonable to update in errata, SCE proposes retaining the same estimate as a conservative approach.

A30




To: TURN Prepared by: David Gunn



Question 18: Regarding interim retirements at Palo Verde, the recorded costs were much higher in 2011 than in all other years. Was there a steam generator replacement or other major capital project at any of the units of Palo Verde in 2011? If so, identify the capital project and the cost of that project, and discuss the likelihood that a similar project would be done at Palo Verde prior to its closure. Response to Question 18:

At least a portion of the recorded costs and retirements in 2011 are attributable to a steam generator replacement project. Because of the nature of the accounting process for Palo Verde, specific work orders identifying the cost of the steam generator replacement project are not readily available.

It is uncertain whether a project of similar size would be done at Palo Verde prior to its closure. For example, APS indicates that in the next ten years three evaporative pond liners will require replacement at a cost of approximately $30 million each. SCE notes, despite the effect 2011 has on the historical analysis, a 0.55% weighted average interim retirement rate produces a reasonable estimate. At 0.55% per year, the average life of each component is approximately 90 years, with a maximum life of 180 years (i.e., 1/0.55% = ~180), far exceeding the license-driven remaining life of 25 years.

A31

Appendix B

Workpapers in Support of SCE’s Rebuttal Testimony


Appendix B

B1

Index

Document Pages

SCE & TURN Depreciation Proposal Parameters B2 - B4

Alternative Gradualism Scenarios for Net Salvage B5 - B10

SCE, Cal Advocates, and TURN T&D Depreciation Proposals B11 - B14

SCE’s Authorized and Proposed T&D Lives and Net Salvage B15 - B16

PG&E and SDG&E Authorized/Pending Authorization Depreciation Rates B17 - B19

Comparison of California IOU Authorized Depreciation Rates B20 - B21

Account 368 Debit Reserve Forecast B22 - B23

Straight-Line vs. Inflation Deferred Method B24 - B25

Perris Decommissioning Impact Table B26 - B27

STANDARD PRACTICE U-4 B28 - B29

SCE-18, Vol. 03, Depreciation Study, Hydro and Other Decommissioning, Other Generation


Witness: David Gunn

SCE & TURN Depreciation Proposal Parameters

B2


Annual Accrual Rate Determination

in thousands of Dollars

SCE Proposal

For Estimated Year 2021

Calculation of Annual Depreciation Expense Rates and Lives (in Thousands of Dollars)

FERC Gross Est. Future Net Salvage Depr. Depr. Average Rem. Annual Depr. Annual

Account Description Plant % Amount Reserve Balance Curve Serv. Life Life Depr. Rate Res. Adj.

A B C D E=C x D F G=C‐E‐F H I J K=G/J L=K/C

Transmission and Distribution

Transmission

350.2 Easements 211,617 0.0 % ‐ 32,423 179,194 60 3,527 1.67%

352 Structures and Improvements 983,751 (35.0%) (344,313) 176,347 1,151,716 L 1.0 55 48 23,803 2.42%

353 Station Equipment 6,071,410 (15.0%) (910,712) 1,064,912 5,917,210 L 0.5 45 38 157,378 2.59%

Transmission Substations 7,055,161 (17.8%) (1,255,024) 1,241,259 7,068,926 46 39 181,181 2.57%

354 Towers and Fixtures 2,355,779 (80.0%) (1,884,623) 610,553 3,629,849 R 5.0 65 53 68,094 2.89%

355 Poles and Fixtures 1,500,196 (90.0%) (1,350,176) 161,028 2,689,345 SC 65 61 44,392 2.96%

356 Overhead Conductors & Devices 1,653,093 (100.0%) (1,653,093) 689,158 2,617,029 R 3.0 61 48 54,719 3.31%

357 Underground Conduit 271,487 0.0 % ‐ 28,188 243,299 R 3.0 55 49 4,962 1.83%

358 Underground Conductors & Devices 399,340 (30.0%) (119,802) 104,278 414,864 S 1.0 45 36 11,462 2.87%

359 Roads and Trails 195,497 0.0 % ‐ 27,090 168,407 R 5.0 60 52 3,219 1.65%

Transmission Lines 6,375,392 (78.5%) (5,007,695) 1,620,294 9,762,793 62 52 186,848 2.93%

Distribution

360.2 Easements 59,756 0.0 % ‐ 12,106 47,650 60 996 1.67%

361 Structures and Improvements 696,488 (40.0%) (278,595) 208,346 766,737 L 0.5 55 46 16,598 2.38%

362 Station Equipment 2,726,408 (40.0%) (1,090,563) 500,805 3,316,166 S ‐0.5 65 57 58,531 2.15%

Distribution Substations 3,422,896 (40.0%) (1,369,158) 709,151 4,082,903 63 54 75,129 2.19%

364 Poles, Towers and Fixtures 3,147,642 (210.0%) (6,610,048) 801,444 8,956,245 R 1.0 55 47 188,697 5.99%


366 Underground Conduit 2,389,265 (80.0%) (1,911,412) 530,372 3,770,306 R 3.0 59 46 81,841 3.43%

367 Underground Conductors & Devices 6,486,079 (100.0%) (6,486,079) 2,339,532 10,632,627 L 1.0 47 38 278,960 4.30%

368 Line Transformers 4,218,947 (50.0%) (2,109,474) 815,453 5,512,968 S 1.5 33 23 238,822 5.66%

369 Services 1,494,348 (100.0%) (1,494,348) 928,312 2,060,385 R 1.5 55 42 49,623 3.32%

Distribution Lines 19,578,775 (112.9%) (22,112,097) 5,955,811 35,735,061 48 38 941,864 4.81%

370 Meters 1,011,251 (5.0%) (50,563) 419,890 641,924 R 3.0 20 11 58,728 5.81%

373 Installations on Customer Premises 12,373 (100.0%) (12,373) 151 24,594 R 1.5 55 55 447 3.61%

373 Street Lighting & Signal Systems 862,112 (50.0%) (431,056) 195,899 1,097,268 L 0.5 50 40 27,290 3.17%

B3


Annual Accrual Rate Determination

in thousands of Dollars

TURN Proposal

For Estimated Year 2021

Calculation of Annual Depreciation Expense Rates and Lives (in Thousands of Dollars)

FERC Gross Est. Future Net Salvage Depr. Depr. Average Rem. Annual Depr. Annual

Account Description Plant % Amount Reserve Balance Curve Serv. Life Life Depr. Rate Res. Adj.

A B C D E=C x D F G=C‐E‐F H I J K=G/J L=K/C

Transmission and Distribution

Transmission

350.2 Easements 211,617 0.0 % ‐ 32,423 179,194 60 3,527 1.67%

352 Structures and Improvements 983,751 (35.0%) (344,313) 176,347 1,151,716 L 0.5 58 52 22,123 2.25%

353 Station Equipment 6,071,410 (15.0%) (910,712) 1,064,912 5,917,210 L 0.5 45 38 157,378 2.59%

Transmission Substations 7,055,161 (17.8%) (1,255,024) 1,241,259 7,068,926 47 39 179,501 2.54%

354 Towers and Fixtures 2,355,779 (65.0%) (1,531,256) 610,553 3,276,483 R 5.0 69 57 57,297 2.43%

355 Poles and Fixtures 1,500,196 (77.0%) (1,155,151) 161,028 2,494,319 SC 65 61 41,173 2.74%


357 Underground Conduit 271,487 0.0 % ‐ 28,188 243,299 R 3.0 55 49 4,962 1.83%

358 Underground Conductors & Devices 399,340 (19.0%) (75,875) 104,278 370,936 S 1.0 45 36 10,248 2.57%

359 Roads and Trails 195,497 0.0 % ‐ 27,090 168,407 R 5.0 60 52 3,219 1.65%

Transmission Lines 6,375,392 (65.4%) (4,167,411) 1,620,294 8,922,509 65 55 162,760 2.55%

Distribution

360.2 Easements 59,756 0.0 % ‐ 12,106 47,650 60 996 1.67%

361 Structures and Improvements 696,488 (29.0%) (201,981) 208,346 690,124 L 0 58 50 13,714 1.97%

362 Station Equipment 2,726,408 (29.0%) (790,658) 500,805 3,016,261 L 0 67 59 50,807 1.86%

Distribution Substations 3,422,896 (29.0%) (992,640) 709,151 3,706,385 65 57 64,520 1.88%

364 Poles, Towers and Fixtures 3,147,642 (210.0%) (6,610,048) 801,444 8,956,245 R 1.0 55 47 188,697 5.99%


366 Underground Conduit 2,389,265 (43.0%) (1,027,384) 530,372 2,886,278 R 2.5 64 52 55,969 2.34%

367 Underground Conductors & Devices 6,486,079 (70.0%) (4,540,256) 2,339,532 8,686,803 L 1.0 47 38 227,909 3.51%

368 Line Transformers 4,218,947 (28.0%) (1,181,305) 815,453 4,584,800 S 1.5 33 23 198,612 4.71%

369 Services 1,494,348 (100.0%) (1,494,348) 928,312 2,060,385 R 1.5 60 46 44,395 2.97%

Distribution Lines 19,578,775 (88.5%) (17,322,281) 5,955,811 30,945,244 49 39 797,177 4.07%

370 Meters 1,011,251 (5.0%) (50,563) 419,890 641,924 R 3.0 30 20 31,520 3.12%

373 Installations on Customer Premises 12,373 (100.0%) (12,373) 151 24,594 R 1.5 55 55 447 3.61%

373 Street Lighting & Signal Systems 862,112 (35.0%) (301,739) 195,899 967,951 L 0.5 50 40 24,075 2.79%

B4



Witness: David Gunn

Alternative Gradualism Scenarios for Net Salvage

B5

Southern California Edison2021 GRC Depreciation StudyComparison of Net Salvage Rates

FERC SCE TURN - 25% 30% 40% 50%Acct Description Authorized Proposed Gradualism Gradualism Gradualism Gradualism

A B C D E=(D-C)*25%+C F=(D-C)*30%+C G=(D-C)*40%+C H=(D-C)*50%+CTransmission Plant

352 Structures and Improvements -35% -35% -35% -35% -35% -35%353 Station Equipment -15% -15% -15% -15% -15% -15%354 Towers and Fixtures -60% -80% -65% -66% -68% -70%355 Poles and Fixtures -72% -90% -77% -77% -79% -81%356 Overhead Conductors & Devices -80% -100% -85% -86% -88% -90%357 Underground Conduit 0% 0% 0% 0% 0% 0%358 Underground Conductors & Devices -15% -30% -19% -20% -21% -23%359 Roads and Trails 0% 0% 0% 0% 0% 0%

Distribution Plant361 Structures and Improvements -25% -40% -29% -30% -31% -33%362 Station Equipment -25% -40% -29% -30% -31% -33%364 Poles, Towers and Fixtures -210% -210% -210% -210% -210% -210%365 Overhead Conductors & Devices -115% -190% -134% -138% -145% -153%366 Underground Conduit -30% -80% -43% -45% -50% -55%367 Underground Conductors & Devices -60% -100% -70% -72% -76% -80%368 Line Transformers -20% -50% -28% -29% -32% -35%369 Services -100% -100% -100% -100% -100% -100%370 Meters -5% -5% -5% -5% -5% -5%371 Installations on Customer Premises -100% -100% -100% -100% -100% -100%373 Street Lighting & Signal Systems -30% -50% -35% -36% -38% -40%

General Buildings390 Structures and Improvements -10% -10% -10% -10% -10% -10%

B6

Southern California Edison2021 GRC Depreciation StudyComparison of Transmission and Distribution Depreciation Rates25% Net Salvage Gradualismin Dollars

2018 GRC Authorized 2018 GRC Auth. NSR 2021 GRC Proposed Impact Impact Total IncreaseFERC CPUC Plant (Lives and NSRs) 2021 GRC Prop. Life (Lives and NSRs) due to due to (Decrease)Acct Description Jan 1, 2019 Rate Expense Rate Expense Rate Expense Life Proposals1 NSR Proposals in Accrual

A B C D E=C*D F G=C*F H I=C*H J=G-E K=I-G L=J+KTransmission Plant

352 Structures and Improvements 340,075,763 2.41% $8,195,826 2.25% $7,651,705 2.25% $7,651,705 ($544,121) $0 ($544,121)353 Station Equipment 2,612,060,862 2.58% 67,391,170 2.59% 67,652,376 2.59% 67,652,376 $261,206 $0 $261,206354 Towers and Fixtures 71,069,207 2.46% 1,748,302 2.34% 1,663,019 2.43% 1,726,982 ($85,283) $63,962 ($21,321)355 Poles and Fixtures 1,113,653,589 2.54% 28,286,801 2.66% 29,623,185 2.74% 30,514,108 $1,336,384 $890,923 $2,227,307356 Overhead Conductors & Devices 341,584,044 2.83% 9,666,828 2.68% 9,154,452 2.77% 9,461,878 ($512,376) $307,426 ($204,950)357 Underground Conduit 80,595,837 1.73% 1,394,308 1.82% 1,466,844 1.83% 1,474,904 $72,536 $8,060 $80,596358 Underground Conductors & Devices 315,350,326 2.30% 7,253,057 2.46% 7,757,618 2.57% 8,104,503 $504,561 $346,885 $851,446359 Roads and Trails 21,713,455 1.65% 358,272 1.65% 358,272 1.65% 358,272 $0 $0 $0

Distribution Plant $0 $0 $0361 Structures and Improvements 696,487,874 2.27% 15,810,275 1.89% 13,163,621 1.97% 13,720,811 ($2,646,654) $557,190 ($2,089,464)362 Station Equipment 2,726,408,043 1.90% 51,801,753 1.80% 49,075,345 1.86% 50,711,190 ($2,726,408) $1,635,845 ($1,090,563)364 Poles, Towers and Fixtures 3,147,641,758 5.96% 187,599,449 5.99% 188,543,741 5.99% 188,543,741 $944,293 $0 $944,293365 Overhead Conductors & Devices 1,842,492,281 3.85% 70,935,953 4.02% 74,068,190 4.43% 81,622,408 $3,132,237 $7,554,218 $10,686,455366 Underground Conduit 2,389,265,472 2.27% 54,236,326 2.09% 49,935,648 2.34% 55,908,812 ($4,300,678) $5,973,164 $1,672,486367 Underground Conductors & Devices 6,486,079,350 3.51% 227,661,385 3.25% 210,797,579 3.51% 227,661,385 ($16,863,806) $16,863,806 $0368 Line Transformers 4,218,947,448 4.35% 183,524,214 4.36% 183,946,109 4.71% 198,712,425 $421,895 $14,766,316 $15,188,211369 Services 1,494,348,468 3.27% 48,865,195 2.97% 44,382,149 2.97% 44,382,149 ($4,483,045) $0 ($4,483,045)370 Meters 1,011,251,062 5.99% 60,573,939 3.12% 31,551,033 3.12% 31,551,033 ($29,022,905) $0 ($29,022,905)371 Installations on Customer Premises 12,372,731 4.44% 549,349 3.61% 446,656 3.61% 446,656 ($102,694) $0 ($102,694)373 Street Lighting & Signal Systems 862,111,578 2.79% 24,052,913 2.66% 22,932,168 2.79% 24,052,913 ($1,120,745) $1,120,745 $0

General Buildings $0 $0 $0390 Structures and Improvements 1,079,844,132 2.08% 22,460,758 1.82% 19,653,163 1.82% 19,653,163 ($2,807,595) $0 ($2,807,595)

Total 30,863,353,278 3.47% 1,072,366,074 3.28% 1,013,822,874 3.45% 1,063,911,415 (58,543,199) 50,088,540 (8,454,659) / 1 Includes impact from applying authorized parameters to updated recorded balances (i.e., passage of time)

B7




352 Structures and Improvements 340,075,763 2.41% $8,195,826 2.25% $7,651,705 2.25% $7,651,705 ($544,121) $0 ($544,121)353 Station Equipment 2,612,060,862 2.58% 67,391,170 2.59% 67,652,376 2.59% 67,652,376 $261,206 $0 $261,206354 Towers and Fixtures 71,069,207 2.46% 1,748,302 2.34% 1,663,019 2.45% 1,741,196 ($85,283) $78,176 ($7,107)355 Poles and Fixtures 1,113,653,589 2.54% 28,286,801 2.66% 29,623,185 2.74% 30,514,108 $1,336,384 $890,923 $2,227,307356 Overhead Conductors & Devices 341,584,044 2.83% 9,666,828 2.68% 9,154,452 2.79% 9,530,195 ($512,376) $375,742 ($136,634)357 Underground Conduit 80,595,837 1.73% 1,394,308 1.82% 1,466,844 1.83% 1,474,904 $72,536 $8,060 $80,596358 Underground Conductors & Devices 315,350,326 2.30% 7,253,057 2.46% 7,757,618 2.59% 8,167,573 $504,561 $409,955 $914,516359 Roads and Trails 21,713,455 1.65% 358,272 1.65% 358,272 1.65% 358,272 $0 $0 $0

Distribution Plant $0 $0 $0361 Structures and Improvements 696,487,874 2.27% 15,810,275 1.89% 13,163,621 1.99% 13,860,109 ($2,646,654) $696,488 ($1,950,166)362 Station Equipment 2,726,408,043 1.90% 51,801,753 1.80% 49,075,345 1.88% 51,256,471 ($2,726,408) $2,181,126 ($545,282)364 Poles, Towers and Fixtures 3,147,641,758 5.96% 187,599,449 5.99% 188,543,741 5.99% 188,543,741 $944,293 $0 $944,293365 Overhead Conductors & Devices 1,842,492,281 3.85% 70,935,953 4.02% 74,068,190 4.52% 83,280,651 $3,132,237 $9,212,461 $12,344,698366 Underground Conduit 2,389,265,472 2.27% 54,236,326 2.09% 49,935,648 2.38% 56,864,518 ($4,300,678) $6,928,870 $2,628,192367 Underground Conductors & Devices 6,486,079,350 3.51% 227,661,385 3.25% 210,797,579 3.57% 231,553,033 ($16,863,806) $20,755,454 $3,891,648368 Line Transformers 4,218,947,448 4.35% 183,524,214 4.36% 183,946,109 4.75% 200,400,004 $421,895 $16,453,895 $16,875,790369 Services 1,494,348,468 3.27% 48,865,195 2.97% 44,382,149 2.97% 44,382,149 ($4,483,045) $0 ($4,483,045)370 Meters 1,011,251,062 5.99% 60,573,939 3.12% 31,551,033 3.12% 31,551,033 ($29,022,905) $0 ($29,022,905)371 Installations on Customer Premises 12,372,731 4.44% 549,349 3.61% 446,656 3.61% 446,656 ($102,694) $0 ($102,694)373 Street Lighting & Signal Systems 862,111,578 2.79% 24,052,913 2.66% 22,932,168 2.82% 24,311,546 ($1,120,745) $1,379,379 $258,633

General Buildings $0 $0 $0390 Structures and Improvements 1,079,844,132 2.08% 22,460,758 1.82% 19,653,163 1.82% 19,653,163 ($2,807,595) $0 ($2,807,595)

Total 30,863,353,278 3.47% 1,072,366,074 3.28% 1,013,822,874 3.48% 1,073,193,404 (58,543,199) 59,370,530 827,330 / 1 Includes impact from applying authorized parameters to updated recorded balances (i.e., passage of time

B8




352 Structures and Improvements 340,075,763 2.41% $8,195,826 2.25% $7,651,705 2.25% $7,651,705 ($544,121) $0 ($544,121)353 Station Equipment 2,612,060,862 2.58% 67,391,170 2.59% 67,652,376 2.59% 67,652,376 261,206 - 261,206 354 Towers and Fixtures 71,069,207 2.46% 1,748,302 2.34% 1,663,019 2.48% 1,762,516 (85,283) 99,497 14,214 355 Poles and Fixtures 1,113,653,589 2.54% 28,286,801 2.66% 29,623,185 2.78% 30,959,570 1,336,384 1,336,384 2,672,769 356 Overhead Conductors & Devices 341,584,044 2.83% 9,666,828 2.68% 9,154,452 2.83% 9,666,828 (512,376) 512,376 - 357 Underground Conduit 80,595,837 1.73% 1,394,308 1.82% 1,466,844 1.83% 1,474,904 72,536 8,060 80,596 358 Underground Conductors & Devices 315,350,326 2.30% 7,253,057 2.46% 7,757,618 2.62% 8,262,179 504,561 504,561 1,009,121 359 Roads and Trails 21,713,455 1.65% 358,272 1.65% 358,272 1.65% 358,272 - - -

Distribution Plant361 Structures and Improvements 696,487,874 2.27% 15,810,275 1.89% 13,163,621 2.01% 13,999,406 (2,646,654) 835,785 (1,810,868) 362 Station Equipment 2,726,408,043 1.90% 51,801,753 1.80% 49,075,345 1.90% 51,801,753 (2,726,408) 2,726,408 - 364 Poles, Towers and Fixtures 3,147,641,758 5.96% 187,599,449 5.99% 188,543,741 5.99% 188,543,741 944,293 - 944,293 365 Overhead Conductors & Devices 1,842,492,281 3.85% 70,935,953 4.02% 74,068,190 4.67% 86,044,390 3,132,237 11,976,200 15,108,437 366 Underground Conduit 2,389,265,472 2.27% 54,236,326 2.09% 49,935,648 2.48% 59,253,784 (4,300,678) 9,318,135 5,017,457 367 Underground Conductors & Devices 6,486,079,350 3.51% 227,661,385 3.25% 210,797,579 3.67% 238,039,112 (16,863,806) 27,241,533 10,377,727 368 Line Transformers 4,218,947,448 4.35% 183,524,214 4.36% 183,946,109 4.88% 205,884,635 421,895 21,938,527 22,360,421 369 Services 1,494,348,468 3.27% 48,865,195 2.97% 44,382,149 2.97% 44,382,149 (4,483,045) - (4,483,045) 370 Meters 1,011,251,062 5.99% 60,573,939 3.12% 31,551,033 3.12% 31,551,033 (29,022,905) - (29,022,905) 371 Installations on Customer Premises 12,372,731 4.44% 549,349 3.61% 446,656 3.61% 446,656 (102,694) - (102,694) 373 Street Lighting & Signal Systems 862,111,578 2.79% 24,052,913 2.66% 22,932,168 2.87% 24,742,602 (1,120,745) 1,810,434 689,689

General Buildings390 Structures and Improvements 1,079,844,132 2.08% 22,460,758 1.82% 19,653,163 1.82% 19,653,163 (2,807,595) - (2,807,595)

Total 30,863,353,278 3.47% 1,072,366,074 3.28% 1,013,822,874 3.54% 1,092,130,775 (58,543,199) 78,307,900 19,764,701 / 1 Includes impact from applying authorized parameters to updated recorded balances (i.e., passage of time)

B9




352 Structures and Improvements 340,075,763 2.41% $8,195,826 2.25% $7,651,705 2.25% $7,651,705 ($544,121) $0 ($544,121)353 Station Equipment 2,612,060,862 2.58% 67,391,170 2.59% 67,652,376 2.59% 67,652,376 261,206 - 261,206 354 Towers and Fixtures 71,069,207 2.46% 1,748,302 2.34% 1,663,019 2.52% 1,790,944 (85,283) 127,925 42,642 355 Poles and Fixtures 1,113,653,589 2.54% 28,286,801 2.66% 29,623,185 2.81% 31,293,666 1,336,384 1,670,480 3,006,865 356 Overhead Conductors & Devices 341,584,044 2.83% 9,666,828 2.68% 9,154,452 2.87% 9,803,462 (512,376) 649,010 136,634 357 Underground Conduit 80,595,837 1.73% 1,394,308 1.82% 1,466,844 1.83% 1,474,904 72,536 8,060 80,596 358 Underground Conductors & Devices 315,350,326 2.30% 7,253,057 2.46% 7,757,618 2.68% 8,451,389 504,561 693,771 1,198,331 359 Roads and Trails 21,713,455 1.65% 358,272 1.65% 358,272 1.65% 358,272 - - -

Distribution Plant361 Structures and Improvements 696,487,874 2.27% 15,810,275 1.89% 13,163,621 2.05% 14,278,001 (2,646,654) 1,114,381 (1,532,273) 362 Station Equipment 2,726,408,043 1.90% 51,801,753 1.80% 49,075,345 1.93% 52,619,675 (2,726,408) 3,544,330 817,922 364 Poles, Towers and Fixtures 3,147,641,758 5.96% 187,599,449 5.99% 188,543,741 5.99% 188,543,741 944,293 - 944,293 365 Overhead Conductors & Devices 1,842,492,281 3.85% 70,935,953 4.02% 74,068,190 4.84% 89,176,626 3,132,237 15,108,437 18,240,674 366 Underground Conduit 2,389,265,472 2.27% 54,236,326 2.09% 49,935,648 2.58% 61,643,049 (4,300,678) 11,707,401 7,406,723 367 Underground Conductors & Devices 6,486,079,350 3.51% 227,661,385 3.25% 210,797,579 3.78% 245,173,799 (16,863,806) 34,376,221 17,512,414 368 Line Transformers 4,218,947,448 4.35% 183,524,214 4.36% 183,946,109 5.01% 211,369,267 421,895 27,423,158 27,845,053 369 Services 1,494,348,468 3.27% 48,865,195 2.97% 44,382,149 2.97% 44,382,149 (4,483,045) - (4,483,045) 370 Meters 1,011,251,062 5.99% 60,573,939 3.12% 31,551,033 3.12% 31,551,033 (29,022,905) - (29,022,905) 371 Installations on Customer Premises 12,372,731 4.44% 549,349 3.61% 446,656 3.61% 446,656 (102,694) - (102,694) 373 Street Lighting & Signal Systems 862,111,578 2.79% 24,052,913 2.66% 22,932,168 2.92% 25,173,658 (1,120,745) 2,241,490 1,120,745

General Buildings390 Structures and Improvements 1,079,844,132 2.08% 22,460,758 1.82% 19,653,163 1.82% 19,653,163 (2,807,595) - (2,807,595)


B10



Witness: David Gunn

SCE, Cal Advocates, and TURN T&D Depreciation Proposals

B11

Southern California Edison2021 GRC Depreciation StudyComparison of Transmission and Distribution Depreciation RatesSCE's Proposalin Dollars


A B C D E=C*D F G=C*F H I=C*H J=G-E K=I-G L=J+KTransmission Plant350.2 Easements 55,868,644 1.67% $933,006 1.67% $933,006 1.67% $933,006 $0 $0 $0352 Structures and Improvements 340,075,763 2.41% $8,195,826 2.42% $8,229,833 2.42% $8,229,833 $34,008 $0 $34,008353 Station Equipment 2,612,060,862 2.58% 67,391,170 2.59% 67,652,376 2.59% 67,652,376 261,206 - 261,206 354 Towers and Fixtures 71,069,207 2.46% 1,748,302 2.52% 1,790,944 2.89% 2,053,900 42,642 262,956 305,598 355 Poles and Fixtures 1,113,653,589 2.54% 28,286,801 2.66% 29,623,185 2.96% 32,964,146 1,336,384 3,340,961 4,677,345 356 Overhead Conductors & Devices 341,584,044 2.83% 9,666,828 2.89% 9,871,779 3.31% 11,306,432 204,950 1,434,653 1,639,603 357 Underground Conduit 80,595,837 1.73% 1,394,308 1.82% 1,466,844 1.83% 1,474,904 72,536 8,060 80,596 358 Underground Conductors & Devices 315,350,326 2.30% 7,253,057 2.46% 7,757,618 2.87% 9,050,554 504,561 1,292,936 1,797,497 359 Roads and Trails 21,713,455 1.65% 358,272 1.65% 358,272 1.65% 358,272 - - -

Distribution Plant360.2 Easements 59,756,182 1.67% 997,928 1.67% 997,928 1.67% 997,928 - - - 361 Structures and Improvements 696,487,874 2.27% 15,810,275 2.06% 14,347,650 2.38% 16,576,411 (1,462,625) 2,228,761 766,137 362 Station Equipment 2,726,408,043 1.90% 51,801,753 1.88% 51,256,471 2.15% 58,617,773 (545,282) 7,361,302 6,816,020 364 Poles, Towers and Fixtures 3,147,641,758 5.96% 187,599,449 5.99% 188,543,741 5.99% 188,543,741 944,293 - 944,293 365 Overhead Conductors & Devices 1,842,492,281 3.85% 70,935,953 4.02% 74,068,190 5.64% 103,916,565 3,132,237 29,848,375 32,980,612 366 Underground Conduit 2,389,265,472 2.27% 54,236,326 2.34% 55,908,812 3.43% 81,951,806 1,672,486 26,042,994 27,715,479 367 Underground Conductors & Devices 6,486,079,350 3.51% 227,661,385 3.25% 210,797,579 4.30% 278,901,412 (16,863,806) 68,103,833 51,240,027 368 Line Transformers 4,218,947,448 4.35% 183,524,214 4.36% 183,946,109 5.66% 238,792,426 421,895 54,846,317 55,268,212 369 Services 1,494,348,468 3.27% 48,865,195 3.32% 49,612,369 3.32% 49,612,369 747,174 - 747,174 370 Meters 1,011,251,062 5.99% 60,573,939 5.81% 58,753,687 5.81% 58,753,687 (1,820,252) - (1,820,252) 371 Installations on Customer Premises 12,372,731 4.44% 549,349 3.61% 446,656 3.61% 446,656 (102,694) - (102,694) 373 Street Lighting & Signal Systems 862,111,578 2.79% 24,052,913 2.66% 22,932,168 3.17% 27,328,937 (1,120,745) 4,396,769 3,276,024


B12

Southern California Edison2021 GRC Depreciation StudyComparison of Transmission and Distribution Depreciation RatesCal Advocates' Proposalin Dollars


A B C D E=C*D F G=C*F H I=C*H J=G-E K=I-G L=J+KTransmission Plant350.2 Easements 55,868,644 1.67% $933,006 1.67% $933,006 1.67% $933,006 $0 $0 $0352 Structures and Improvements 340,075,763 2.41% $8,195,826 2.42% $8,229,833 2.42% $8,229,833 $34,008 $0 $34,008353 Station Equipment 2,612,060,862 2.58% 67,391,170 2.59% 67,652,376 2.59% 67,652,376 261,206 - 261,206 354 Towers and Fixtures 71,069,207 2.46% 1,748,302 2.52% 1,790,944 2.89% 2,053,900 42,642 262,956 305,598 355 Poles and Fixtures 1,113,653,589 2.54% 28,286,801 2.66% 29,623,185 2.96% 32,964,146 1,336,384 3,340,961 4,677,345 356 Overhead Conductors & Devices 341,584,044 2.83% 9,666,828 2.89% 9,871,779 3.31% 11,306,432 204,950 1,434,653 1,639,603 357 Underground Conduit 80,595,837 1.73% 1,394,308 1.82% 1,466,844 1.83% 1,474,904 72,536 8,060 80,596 358 Underground Conductors & Devices 315,350,326 2.30% 7,253,057 2.46% 7,757,618 2.87% 9,050,554 504,561 1,292,936 1,797,497 359 Roads and Trails 21,713,455 1.65% 358,272 1.65% 358,272 1.65% 358,272 - - -

Distribution Plant360.2 Easements 59,756,182 1.67% 997,928 1.67% 997,928 1.67% 997,928 - - - 361 Structures and Improvements 696,487,874 2.27% 15,810,275 2.06% 14,347,650 2.38% 16,576,411 (1,462,625) 2,228,761 766,137 362 Station Equipment 2,726,408,043 1.90% 51,801,753 1.88% 51,256,471 2.15% 58,617,773 (545,282) 7,361,302 6,816,020 364 Poles, Towers and Fixtures 3,147,641,758 5.96% 187,599,449 5.99% 188,543,741 5.99% 188,543,741 944,293 - 944,293 365 Overhead Conductors & Devices 1,842,492,281 3.85% 70,935,953 4.02% 74,068,190 4.34% 79,964,165 3,132,237 5,895,975 9,028,212 366 Underground Conduit 2,389,265,472 2.27% 54,236,326 2.34% 55,908,812 2.67% 63,793,388 1,672,486 7,884,576 9,557,062 367 Underground Conductors & Devices 6,486,079,350 3.51% 227,661,385 3.25% 210,797,579 3.51% 227,661,385 (16,863,806) 16,863,806 - 368 Line Transformers 4,218,947,448 4.35% 183,524,214 4.36% 183,946,109 4.58% 193,227,793 421,895 9,281,684 9,703,579 369 Services 1,494,348,468 3.27% 48,865,195 3.32% 49,612,369 3.32% 49,612,369 747,174 - 747,174 370 Meters 1,011,251,062 5.99% 60,573,939 5.81% 58,753,687 5.81% 58,753,687 (1,820,252) - (1,820,252) 371 Installations on Customer Premises 12,372,731 4.44% 549,349 3.61% 446,656 3.61% 446,656 (102,694) - (102,694) 373 Street Lighting & Signal Systems 862,111,578 2.79% 24,052,913 2.66% 22,932,168 3.17% 27,328,937 (1,120,745) 4,396,769 3,276,024


B13

Southern California Edison2021 GRC Depreciation StudyComparison of Transmission and Distribution Depreciation RatesTURN's Proposalin Dollars


A B C D E=C*D F G=C*F H I=C*H J=G-E K=I-G L=J+KTransmission Plant350.2 Easements 55,868,644 1.67% $933,006 1.67% $933,006 1.67% $933,006 $0 $0 $0352 Structures and Improvements 340,075,763 2.41% $8,195,826 2.25% $7,651,705 2.25% $7,651,705 ($544,121) $0 ($544,121)353 Station Equipment 2,612,060,862 2.58% 67,391,170 2.59% 67,652,376 2.59% 67,652,376 261,206 - 261,206 354 Towers and Fixtures 71,069,207 2.46% 1,748,302 2.34% 1,663,019 2.43% 1,726,982 (85,283) 63,962 (21,321) 355 Poles and Fixtures 1,113,653,589 2.54% 28,286,801 2.66% 29,623,185 2.74% 30,514,108 1,336,384 890,923 2,227,307 356 Overhead Conductors & Devices 341,584,044 2.83% 9,666,828 2.68% 9,154,452 2.77% 9,461,878 (512,376) 307,426 (204,950) 357 Underground Conduit 80,595,837 1.73% 1,394,308 1.82% 1,466,844 1.83% 1,474,904 72,536 8,060 80,596 358 Underground Conductors & Devices 315,350,326 2.30% 7,253,057 2.46% 7,757,618 2.57% 8,104,503 504,561 346,885 851,446 359 Roads and Trails 21,713,455 1.65% 358,272 1.65% 358,272 1.65% 358,272 - - -

Distribution Plant360.2 Easements 59,756,182 1.67% 997,928 1.67% 997,928 1.67% 997,928 - - - 361 Structures and Improvements 696,487,874 2.27% 15,810,275 1.89% 13,163,621 1.97% 13,720,811 (2,646,654) 557,190 (2,089,464) 362 Station Equipment 2,726,408,043 1.90% 51,801,753 1.80% 49,075,345 1.86% 50,711,190 (2,726,408) 1,635,845 (1,090,563) 364 Poles, Towers and Fixtures 3,147,641,758 5.96% 187,599,449 5.99% 188,543,741 5.99% 188,543,741 944,293 - 944,293 365 Overhead Conductors & Devices 1,842,492,281 3.85% 70,935,953 4.02% 74,068,190 4.43% 81,622,408 3,132,237 7,554,218 10,686,455 366 Underground Conduit 2,389,265,472 2.27% 54,236,326 2.09% 49,935,648 2.34% 55,908,812 (4,300,678) 5,973,164 1,672,486 367 Underground Conductors & Devices 6,486,079,350 3.51% 227,661,385 3.25% 210,797,579 3.51% 227,661,385 (16,863,806) 16,863,806 - 368 Line Transformers 4,218,947,448 4.35% 183,524,214 4.36% 183,946,109 4.71% 198,712,425 421,895 14,766,316 15,188,211 369 Services 1,494,348,468 3.27% 48,865,195 2.97% 44,382,149 2.97% 44,382,149 (4,483,045) - (4,483,045) 370 Meters 1,011,251,062 5.99% 60,573,939 3.12% 31,551,033 3.12% 31,551,033 (29,022,905) - (29,022,905) 371 Installations on Customer Premises 12,372,731 4.44% 549,349 3.61% 446,656 3.61% 446,656 (102,694) - (102,694) 373 Street Lighting & Signal Systems 862,111,578 2.79% 24,052,913 2.66% 22,932,168 2.79% 24,052,913 (1,120,745) 1,120,745 -

Total 29,899,133,971 3.52% 1,051,836,251 3.33% 996,100,646 3.50% 1,046,189,186 (55,735,605) 50,088,540 (5,647,064) / 1 Includes impact from applying authorized parameters to updated recorded balances (i.e., passage of time)

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Witness: David Gunn

SCE's Authorized and Proposed T&D Lives and Net Salvage

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Southern California Edison2021 GRC Depreciation StudyTransmission and Distribution Lives and Net Salvage Ratesin Dollars

FERC CPUC Plant Lives Net SalvageAcct Description Jan 1, 2019 Authorized Proposed Authorized Proposed

A B C D E F GTransmission Plant

350.2 Easements 55,868,644 60 60 0% 0%352 Structures and Improvements 340,075,763 55 55 -35% -35%353 Station Equipment 2,612,060,862 45 45 -15% -15%354 Towers and Fixtures 71,069,207 65 65 -60% -80%355 Poles and Fixtures 1,113,653,589 65 65 -72% -90%356 Overhead Conductors & Devices 341,584,044 61 61 -80% -100%357 Underground Conduit 80,595,837 55 55 0% 0%358 Underground Conductors & Devices 315,350,326 45 45 -15% -30%359 Roads and Trails 21,713,455 60 60 0% 0%

Distribution Plant360.2 Easements 59,756,182 60 60 0% 0%361 Structures and Improvements 696,487,874 50 55 -25% -40%362 Station Equipment 2,726,408,043 65 65 -25% -40%364 Poles, Towers and Fixtures 3,147,641,758 55 55 -210% -210%365 Overhead Conductors & Devices 1,842,492,281 55 55 -115% -190%366 Underground Conduit 2,389,265,472 59 59 -30% -80%367 Underground Conductors & Devices 6,486,079,350 43 47 -60% -100%368 Line Transformers 4,218,947,448 33 33 -20% -50%369 Services 1,494,348,468 55 55 -100% -100%370 Meters 1,011,251,062 20 20 -5% -5%371 Installations on Customer Premises 12,372,731 55 55 -100% -100%373 Street Lighting & Signal Systems 862,111,578 48 50 -30% -50%

Total Transmission & Distribution 29,899,133,971 49 50 -62% -87%

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Witness: David Gunn

PG&E and SDG&E Authorized/Pending Authorization Depreciation Rates

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Southern California Edison2021 GRC Depreciation StudyPG&E Pending Authorization Depreciation Rates (2020 GRC)(in $ millions)

FERCAccount Plant

PendingAuthorization

RatesDepreciation

Expense

Composite Depreciation

RateA B C D=B*C E=D/B

Transmission350.02 $3,788 1.29% $49352.01 $451 1.35% $6353.01 $37,596 3.65% $1,372353.02 $104,639 0.64% $670353.03 $66,787 3.63% $2,424

354 $56,867 2.44% $1,388354.01 $15,880 6.88% $1,093

355 $45,696 3.26% $1,490356 $69,538 2.99% $2,079

356.01 $3,784 7.96% $301357 $1,621 0.94% $15358 $3,395 1.49% $51359 $33 1.59% $1

Subtotal $410,075 $10,938 2.67%

Distribution360.02 $117,390 3.31% $3,886361.01 $284,314 1.59% $4,521361.02 $38,598 1.66% $641

362 $3,344,028 3.06% $102,327363 $1,090 3.74% $41

363.01 $32,142 6.62% $2,128364 $4,322,567 6.07% $262,380365 $4,716,483 3.96% $186,773366 $2,861,362 2.41% $68,959367 $4,554,288 3.12% $142,094

368.01 $2,623,693 4.39% $115,180368.02 $827,706 3.91% $32,363369.01 $899,973 3.98% $35,819369.02 $2,372,356 2.71% $64,291370.01 $1,157,714 6.86% $79,419

371 $27,314 0.00% $0372 $895 0.00% $0

373.01 $13,248 3.80% $503373.02 $42,505 2.87% $1,220373.03 $115,047 3.01% $3,463373.04 $61,036 3.78% $2,307

Subtotal $28,413,749 $1,108,314 3.90%

T&D Composite $28,823,824 $1,119,251 3.88%

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Southern California Edison2021 GRC Depreciation StudySDG&E Authorized Depreciation Rates (2019 GRC)(in $ millions)

FERCAccount Plant

AuthorizedRates

DepreciationExpense

CompositeDepreciation

RateA B C D=B*C E=D/B

Transmission350.02 $56,302 0.00% $0352.01 $309,908 1.68% $5,206353.01 $461,521 3.52% $16,246353.02 $1,284,528 3.20% $41,105353.03 $819,864 3.20% $26,236

354 $77,696 1.70% $1,321354.01 $21,696 1.70% $369

355 $907,481 4.59% $41,653356 $254,314 2.67% $6,790

356.01 $13,839 2.67% $369357 $270,503 2.05% $5,545358 $379,995 2.05% $7,790359 $6,983 1.67% $117

Subtotal $4,864,632 $152,747 3.14%

Distribution361 $4,684,420 3.86% $180,819

362.1 $497,743,668 4.75% $23,644,815363 $38,262,884 10.31% $3,945,554364 $671,234,957 4.11% $27,605,880365 $612,265,759 2.88% $17,655,295366 $1,179,180,817 2.63% $30,957,034367 $1,477,512,735 3.38% $50,000,508

368.1 $597,268,188 5.52% $32,962,634368.2 $34,948,635 17.58% $6,142,712369.1 $146,323,666 2.82% $4,131,449369.2 $342,165,360 2.96% $10,138,360370.1 $3,509,707 2.01% $70,605

370.11 $189,867,454 6.71% $12,747,511370.2 $5,231,201 2.04% $106,790

370.21 $50,556,957 6.66% $3,365,273371 $8,616,917 3.05% $262,669

373.2 $29,637,524 4.62% $1,368,690Subtotal $5,889,010,847 $225,286,598 3.83%

T&D Composite $5,893,875,479 $225,439,346 3.82%

B19



Witness: David Gunn

Comparison of California IOU Authorized Depreciation Rates

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Southern California Edison2021 GRC Depreciation StudyComparison of CA IOU Depr Rates(in $ millions)

LineNo. Description Amount1. SCE 3.52%2. PG&E 3.88%3. SDG&E 3.82%

4. Average of PG&E & SDG&E Rates 3.85%

5=4-1 Rate Difference 0.33%

6. SCE Plant Balance 29,899

7=5*6 SCE's additional depreciation expense ifauthorized rates similar to CA IOUs 100

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Witness: David Gunn

Account 368 Debit Reserve Forecast

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Southern California Edison2021 GRC Depreciation StudyAccount 368: Line TransformersDebit Reserve Forecast

2018 Plant Balance $4,217,980,327Authorized Rate 1.66%TURN Proposal 1.58%SCE Proposal 2.54%CalPA Proposal 1.45%

TURN Proposal Recorded Authorized Authorized Proposed Proposed Proposed Proposed2018 2019 2020 2021 2022 2023 2024

Beginning COR Reserve (150,489,973) (160,061,889) (169,633,806) (182,580,107) (195,526,407) (208,472,708) Depreciation Expense* 70,018,473 70,018,473 66,644,089 66,644,089 66,644,089 66,644,089 Cost of Removal** $79,590,390 $79,590,390 $79,590,390 $79,590,390 $79,590,390 $79,590,390Ending COR Reserve (150,489,973) (160,061,889) (169,633,806) (182,580,107) (195,526,407) (208,472,708) (221,419,009)

CalPA Proposal Recorded Authorized Authorized Proposed Proposed Proposed Proposed2018 2019 2020 2021 2022 2023 2024

Beginning COR Reserve (150,489,973) (160,061,889) (169,633,806) (188,063,481) (206,493,156) (224,922,831) Depreciation Expense 70,018,473 70,018,473 61,160,715 61,160,715 61,160,715 61,160,715 Cost of Removal $79,590,390 $79,590,390 $79,590,390 $79,590,390 $79,590,390 $79,590,390Ending COR Reserve (150,489,973) (160,061,889) (169,633,806) (188,063,481) (206,493,156) (224,922,831) (243,352,507)

SCE Proposal Recorded Authorized Authorized Proposed Proposed Proposed Proposed2018 2019 2020 2021 2022 2023 2024

Beginning COR Reserve (150,489,973) (160,061,889) (169,633,806) (142,087,495) (114,541,185) (86,994,875) Depreciation Expense 70,018,473 70,018,473 107,136,700 107,136,700 107,136,700 107,136,700 Cost of Removal $79,590,390 $79,590,390 $79,590,390 $79,590,390 $79,590,390 $79,590,390Ending COR Reserve (150,489,973) (160,061,889) (169,633,806) (142,087,495) (114,541,185) (86,994,875) (59,448,564) *Calculated using YE 2018 Plant Balance and assumes no future plant growth.**Average balance of 2016-2018 Cost of Removal.

B23



Witness: David Gunn

Straight-Line vs. Inflation Deferred Method

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Southern California Edison2021 GRC Depreciation StudyGeneration DecommissioningStraight-Line vs. Inflation Deferred Method

Current cost to Decomm 45,639 Annual inflation Rate 4%Service Life 20

(SCE) (TURN)Cost to Straight Inflation Accrual Inflation

Year Decomm (EOY $) Line Deferred Growth Rate MatchedA B C D E F0 45,639 1 47,464 5,000 2,373 4,107 2 49,363 5,000 2,473 4.2% 4,181 3 51,337 5,000 2,583 4.4% 4,256 4 53,391 5,000 2,704 4.7% 4,335 5 55,526 5,000 2,837 4.9% 4,418 6 57,748 5,000 2,985 5.2% 4,503 7 60,057 5,000 3,150 5.5% 4,592 8 62,460 5,000 3,335 5.9% 4,684 9 64,958 5,000 3,543 6.2% 4,780 10 67,556 5,000 3,779 6.7% 4,880 11 70,259 5,000 4,050 7.2% 4,984 12 73,069 5,000 4,362 7.7% 5,092 13 75,992 5,000 4,727 8.4% 5,205 14 79,031 5,000 5,161 9.2% 5,322 15 82,193 5,000 5,688 10.2% 5,443 16 85,480 5,000 6,346 11.6% 5,570 17 88,900 5,000 7,201 13.5% 5,701 18 92,456 5,000 8,386 16.5% 5,838 19 96,154 5,000 10,235 22.1% 5,980 20 100,000 5,000 14,081 37.6% 6,128

Total 100,000 100,000 100,000

Straight‐Line

Inflation Deferred

Inflation Matched

B25



Witness: David Gunn

Perris Decommissioning Impact Table

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Southern California Edison2021 GRC Depreciation StudyPerris DecommissioningComparison of Proposals

SCE TURN1. Net book value at the time decommissioning 25,680,531 25,680,531

Less:

2. (5,139,162) (5,139,162)

Plus:3. Forecast expenditures on Perris Decommissioning 6,500,000 6,500,000

4=1+2+3 Total capital subject to TURN's recommendation 27,041,370 27,041,370

5. Remaining Life 10.7 6

6=4/5 Expense 2,536,712 4,506,895

7=4-6*50% Rate Base 25,773,013 24,787,922

8. Pre-Tax Return 9.8711% 0%

9=7*8 Pre-Tax Return on Rate Base 2,544,080 -

10=6+9 Total Revenue Requirement 5,080,792 4,506,895

Authorized depreciation between decomm start date (i.e.,retirement date) and 1/1/2021 (i.e., start of GRC cycle)

B27



Witness: David Gunn

STANDARD PRACTICE U-4

B28

Workpaper – Southern California Edison / 2021 General Rate Case

Exhibit No. SCE-07 Vol.03 Ch I-VI Bk A Witness: D. Gunn

a. Unit accounting (sometimes called item accounting) requires a specific record, usually a card, for each individual item of property. A service life .ajl.d s)llvage estimate are applied and an individual accrual for the m,iit is_ determined. The accruals are accumulated ~ach year on the unit record and reappraisals using: the remaining life principle may· be made. If the unit is retired ahead of its expectancy, the defi-ciency in accruals is charged to depreciation expense that year. If the unit outlives its expectancy, the accruals are stopped when the accuml}lations equal the full original cost installed Jess estimated net sal-vage, and no further accruals are made for that unit.

b. In group accounting all units having like mortality characteristics or all units of an account are con-sidered together. Accruals for the group· are based on composite or weighted average values of salvage and service life expectancy. The resulting values are applied to the surviving plant balances each year or each accounting period. A deficiency due to early retirement of a particular unit is made up through greater accruals on a unit which outlives the average. As discussed in Chapter 8, periodic reappraisals of the life expectap.cy and salvage. estimates are required with group accounting. Because of greater simplicity in maintaining records, the group basis is more feasible for most classes 0£ utility property where large numbers of units are involved. It is the more generally used base among electric, gas, tele-phone and water utilities.

Subaccounts af Plant, Classes of Property and Age Groups 7. To facilitate service life estimates in group accounting or to distinguish between certain recognized parts

of a large account, subsidiary data showing subdivisions of an account are often maintained. These include the following :

10

a. Subaccounts are generally used to separate geographic portions, or where an account is large, to separate certain classes of prdperty. For example, a telephone utility may separate Ac. 264, V chicle and Other Work Equipment, into Ac. 264-1, Vehicles, and Ac. 264-2, Work Equipment. Where subaccounts have been established they are usually carried separately on the company's books and are thus treated as separate acconnts in computing depreciation expenses and in recording reserves.

b. Classes of property are portions of an account having different physical or mortality characteristics. For example, a water utility may maintain data to show the portion under Ac. 343 Transmission and Distribution Mains, consisting of asbestos-cement mains, cast-iron mains and steel mains. To the ;separate classes of property, different service life and salvage estimates may be applied and a composite value for the account may then be derived as discussed in Chapter 5. Separation by classes of property also facili-tates determination of average unit costs. The classes of property considered separately are often varied from year to year. Extensive use of classes of property within accounts tends to nulli£y the advan-tages of group accounting. The presence of distinct mortality characteristics and the dollar values of plant are criteria which should be considered in deciding whether to maintain separate data for particular classes of property. As a general guide, accounts of less than $25,000 of plant for Class B and C utilities and accounts of less than $100,000 of plant for Class A utilities, need rarely be subdivided by classes of property merely for group depreciation calculations. Above these amounts the presence of distinct mor-tality characteristics or other factors should govern, where separation into classes of property is con-templated.

c. Age groups (also called generations or vintages) represent the survivors of all units of an account or a class of property installed during the same year or span of years. Maintenance of age group or age distribution data permits more accurate determination of service lives and aids in applying unit retire-ment costs. For most types of mortality studies age group data are essential. Where large growth in an account has occurred and an initial subdivision is proposed, subdivision by age groups is usually preferred over subdivision by classes of property. Class A utilities may find both subdivisions desirable for major accounts.

128

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Documents

2021 General Rate Case Rebuttal Testimony › PublishedDocs › SupDoc › A...11 Ninety percent of SCE’s proposal is designed to remedy the pace of under-collection for T&D net