SCE’S Rebuttal to TURN’s Testimony · 2 1 II. 2 RESPONSE TO TURN TESTIMONY 3 A. Response To Testimony Submitted By William Marcus 4 1. Summary Of Mr. Marcus’s Recommendations

Application No.: I.12-10-013 Exhibit No.: SCE-8 Witnesses: Colin Cushnie

Rick Fisher Paul Hunt Jose Perez Russell Worden

(U 338-E)

SCE’S Rebuttal to TURN’s Testimony

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaApril 2013


Table Of Contents

Section Page Witness

-i-

I. INTRODUCTION .............................................................................................1 R. Worden

II. RESPONSE TO TURN TESTIMONY .............................................................2

A. Response To Testimony Submitted By William Marcus ......................2

1. Summary Of Mr. Marcus’s Recommendations .........................2 R. Worden

2. The Commission Should Reject TURN’S Recommendations Regarding Cash Working Capital ........................................................................................2 R. Fisher

3. The Commission Should Reject TURN’S Recommendations Regarding Other Costs That Require Special Commentary ....................................................4

a) Fuel Inventory ................................................................4 J. Perez

(1) Correction To Inventory Figures Provided To TURN ............................................4

(2) SCE’s Purchase Of Fuel Inventory In 2012....................................................................5

b) M&S ...............................................................................5 R. Fisher

4. The Commission Should Reject TURN’S Recommendations Regarding Removing Specific Costs From Rates .......................................................................6 R. Worden

a) The Commission Should Not Disallow “Replacement Power Costs” ..........................................6

b) The Commission Should Not Remove SONGS Base Rates ........................................................7

5. The Commission Should Reject TURN’S Recommendations Regarding Seismic Studies ..........................8 J. Perez

6. AFUDC/CWIP ...........................................................................9 P. Hunt

a) Continued Accrual Of AFUDC Is Reasonable From Policy And Ratemaking Perspectives..................................................................10


Table Of Contents (Continued)

Section Page Witness

ii

b) Accounting Standards Do Not Prohibit Continued Accrual Of AFUDC ...................................10

c) Precedent Does Not Preclude Continued Accrual of AFUDC ......................................................11

d) Mr. Marcus’s Comments Regarding Retroactive Ratemaking Are A Red Herring ...............12

B. Response To Testimony Submitted By Kevin Woodruff ....................12

1. Summary Of Mr. Woodruff’s Recommendations ...................12 C. Cushnie

2. The Commission Should Reject TURN’s Recommendations That Would Add Foregone Energy Sales Net Revenue And “Consequential Costs” To SCE’s Computation Of Replacement Power Costs .............................................................................13

3. The Commission Should Accept TURN’s And SCE’s Proposals To Account For Planned Refueling And Maintenance Outages In Calculating Estimated Replacement Costs ...................................................................17

4. The Commission Should Reject TURN’s Recommendation That Would Change SCE’s Computation Of Replacement Power Costs ............................19

5. The Commission Should Disregard TURN’s Assertion That SCE’s Computation Of Replacement Power Costs Has A Downward Bias .......................................20

6. Summary Of SCE’s Estimate Of 2012 Replacement Costs And Foregone Energy Sales Net Revenues Recorded In Its OMA...............................................................22

III. CONCLUSION ................................................................................................24 R. Worden

Witness Qualifications


List Of Tables

Table Page

-iii-

Table II-1 Miscellaneous 2012 Market-Related Charges Associated with the SONGS

Outages ................................................................................................................................................16

Table II-2 Estimated Replacement Energy Costs and Foregone Energy Sales Net

Revenue During Scheduled Outages ...................................................................................................18

Table II-3 Estimated Replacement Energy Costs and Foregone Energy Sales Net

Revenue Associated with 2012 SONGs Outages ................................................................................23

1

I. 1

INTRODUCTION 2

This rebuttal testimony responds to testimony sponsored by William Marcus and Kevin 3

Woodruff on behalf of The Utility Reform Network (TURN) in connection with California Public 4

Utilities Commission (Commission) Investigation (I.) 12-10-013 regarding the extended outages at 5

San Onofre Nuclear Generating Station (SONGS). The TURN testimony sponsored by Mr. Marcus 6

proposes adjustments to the SONGS costs through 2012 reported by Southern California Edison 7

(SCE), and recommends that certain costs be removed from rates. The TURN testimony sponsored 8

by Mr. Woodruff addresses the costs SCE has incurred to acquire market energy, capacity, and 9

related products and services needed by SCE to serve load associated with the SONGS outages, and 10

recommends a methodology for calculating these costs. As explained below, the Commission 11

should not adopt TURN’s proposed cost adjustments, as these adjustments are not warranted. In 12

addition, the Commission should not adopt TURN’s ratemaking proposals. 13

This testimony includes rebuttal of testimony that SCE has moved to defer. As of this date, 14

no ruling has been received on SCE’s motion. To the extent SCE’s motion is granted, the 15

corresponding portions of this rebuttal testimony would not be introduced. In serving rebuttal 16

testimony, SCE does not waive its position as set forth in its motion that certain portions of TURN’s 17

testimony are outside the scope of Phase 1.18

2

II. 1

RESPONSE TO TURN TESTIMONY 2

A. Response To Testimony Submitted By William Marcus 3

1. Summary Of Mr. Marcus’s Recommendations 4

In Mr. Marcus’s testimony, TURN identifies cash working capital as a cost category that 5

SCE has not reported or tracked in SCE’s SONGS Memorandum Account (SONGSMA). TURN also 6

identifies nuclear-fuel-related and material & supply (M&S) costs as cost categories that require special 7

commentary and ratemaking treatment. In addition, TURN proposes ratemaking principles for the 8

Commission to follow with respect to: (1) removing certain specific costs from rates; (2) allowing 9

certain costs without refund (i.e., certain safety-related costs and nuclear-insurance-related costs); (3) 10

keeping other costs subject to refund (i.e., certain Unit 2 costs); and (4) recommending other various 11

accounting adjustments to SONGS expenditures not yet included in rates. 12

SCE responds to these issues below. 13

2. The Commission Should Reject TURN’S Recommendations Regarding Cash 14

Working Capital 15

TURN witness Marcus proposes that “the Commission should require Edison to calculate 16

cash working capital for SONGS as a whole.”1 The Commission should reject this recommendation. 17

Working cash represents the capital supplied by shareholders to meet day-to-day utility 18

operational requirements by bridging the gap between the time expenditures are required for services 19

and the time revenues are collected for those services. Working cash is included in rate base to 20

recognize the capital cost incurred to fund this operational requirement. 21

SCE determines the working cash requirement using the lead lag approach, as set forth in 22

the Commission’s Standard Practice U-16. The lead lag approach is a method used to determine the 23

amount of funds required to pay operating expenses in advance of receiving customer revenues. It 24

requires a comprehensive analysis of transactions to determine the net lag days, which is based on: (1) 25

the time lag between the rendering of utility services and the receipt of the associated revenues for those 26

services (Revenue Lag); and (2) the time lag between the recording of the utility costs and payment of 27

those costs (Expense Lag). 28

1 The Utility Reform Network Testimony Sponsored by William Marcus (TURN (Marcus)), p. 6.

3

To the extent that SCE must make payments for costs prior to receiving revenues from 1

customers, SCE must use capital funds to pay for the costs during that period of time. Thus, working 2

cash is determined by deriving the average days of working cash requirement and applying that to the 3

average daily expense. While multiplication of average days lag and daily expense is a simple 4

calculation, the derivation of the number of the days is the result of significant analysis. In particular, 5

Expense Lag is based on the weighted average time lag between recording and payment of numerous 6

expense items, including (but not limited to) purchased power, labor, goods, services, material 7

issuances, insurance provisions, injuries and damages, funded pension provisions, benefits and unfunded 8

pension provisions, franchise requirements, and taxes. These individual components may also contain 9

numerous subcomponents. 10

In SCE’s 2012 GRC decision, the Commission authorized $221,150,000 for working 11

cash.2 This represents approximately 1.47% of SCE’s authorized rate base of $15,072,220,000.3 This 12

authorized working cash amount is based on a total company perspective. It was the result of a rigorous 13

study that took many months to produce. Most of SCE’s data was collected and analyzed at an 14

aggregate company level, and in some cases data is simply not available by operating unit, or generating 15

station, in the case of SONGS. 16

It would not be accurate or reliable to apply the total-company cash working capital to 17

SONGS, as the total-company Expense Lag does not necessarily reflect the Expense Lag for expenses 18

associated with SONGS. As SCE stated in its response to TURN’s data request for computation of 19

“cash working capital associated with the Edison share of SONGS”: 20

SCE objects to this data request as being burdensome because it would require SCE 21 to perform a new study. In addition, SCE’s accounting systems do not permit 22 separation of all necessary data to conduct a “SONGS-only” cash working capital 23 study, which would cast doubt on the accuracy of any new study.”4 24

25

Additionally, the Expense Lag for replacement power costs may vary and would require a 26

separate study. Mr. Marcus agrees, noting that a “specific analysis of SONGS needs to be done because 27

2 D. 12-11-051, 2012 WL 6641483 (Nov. 29, 2012), Appendix C, p. C-21, line 13.

3 Id., line 24.

4 TURN (Marcus), Attachment B (emphasis added).

4

its fraction of costs . . . are different than for the system as a whole.”5 A proper cash working capital 1

study also would have to be conducted on a month-by-month basis, which is not practical or appropriate 2

given the extensive amount of data that is required to generate the inputs, for either a SONGS-only 3

amount or total company. 4

Given the relatively modest impact of cash working capital on SCE’s total company 5

revenue requirement, the burden and expense of developing a SONGS-specific cash working capital 6

estimate (which in any event would not be accurate due to data limitations) is not justified. 7

3. The Commission Should Reject TURN’S Recommendations Regarding Other Costs 8

That Require Special Commentary 9

Mr. Marcus makes a number of observations and recommendations regarding SONGS 10

fuel inventory and M&S costs. The Commission should not adopt these recommendations for the 11

reasons explained below. 12

a) Fuel Inventory 13

(1) Correction To Inventory Figures Provided To TURN 14

Mr. Marcus cites SCE’s response to Data Request TURN-SCE-5, 15

Question No. 4, to list the amount of SONGS pre-core and in-core fuel inventory.6 Mr. Marcus notes 16

that SCE transferred $121 million to in-core inventory for Unit 2 in June 2012, but that there was no 17

corresponding reduction in pre-core inventory, leading Mr. Marcus to question SCE’s treatment of the 18

SONGS fuel inventory and suggest that the return on that $121 million may need to be removed from 19

rate base.7 20

The discrepancy noted by Mr. Marcus is the result of an error contained in 21

SCE’s data request response, which inadvertently provided incorrect pre-core inventories for Unit 2. 22

SCE has provided a corrected response to TURN. The corrected response clarifies that SCE inserted 23

fuel into Unit 2 as part of the refueling outage for Unit 2, which SCE implemented in January/February 24

2012. The corrected figures provided by SCE now reflect the accounting entries made in June 2012 25

where SCE transferred the $121 million to in-core inventory, with a corresponding reduction in the pre-26

5 Id. at 2.

6 Id. at 3.

7 Id.

5

core inventory. Therefore, there is no discrepancy with SCE’s treatment of SONGS fuel inventory, and 1

no return on the fuel inventory should be removed from rate base. 2

(2) SCE’s Purchase Of Fuel Inventory In 2012 3

Mr. Marcus also notes that the total SONGS 2 & 3 pre-core fuel inventory 4

was $304 million as of October, 2012. Mr. Marcus observes that SCE added approximately $139 5

million of pre-core inventory during 2012 when neither SONGS unit was producing electricity. Mr. 6

Marcus does not contend that SCE’s purchase of fuel inventory for SONGS under its various fuel 7

contracts was imprudent. 8

SCE identified in Appendix 1, Tab 14 (for Exhibits SCE-2 and SCE-3) the 9

various nuclear fuel contracts open during 2011 and 2012. As SCE explained in Exhibit SCE-2, these 10

long-term contracts are necessary for SCE to procure and schedule materials in connection with SCE’s 11

nuclear fuel supply management for SONGS, including acquiring various materials and services: (1) 12

natural uranium concentrates (U3O8); (2) conversion to uranium hexafluoride (UF6); (3) enrichment 13

services; and (4) design and fabrication of fuel assemblies. SCE’s nuclear fuel contracts and expenses 14

for SONGS are traditionally reviewed annually in SCE’s Energy Resource Recovery Account (ERRA) 15

review proceeding. The contracts include a mix of fixed and requirements-based contracts. SCE was 16

contractually obligated to purchase in 2012 approximately $139 million of fuel under certain contracts. 17

Because these contractual commitments were made before the outages commenced, and could not be 18

avoided, SCE’s purchase of this inventory was reasonable. 19

In addition, because SONGS nuclear fuel requirements depend on future 20

operational considerations that are uncertain, including when the units will return to service, the power 21

level at which the units are operated, and the length and frequency of planned outages, it is premature to 22

determine any estimated nuclear fuel costs/savings related to the extended outages. 23

b) M&S 24

Mr. Marcus proposes that “[t]he Commission should allow only 50% of CPUC-25

authorized Materials and Supplies inventory in rate base.”8 While Mr. Marcus does not explain the basis 26

for this recommendation, he appears to assume that removing the capital costs of one of the two units 27

from rate base means that 50% of materials and supplies (M&S) should also be removed.9 TURN’s 28

8 Id. at 6.

9 Id. at 5.

6

proposal, however, is based on the erroneous assumption that M&S is specific to each unit. In fact, 1

SCE’s M&S inventory is fungible between units and also supports the common plant. Because TURN 2

agrees that common plant should remain in rate base, it would be inappropriate to remove M&S 3

inventory from rate base even if the Commission were to agree with TURN’s recommendation to 4

remove Unit 3 from rate base. In addition, as explained below, the Commission should not accept 5

TURN’s recommendation to remove Unit 3 from rate base. 6

4. The Commission Should Reject TURN’S Recommendations Regarding Removing 7

Specific Costs From Rates 8

TURN’s witnesses recommend that the Commission either (1) disallow “replacement 9

power costs”10 incurred in 2012, or (2) remove SONGS base rate costs from rates.11 Both TURN 10

witnesses recommend that the Commission disallow replacement power costs from the commencement 11

of the outages up to November 1, 2012.12 The TURN witnesses disagree, however, about the 12

ratemaking for the remainder of 2012. Mr. Marcus argues that the Commission should remove Unit 3 13

from base rates, but remove replacement power costs for Unit 2, for the period November 1 through 14

December 31, 2012.13 TURN witness Mr. Woodruff, by contrast, recommends that the Commission 15

remove both SONGS units from rate base as of November 1, 2012 and permit full recovery of 16

replacement power costs from that date forward.14 The Commission should reject all of TURN’s broad 17

ratemaking recommendations. 18

a) The Commission Should Not Disallow “Replacement Power Costs” 19

TURN’s witnesses do not make clear whether they are recommending interim or 20

permanent ratemaking. To the extent TURN’s witnesses recommend that the Commission permanently 21

disallow recovery of either replacement power or SONGS base rates, the Commission should reject that 22

recommendation. The Commission must permit a utility to recover its costs of service – including both 23

the costs of purchasing power and the costs of a plant that is in the midst of an outage – absent a finding 24

that the outage is due to the utility’s imprudence. Consistent with this principle, the Commission 25

10 SCE reserves the right to argue that “replacement power costs” are not an appropriate remedy for utility imprudence (if

any) for forced outages of utility-owned generation resources.

11 Id. at 4; TURN Testimony Sponsored by Kevin Woodruff (TURN (Woodruff)), p. 2.

12 TURN (Marcus), p. 4; TURN (Woodruff), p. 2.

13 TURN (Marcus), p. 5.

14 TURN (Woodruff), pp. 2-3.

7

permits utilities to recover both base rates associated with utility-owned generation, as well as the cost to 1

purchase additional power in the market, when an outage does not result from utility imprudence. The 2

Commission has made no finding regarding SCE’s prudence in this case. It will examine that issue in 3

Phase 3. Accordingly, there is no basis for permanently disallowing recovery of either costs associated 4

with market purchases or SONGS base rates at this time. 5

Alternatively, TURN’s witnesses may be recommending that the Commission 6

remove replacement power costs or SONGS base rates recorded in 2012 on an interim basis, pending 7

review in Phase 3 of SCE’s prudence. The Commission should reject this recommendation as well. 8

SCE has already recovered its 2012 market energy and capacity costs in rates, including those costs 9

associated with the SONGS outages, through the operation of the Energy Resource Recovery Account 10

(“ERRA”).15 By stating that SCE’s “replacement power” costs should be disallowed, TURN’s 11

witnesses apparently recommend that the Commission order SCE to refund those amounts to customers. 12

However, if the Commission finds in Phase 3 that SCE’s actions were prudent, any refund would be 13

reversed. Such rate swings would create rate shock, which is contrary to the public interest.16 14

Moreover, an interim refund would contravene AB 57, which requires the Commission to ensure that 15

power procurement costs are promptly recovered and that ERRA balances do not exceed 5% of recorded 16

generation revenues.17 Unless and until the Commission makes a finding that the SONGS outages are 17

due, in whole or in significant part, to SCE’s imprudence, it must permit SCE to recover and retain 18

revenue to cover its procurement costs. Finally, there is no need to order a refund at this time, as the 19

Commission has authority to order a refund at a later date if necessary. 20

b) The Commission Should Not Remove SONGS Base Rates 21

For similar reasons, SONGS base rates for November and December 2012 should 22

not be adjusted pending Phase 3, as Mr. Marcus recommends with respect to Unit 3 and Mr. Woodruff 23

recommends with respect to both Units 2 and 3. Because SONGS base rates are subject to refund as of 24

15 In A. 11-08-001, SCE estimated its costs for 2012 purchased power and proposed 2012 ERRA rates based in part on that

forecast. 2012 WL 960073 (Mar. 8, 2012). D. 12-07-007 accepted those forecast rates, and accordingly, SCE implemented its 2012 ERRA rates on August 1, 2012. Because SCE’s actual market costs in 2012 were lower than the forecast rates, the difference will be trued up along with all other ERRA-related costs in 2012 and returned to customers in 2013.

16 D. 12-11-051, 2012 WL 6641483, at *15; see also SCE-1, p. 4.

8

November 1, 2012, the Commission can implement a rate adjustment relating to base rates if and when 1

it finds that the outages are due, in whole or in part, to SCE’s imprudence. Adjusting base rates at this 2

time would risk creating rate shock,18 would have adverse financial effects that would ultimately harm 3

ratepayers,19 and would inappropriately prejudge Phase 2, which will consider whether and when to 4

remove SONGS from rates. 5

5. The Commission Should Reject TURN’S Recommendations Regarding Seismic 6

Studies 7

Mr. Marcus states: “TURN recommends that the Commission suspend SCE’s authority to 8

collect any future revenues for seismic studies related to the relicensing of the plant and eliminate any 9

seismic O&M expenditures already incurred in Edison balancing accounts in current rates.”20 Mr. 10

Marcus further states: “Allowing seismic studies for relicensing places the cart before the horse. It is 11

unreasonable to spend tens of millions of dollars to relicense the plant before it is known whether the 12

plant can even be restarted or whether it will be economic to run.”21 TURN misunderstands the nature 13

of the seismic studies, and its recommendation is flawed. 14

The seismic studies are not being performed in connection with SONGS license renewal. 15

Rather, they are being carried out to respond to existing regulatory requirements, as stated in the 16

Commission’s decision authorizing the seismic studies: 17

Continued from the previous page 17 Public Utilities Code § 454.5(d)(3). See also D. 02-10-062, p. 52 (“The purpose of balancing accounts and timely

recovery of procurement costs are intertwined with AB 57.”); D. 04-01-048, pp. 8-9 (discussing mitigating factors to reduce undercollections).

18 SCE-1, p. 4.

19 Id. at 15-18.

20 TURN (Marcus), p. 9 (emphasis added).

21 Id. (emphasis added).

9

The SONGS 2 & 3 seismic activities attempt to respond to state regulatory objectives 1 regarding assessing SONGS 2 & 3 seismic conditions, including the CEC’s AB 1632 2 Report recommendation and direction from the Commission. The new seismic 3 research projects should be designed to also provide sufficient information for SCE to 4 respond to the NRC’s requirements for seismic hazard and risk analysis contained in 5 the March 12, 2012 NRC Letter to All Power Reactor Licensees et al., Request for 6 Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) 7 Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review 8 of Insights from the Fukushima Dai-Ichi Accident.22 9

SCE should proceed with the SONGS 2 & 3 seismic activities described in A.11-04-10 006 [(the application requesting seismic study funding)], as the SONGS 2 & 3 11 seismic activities are in the public interest and attempt to respond to state regulatory 12 objectives regarding assessing SONGS 2 & 3 seismic conditions, including the CEC’s 13 AB 1632 Report recommendations and directions from the Commission.23 14

The Commission issued this decision on May 15, 2012, three and a half months after the SONGS 15

outages began. The outages do not change the Commission’s conclusion that the seismic studies should 16

continue, as they respond to state and federal regulatory objectives and are in the public interest. 17

In accordance with the decision approving the studies, SCE has provided the 18

Commission’s Energy Division Director with its plans for seismic research projects, periodic status 19

reports, and findings and/or results24 associated with the projects, so that these materials can be provided 20

to the Independent Peer Review Group (IPRG) established by the Commission for the seismic research 21

projects.25 22

6. AFUDC/CWIP 23

Mr. Marcus recommends that the Commission order SCE to stop accruing Allowance for 24

Funds Used During Construction (AFUDC) for SONGS capital projects that SCE has suspended in light 25

of the current outages.26 Mr. Marcus’s recommendation is based on faulty analysis and, if adopted, 26

would create bad policy. The Commission should reject this recommendation. 27

22 D. 12-05-004, 2012 WL 1883304, at *8, Finding of Fact 2 (May 10, 2012).

23 Id. at *8, Conclusion of Law 2.

24 This information is available on the Commission’s website at http://www.cpuc.ca.gov/PUC/energy/nuclear.htm.

25 In accordance with Ordering Paragraphs 8 and 9 of D. 12-05-004, at *9.

26 TURN (Marcus), p. 10.

10

a) Continued Accrual Of AFUDC Is Reasonable From Policy And Ratemaking 1

Perspectives 2

AFUDC represents the cost of financing capital projects before they enter service. 3

AFUDC is accumulated while the projects are ongoing and added to the capital cost of the projects when 4

they are added to rate base. 5

Mr. Marcus’s recommendation that SCE stop accruing AFUDC would improperly 6

prevent SCE from recovering the cost of financing SONGS capital projects, regardless of future events. 7

For example, if Unit 2 returns to service, capital projects currently in Construction Work in Progress 8

(CWIP) that are associated with Unit 2 or common plant may enter service and be added to rate base. In 9

that event, SCE should likewise recover the cost of financing those projects. In any case, SCE’s 10

continued accrual of AFUDC does not prevent the Commission from taking appropriate ratemaking 11

action in the future, when SCE seeks to recover the cost of the capital projects that are currently in 12

CWIP. There is no need to prejudge the outcome of this ratemaking by prohibiting SCE from recording 13

AFUDC on its books. As Mr. Marcus recognizes,27 the accrual of AFUDC does not have a current 14

impact on rates. 15

b) Accounting Standards Do Not Prohibit Continued Accrual Of AFUDC 16

Mr. Marcus erroneously asserts that accounting standards prohibit SCE from 17

recording AFUDC, relying on Statement of Accounting Standards (SFAS) 34.28 First, the 18

Commission’s ratemaking policy is not dictated by financial accounting standards. For the reasons 19

noted, it is fair and appropriate to permit SCE to record AFUDC, subject to a future ratemaking 20

determination by the Commission. Second, SFAS-71, which modifies SFAS 34, governs AFUDC for 21

public utilities. Where, as in California, the regulatory agency requires the cost of financing 22

construction to be capitalized, “the amounts capitalized for rate-making purposes as part of the cost of 23

acquiring the assets shall be capitalized for financial reporting purposes instead of the amount of interest 24

that would be capitalized in accordance with FASB Statement No. 34.”29 25

27 Id. at 11.

28 Id. at 10.

29 SFAS 71, ¶ 15, http://www.fasb.org/pdf/fas71.pdf.

11

c) Precedent Does Not Preclude Continued Accrual of AFUDC 1

Mr. Marcus cites no California precedent that would support his recommendation 2

that SCE be precluded from accruing AFUDC on CWIP. Instead, Mr. Marcus references a FERC Order 3

and a rule of the Mississippi Public Service Commission. Neither precedent supports Mr. Marcus’s 4

recommendation. 5

The cited FERC order reads as follows: “[I]f a natural gas pipeline suspends 6

substantially all activities related to the construction of pipeline facilities, AFUDC accruals must cease 7

unless the company can justify the interruption as being reasonable under the circumstances.”30 The 8

order is not analogous to the SONGS situation for two reasons. First, SCE has not suspended 9

“substantially all activities related to the construction” of SONGS. Instead, SONGS already exists, and 10

SCE continues to work toward a restart of SONGS. As Mr. Marcus notes, the FERC precedent is 11

similar to its rule on abandoned projects.31 Neither SONGS nor the amounts in CWIP, however, 12

constitute abandoned plant. Hence, FERC’s guidance with respect to abandoned projects is not relevant 13

in this situation. Second, FERC’s order permits AFUDC accrual if the suspension is reasonable under 14

the circumstances. Here, it was reasonable for SCE to suspend certain SONGS capital projects given the 15

current outages and SCE’s efforts to work toward restart. Further, for the projects that have been 16

suspended until the steam generator problems are resolved, SCE still incurs financing costs until they are 17

completed and enter rate base. For the reasons explained above, it is reasonable to continue to accrue 18

AFUDC and the FERC order does not indicate otherwise. 19

The Mississippi Public Service Commission Public Utilities Rules of Practice and 20

Procedure also fail to support Mr. Marcus’s claim that some state commissions forbid AFUDC accrual 21

during periods of construction suspension.32 The Mississippi rule reads in its entirety as follows: 22

30 No. CP09-36-002 et al., 130 FERC ¶ 61,193, 61854, at ¶ 38.

31 TURN (Marcus), p. 11 & n.14.

32 Id. at 11& n.15.

12

The Commission may, by incorporating a provision in its order granting a 1 Facilities Certificate, suspend Commission authority for the construction or 2 acquisition of a facility, plant or other capital item, whether previously 3 certificated or not, upon failure by a utility to adhere to the provisions of this 4 rule or an order of the Commission, or for its failure to timely provide the 5 Commission, Commission staff or the Staff with any reasonable information 6 requested concerning the cost, purpose or construction of the facility, plant or 7 other capital item. Except as specifically allowed by order of the 8 Commission, the related capital expenditures made during the period of 9 suspension on the suspended construction or acquisition shall not be allowed 10 in rate base during the period of such suspension nor shall Allowance for 11 Funds Used During Construction (AFUDC) accrue on any such funds during 12 any period of suspension.33 13

The rule is clearly predicated on the utility’s failure to adhere to the rules or an 14

order of the Commission and only applies in such a situation. This source provides no support for Mr. 15

Marcus’s recommendation. 16

d) Mr. Marcus’s Comments Regarding Retroactive Ratemaking Are A Red Herring 17

Mr. Marcus’s discussion of retroactive ratemaking has the issue exactly 18

backward. If AFUDC accrual is suspended, the doctrine of retroactive ratemaking may prevent the 19

utility from recovering the financing costs it bears during the suspension period. In addition, as Mr. 20

Marcus notes, settlement agreements are not precedent according to the Commission’s rules, so his 21

example from PG&E’s 2011 GRC is not relevant. 22

In summary, Mr. Marcus’s recommendations on this issue have no foundation and 23

the Commission should reject them. 24

B. Response To Testimony Submitted By Kevin Woodruff 25

1. Summary Of Mr. Woodruff’s Recommendations 26

TURN witness Kevin Woodruff’s Phase 1, March 29, 2013, testimony addresses the 27

estimate of 2012 market energy and capacity-related costs of Southern California Edison Company 28

(SCE) and San Diego Gas & Electric Company (SDG&E) associated with the extended outages that 29

occurred beginning in early 2012 at Units 2 and 3 of the San Onofre Nuclear Generating Station 30

(SONGS).34 Mr. Woodruff’s testimony summarizes each utility’s estimate of replacement power costs 31

incurred in 2012, and offers both specific and general observations on the methodologies for such 32

estimates. In some instances, Mr. Woodruff proposes specific recommendations to adjust SCE’s 33

33 Miss. Pub. Serv. Comm’n and Pub. Util. Staff Rules of Practice and Proc., Rule 104 at 44 (2012) (emphasis added).

34 For ease of reference, SCE sometimes refers to these costs as “replacement power” costs in this rebuttal testimony.

13

estimate of replacement costs. My testimony below addresses Mr. Woodruff’s specific 1

recommendations as they relate to SCE.35 To the extent that Mr. Woodruff only offered general 2

observations, SCE reserves the right to respond if and when TURN makes specific recommendations. 3

2. The Commission Should Reject TURN’s Recommendations That Would Add 4

Foregone Energy Sales Net Revenue And “Consequential Costs” To SCE’s 5

Computation Of Replacement Power Costs 6

TURN witness Woodruff refers to the estimate of market-related costs of SCE and 7

SDG&E associated with the SONGS outages as “consequential power supply costs” or “consequential 8

costs.”36 SCE contests any inference that any estimate of replacement power costs can or should include 9

consequential costs. Only estimates of market costs that represent amounts equivalent to the lost 10

SONGS generation capacity and energy needed to meet bundled customer demand should be identified 11

and considered as “replacement costs.” In this respect, the Commission has required SCE to separately 12

report replacement power costs and foregone energy sales net revenue in SCE’s Outage Memorandum 13

Account (OMA). TURN’s testimony, however, recommends that SCE’s estimated foregone energy 14

sales net revenue should be treated the same as estimates of SCE’s replacement power costs.37 TURN’s 15

recommendation must be rejected because the opportunity cost of foregone energy sales (which occurs 16

during hours in which SCE’s net open position is “long”) is not related to the costs associated with the 17

required market transactions to meet SCE’s bundled customer demand. SCE has estimated the foregone 18

energy sales revenue associated with the SONGS outages and reported its estimate of these opportunity 19

costs in a separate OMA subaccount pursuant to Commission direction. These opportunity costs should 20

not be considered replacement power costs because there is no replacement of SONGS energy required 21

to meet SCE’s bundled customer demand during hours in which SCE’s net open position is “long.” 22

35 Failure to address each of Mr. Woodruff’s specific recommendations should not be inferred as support for such

recommendations. Mr. Woodruff’s March 29, 2013, testimony was prepared prior to SCE’s April 2, 2013, “Energy Resource Recovery Account (ERRA) Review of Operations, 2012” testimony. SCE’s ERRA testimony at SCE-3 (which has been served on the service list in this proceeding) provides further explanation and detail of SCE’s estimated 2012 replacement power cost calculations, and represents SCE’s proposed estimate of its 2012 replacement power costs associated with the SONGS outages for purposes of updating its SONGS Outage Memorandum Account. As SCE explained in its 2012 ERRA testimony, “SCE reserves the right to present an alternative cost impact methodology in a subsequent phase of I.12-10-013 if such a calculation is necessary.” Southern California Edison Company’s Energy Resource Recovery Account (ERRA) Review of Operations, 2012, April 2, 2013, Chapter XVII (“SCE’s 2012 ERRA Testimony”), p. 2.

36 TURN (Woodruff), p. 1, lines 19-22.

37 Id. at 17-18.

14

Similarly, TURN’s suggestion that estimates of replacement power costs could or should 1

include estimates of consequential costs associated with the SONGS outages must be rejected as 2

inappropriately expanding what should be a straightforward definition of replacement power costs.38 3

For example, Mr. Woodruff concludes that all LSEs in SP-15 faced higher energy prices in 2012 as a 4

result of the SONGS outages, and that LSEs operating in NP-15 likely incurred higher costs for meeting 5

their customers’ loads. Mr. Woodruff also stated that “estimates of such damages could be made,” but 6

he is not making such a proposal at this time.39 Although TURN did not offer a specific proposal to 7

consider estimates of consequential damages, there is no reason to even consider such estimates in 8

SCE’s estimate of replacement power costs because such estimates should be limited to estimates of the 9

market costs to replace lost SONGS generation capacity and energy to serve bundled customer 10

requirements. Under no circumstance should an estimate of outage-related market costs include an 11

estimate of the costs incurred by other market participants associated with the outage. Indeed, SCE and 12

its customers are not compensated by other market participants for higher energy prices when their 13

generation resources are not available due to forced plant outages. Nor are SCE and its customers 14

compensated by other market participants when SCE’s generation resources are available and an 15

inference could be drawn that energy market prices decrease as a result of their availability. 16

Similarly, TURN witness Woodruff states that costs SCE recorded into its OMA for the 17

Huntington Beach Subaccount and Demand Response Subaccount should be considered as “other 18

consequential costs.”40 The approximate $2.8 million SCE incurred and recorded into the Demand 19

Response OMA subaccount was not incurred to provide cost-effective capacity and energy to meet 20

SCE’s bundled customer requirements (i.e., the costs did not constitute an estimate of the costs of 21

replacement power). Instead, these costs were incurred to enhance the reliability of SCE’s electric 22

system in the western sub-area of the Los Angeles Basin local area. Specifically, the costs were 23

incurred to reduce demand in targeted locations of the western sub-area of the Los Angeles Basin local 24

area to enhance local area reliability during periods of peak demand. These costs are more appropriately 25

categorized as grid reliability costs, because the costs were incurred to enhance the local area reliability 26

38 Estimates of replacement power costs should only include the direct cost associated with serving bundled customer

requirements, up to an amount of capacity and energy equivalent to what the forced generation unit would have provided. SCE has separately estimated and recorded capacity-related and replacement energy costs in its OMA.

39 Id. at 4, line 20- 5, line 2.

40 Id. at 8, lines 5-21.

15

of the Los Angeles Basin. Grid reliability costs are not generation or power procurement costs, and 1

should therefore not be included in any estimate of the market cost of power to serve bundled customer 2

demand. 3

The approximate $16.8 million of Huntington Beach Subaccount costs that TURN 4

witness Woodruff recommends being treated as “consequential costs” are really a summation of the 5

“PIRP Allocation Charges to SONGS,” “Real-Time Imbalance Charges for Day-Ahead Schedule 6

Deviations,” and “On-site Auxiliary Load Costs” charges that I identified in Table XVII-4 of my April 7

2, 2013 ERRA testimony.41 The categorization of these costs as being related to Huntington Beach is 8

incorrect, and SCE will update its OMA accordingly.42 As described further in my testimony below, 9

these costs are associated with the SONGS outages and are directly related to meeting SCE’s bundled 10

customer requirements. As such, they should be considered in the estimate of SCE’s replacement power 11

costs. 12

TURN witness Woodruff also identifies the four “other CAISO charges” that SCE is 13

recording in its OMA and states that these costs should “be considered as consequential power supply 14

costs” because “SCE incurred these costs as a result of the SONGS [o]utages.”43 SCE summarized and 15

provided an explanation of these charges in its 2012 ERRA testimony (the summary is re-provided 16

below as Table II-1 for convenience).44 The “other CAISO charges” identified as “PIRP Allocation 17

Charges to SONGS,” “February 1, 2012 Energy Buy-Back Costs,” and “Auxiliary Load Costs” are the 18

same costs that I described immediately above, which were mislabeled as Huntington Beach Subaccount 19

costs.45 These 2012 CAISO charges can be considered replacement costs because they were incurred as 20

41 SCE’s 2012 ERRA Testimony, Table XVII-4, p. 10.

42 The costs CAISO incurred to return Huntington Beach Units 3 and 4 to service in 2012 that were allocated to SCE in the form of Capacity Procurement Mechanism (CPM) charges are included in SCE’s estimate of its capacity-related costs. SCE has recorded its estimate of its capacity-related costs as a line item in its O&M Expense Subaccount of its OMA. I summarize SCE’s estimate of its 2012 capacity-related costs associated with the SONGS outages in my April 2, 2013 ERRA testimony (see Chapter XVII, pp. 8-9).

43 TURN (Woodruff), p. 9.


45 Table 3 in Mr. Woodruff’s testimony shows $16.845 million of Huntington Beach Subaccount charges. The sum of the “PIRP Allocation Charges to SONGS,” “Real-Time Imbalance Charges for Day-Ahead Schedule Deviations,” and “On-site Auxiliary Load Costs” charges that I identified in Table XVII-4 of my April 2, 2013 ERRA testimony is $16.858 million. The $0.013 million difference is a result of an OMA update to the October 2012 charges that SCE recorded subsequent to TURN’s review of the account entries. Otherwise, all the monthly values for the Huntington Beach Subaccount in TURN Table 3 are the same as the monthly totals for the “other CAISO charges” in TURN Table 4,

(Continued)

16

a result of power charges assessed to SCE to replace generation from SONGS. Specifically, the Real-1

Time Imbalance Energy Charges were incurred to replace the generation from Unit 3 that was not 2

delivered pursuant to SCE’s Day-Ahead IFM schedules for January 31 and February 1, 2012, which 3

were the first two days of the Unit 3 outage. Auxiliary Load Costs were incurred in the form of negative 4

uninstructed deviation charges from the CAISO’s Real-Time imbalance energy market to meet SONGS’ 5

on-site electric demand, which is normally served by its generation output when one or both units are 6

operating. In effect, the negative uninstructed deviation charges are costs incurred to replace energy that 7

SONGS would have otherwise generated to meet its auxiliary load requirements. Finally, the SONGS 8

PIRP Allocation Charges are a CAISO cost allocation that is assessed to net negative uninstructed 9

deviations. To the extent that SCE’s portfolio had a net negative uninstructed deviation and was 10

assessed PIRP charges, SCE used the percentage share that the SONGS negative uninstructed deviations 11

(incurred to serve SONGS’ auxiliary load) represented of SCE’s net total uninstructed deviations to 12

determine the amount of PIRP charges that were associated with SONGS outages. 13

Table II-1 Miscellaneous 2012 Market-Related Charges Associated with the SONGS Outages

TURN’s recommendation to consider (the mislabeled) Huntington Beach Subaccount 14

charges and the three identified “other CAISO charges” cost categories described above as 15

“consequential costs” should be rejected for the reasons provided herein, and because doing so would 16

double count the charges. Instead, the three identified “other CAISO charges” costs should be 17

considered a component of the estimate of SCE’s replacement power costs because they were associated 18

Continued from the previous page demonstrating that the charges are of the same origin and therefore double-counted in TURN’s recommendation to classify the costs as “consequential costs.”

17

with replacement generation that SONGS would have otherwise provided. SCE provides more 1

explanation of these CAISO charge types in its 2012 ERRA testimony, which the Commission has 2

formally consolidated with this proceeding.46 3

In contrast to the other three identified CAISO charges, the Reverse Congestion Costs 4

(also referred to as “Congestion Revenue Rights Charges”) should not be considered in an estimate of 5

the market cost of replacement power because Congestion Revenue Rights (CRRs) are a financial 6

hedge.47 SCE did not acquire its SONGS CRRs because of the extended SONGS outages. Instead, SCE 7

acquired the CRRs in advance of the extended outages to hedge potential congestion costs associated 8

with deliveries from the SONGS units to the load centers. As a result, the approximate $9.6 million of 9

congestion costs associated with SCE’s 2012 SONGS CRRs should not be included in any estimate of 10

the market cost of replacement power. Moreover, it would be inequitable and illogical to selectively 11

consider the cost outcome of a single component of SCE’s portfolio of hedges that existed prior to the 12

SONGS outages, and to include an estimate of such a cost in an estimate of the market cost of 13

replacement power. To the extent that the SONGS outages coincided with higher market prices, the 14

market value of most of SCE’s financial hedge transactions and forward energy purchases increased, 15

and the benefit of those holdings flowed to customers. TURN’s proposal to classify SCE’s SONGS 16

CRRs as replacement costs is unprincipled, because it singles out one element of SCE’s portfolio of 17

hedges. It is unlikely that TURN would have proposed that the cost or revenues of the SONGS CRRs be 18

considered replacement power costs if they had a net positive value. The Commission should reject any 19

proposal to “cherry pick” the net negative value outcomes of hedges and transactions that existed prior 20

to the SONGS outages for inclusion in an estimate of the market cost of replacement power. 21

3. The Commission Should Accept TURN’s And SCE’s Proposals To Account For 22

Planned Refueling And Maintenance Outages In Calculating Estimated 23

Replacement Costs 24

TURN witness Woodruff states that “Replacement Power and Foregone Sales Revenues 25

should also not be assumed to occur during periods when either SONGS unit would have been otherwise 26

46 Id., pp. 2 & 10-11. See ALJ Duda’s April 15, 2013, email ruling served on the SONGS OII and 2012 ERRA service

lists.

47 Id., pp. 10-11.

18

unavailable due to a prescheduled refueling outage.”48 TURN correctly identifies that Unit 2 had a 1

planned refueling and maintenance outage scheduled for January 9, 2012, through March 4, 2012, and 2

that Unit 3 had a planned refueling and maintenance outage scheduled for October 8, 2012, through 3

December 2, 2012. SCE concurs with TURN that replacement power costs and foregone energy sales 4

net revenues should not be calculated during periods when a unit would have otherwise been unavailable 5

due to a planned refueling and maintenance outage. SCE provided such an estimate in its 2012 ERRA 6

testimony, and re-provides this estimate in Table II-2 below.49 7

Table II-2 Estimated Replacement Energy Costs and Foregone Energy Sales

Net Revenue During Scheduled Outages

SCE’s estimate of approximately $49.6 million of planned outage period-related costs 8

differs from TURN’s estimate of approximately $18.5 million.50 Based on SCE’s review of TURN’s 9

$18.5 million estimate summarized in TURN witness Woodruff’s Table 6, SCE believes TURN was not 10

able to reasonably forecast the estimated replacement energy costs and foregone energy sales net 11

revenue associated with the October 8, 2012, through December 2, 2012, planned refueling and 12

maintenance outage for Unit 3 because TURN did not use SCE’s updated analysis for this period. SCE 13

recorded its updated replacement power costs and foregone energy sales net revenue in its OMA on 14

April 1, 2013, after TURN served its March 29, 2013 testimony.51 SCE and TURN have the same $18.0 15

million estimate for the Unit 2 planned outage, but SCE estimates approximately $31.6 million for the 16

48 TURN (Woodruff), pp. 10-13.


50 TURN (Woodruff), p. 13.

51 SCE also provided the updated analysis to TURN in response to TURN Data Request No. 2, Question Nos. 7a and 7b, on February 26, 2013.

19

Unit 3 planned outage compared to TURN’s estimate of approximately $0.5 million. Absent a 1

demonstration that SCE’s calculations are incorrect, the Commission should use SCE’s estimate of 2

approximately $49.6 million (which includes the $31.6 million estimate for Unit 3) to reduce the 3

estimated replacement power costs and foregone energy sales net revenue SCE recorded in its OMA 4

associated with the SONGS outages in 2012. 5

4. The Commission Should Reject TURN’s Recommendation That Would Change 6

SCE’s Computation Of Replacement Power Costs 7

TURN witness Woodruff recommends the Commission require SCE to use SCE’s 8

Default Load Aggregation Point (DLAP) prices to calculate replacement power costs instead of SCE’s 9

proposed SP-15 day-ahead index prices.52 TURN does not offer any rationale for this suggestion, other 10

than that the average SCE DLAP price for most of 2012 was $30.94/MWh compared to the average SP-11

15 day-ahead index price for the same period, which was $30.20/MWh. TURN’s recommendation to 12

use SCE’s DLAP prices as a basis for calculating estimated replacement power costs and foregone 13

energy sales net revenue seems to be based simply on the fact that SCE DLAP prices were, on average, 14

$0.74/MWh higher than SP-15 day-ahead index prices. Selecting a price source because it will yield 15

higher estimated replacement power costs and foregone energy sales net revenue is punitive and 16

arbitrary, and should be rejected. 17

In contrast, SCE has explained that SP-15 day-ahead index prices are more appropriate 18

because “SP-15 day-ahead index prices are commonly used to settle financial transaction for energy 19

transacted for delivery in southern California.”53 Additionally, SCE has explained that SONGS 20

operates in a baseload manner and it is not necessary to utilize the hourly prices that comprise SCE’s 21

DLAP in the CAISO’s Integrated Forward Market (IFM) to estimate replacement costs.54 SCE also 22

explained that “SP-15 is an appropriate pricing point because the SONGS energy that would have 23

otherwise been produced would have generally served SP-15 load,” which includes load outside of 24

SCE’s service territory.55 25


53 SCE’s 2012 ERRA Testimony, p. 3, lines 8-9.

54 Id. at 3, lines 8-9; SCE-2, p. 20, lines 7-12.

55 SCE’s 2012 ERRA Testimony, p. 3, lines 5-6.

20

It also must be noted that SCE generally seeks to reduce its daily net open position in the 1

bilateral day-ahead SP-15 market (which is the basis for SP-15 day-ahead index prices) by purchasing 2

on-peak and off-peak blocks of energy to cover short positions and selling on-peak and off-peak blocks 3

of energy to reduce long positions in its bundled customer portfolio. Because SCE relies on the bilateral 4

day-ahead SP-15 market to reduce its daily net open positions before transacting the balance of its 5

requirements in the CAISO’s IFM, the use of SP-15 day-ahead index prices are most reflective of SCE’s 6

initial opportunity to buy and sell power in the day-ahead timeframe. 7

SCE’s DLAP prices represent the price that SCE pays for energy purchased to serve its 8

bundled load in the CAISO’s IFM. SCE does not receive its DLAP prices for energy sold in the 9

CAISO’s IFM. Instead, SCE receives the applicable generation node price for its energy sales from 10

generation plant, which for the SONGS units is typically less than SCE’s DLAP prices.56 As a result, 11

using SCE’s DLAP prices as a basis for estimating SCE’s foregone energy sales net revenue for the 12

SONGS outages will likely overstate the estimated foregone energy sales net revenue associated with 13

the SONGS outages. On balance, it is reasonable to use SP-15 day-ahead index prices to estimate 14

SCE’s replacement power costs and foregone energy sales net revenues because the SP-15 index prices 15

reflect daily market prices at which buyers and sellers were willing to transact for SP-15 deliveries, and 16

it is the relevant market price point for SCE’s bilateral day-ahead transactions to reduce its daily forecast 17

net open position prior to the operation of the CAISO’s IFM. 18

5. The Commission Should Disregard TURN’s Assertion That SCE’s Computation Of 19

Replacement Power Costs Has A Downward Bias 20

TURN witness Woodruff asserts in several instances that SCE’s methodology to 21

calculate estimated replacement power costs and foregone energy sales net revenue creates a downward 22

bias in the estimate. SCE disagrees with these observations, and has addressed some of these 23

observations above. As discussed in my previous testimony,57 many assumptions have to be made to 24

estimate replacement power costs and foregone energy sales net revenue associated with the SONGS 25

56 TURN witness Woodruff also noted that “prices to serve load tend to be higher than prices received for generation.”

TURN (Woodruff), p.15 n.14. However, TURN’s conclusion that SCE’s use of a single price basis to calculate replacement costs and foregone energy sales net revenue causes a “downward bias” in SCE’s cost estimates is contrary to TURN’s acknowledgement that generation prices tend to be lower than the price to serve load. In fact, TURN’s recommendation to use SCE’s DLAP prices would actually create an upward bias in forecasting SCE’s estimated foregone energy sales net revenue, and should accordingly be rejected.

57 See SCE-2, pp. 18-22; SCE’s 2012 ERRA Testimony.

21

outages. SCE has attempted to present an objective methodology to estimating replacement power costs 1

and foregone energy sales net revenue associated with the SONGS outages for purposes of its OMA 2

reporting and supporting testimony. Increasing the complexity of the calculation methodology and the 3

number of assumptions as to how the market would have responded in the absence of the SONGS 4

outages will not necessarily improve the “accuracy” of SCE’s estimates. It would also introduce 5

numerous “expert” disputes as to what the appropriate counter-factual outcome would have been if 6

SONGS had not experienced its extended outages, or similarly, the impact on SCE’s bundled customer 7

portfolio as a result of the extended SONGS outages. 8

For example, TURN states that “SCE’s use of its actual day-ahead net energy positions 9

‘without SONGS’ to estimate what its day-ahead net energy positions would have been ‘with SONGS’” 10

understates SCE’s estimated replacement power costs and foregone energy sales net revenue associated 11

with the SONGS outages. I do not necessarily agree with TURN’s assertion, because it is not possible 12

to know what SCE’s bundled customer portfolio position would have been had SONGS not experienced 13

its extended outages. Numerous changes to the bundled customer portfolio occurred as a result of the 14

SONGS outages, and market participants’ bid behavior and operations also changed, which creates 15

further uncertainty about what the theoretical “SONGS in” bundled customer net open position would 16

have been. Instead of attempting to identify and quantify each driver of potential change to SCE’s 17

bundled customer open position associated with the SONGS outages, which cannot be assumed to be 18

more accurate than what SCE has already done, SCE simply sought to use objective data for its net open 19

position calculations. In this case, SCE recommended using its net open position that existed prior to its 20

day-ahead bilateral trading activity. TURN witness Woodruff acknowledges that “[f]or practical 21

reasons” he does not think that the Commission needs to change SCE’s assumption on the calculation of 22

its daily net open position.58 Based on the foregoing, the Commission should not consider further 23

revisions to SCE’s estimate of its 2012 replacement power costs and foregone energy sales net revenue 24

associated with the SONGS outages. 25

Similarly, TURN witness Woodruff addresses three categories of costs that SCE 26

identified as being “other non-quantifiable costs” as part of SCE’s identification of cost categories that 27

were potentially impacted by the SONGS outages. TURN acknowledges that “[n]o estimates of such 28

costs may be possible in computing SCE’s” estimated 2012 replacement power costs and foregone 29


22

energy sales net revenue associated with the SONGS outages.59 However, the issue is broader than an 1

inability to ascertain what portion, if any, of the identified cost categories are associated with the 2

SONGS outages.60 Most importantly, it is the fact that the identified cost categories are not costs that 3

are directly incurred to backfill SONGS generation to cover SCE’s net short position that is sufficient 4

reason not to consider them in any estimate of replacement power costs associated with the 2012 5

SONGS outages. Only the costs that SCE incurred to replace SONGS generation capacity and energy to 6

serve bundled customer demand should be considered in the estimate of replacement power costs 7

associated with the SONGS outages. The impact of the SONGS outages on the operation of the market 8

and the CAISO’s cost allocation mechanisms for market-related uplift costs are, at most, indirect costs 9

which should not factor into a consideration of replacement costs to serve bundled customer demand. 10

6. Summary Of SCE’s Estimate Of 2012 Replacement Costs And Foregone Energy 11

Sales Net Revenues Recorded In Its OMA 12

Table II-3 below summarizes the 2012 OMA replacement power costs and foregone 13

energy sales net revenue that SCE has identified as being directly associated with the 2012 SONGS 14

outages to serve its bundled customer demand. These estimates represent a substantial subset of the 15

total market-related costs that SCE has recorded in its OMA in compliance with Commission direction. 16

Table II-3 estimate does not include CRR congestion costs as SCE previously described, nor does it 17

include any of the grid reliability costs that TURN identified. SCE continues to reserve the right to 18

present an alternative cost impact methodology in a subsequent phase of I.12-10-013 if such a 19

calculation is necessary. 20


60 The three cost categories are: (1) Bid Cost Recovery market uplift charges; (2) total SCE portfolio congestion charges; and (3) non-attributable Grid Management Charges. SCE is not aware of any objective means to determine how much, if any, of these charges incurred in 2012 were associated with the SONGS outages. TURN witness Woodruff identified the three cost categories as confidential information because they were identified on a confidential SCE workpaper. SCE does not consider the identification of these cost categories to be confidential information, and therefore publicly discloses the subject cost categories.

23

Table II-3 Estimated Replacement Energy Costs and Foregone Energy Sales

Net Revenue Associated with 2012 SONGs Outages

Cost Category Amount

Replacement Energy (Table XVII‐1) $200,597,245

Capacity‐Related Costs (Table XVII‐3) $33,141,178

Real‐Time Imbalance Energy Charges (1/31/13 ‐ 2/1/13) $27,245

On‐Site Auxiliary Load Charges $7,089,443

PIRP Allocation Charges to SONGS $101,786

LESS: Scheduled Refueling Period Costs (Table XVII‐5) ($37,348,402)

Total of Replacement Power Costs $203,608,495

Foregone Energy Sales Net Revenue (Table XVII‐2) $95,304,825

LESS: Scheduled Refueling Period Costs (Table XVII‐5) ($12,248,058)

Total of Foregone Energy Sales Net Revenue $83,056,767

Note: Table references are to SCE's April 2, 2013, ERRA Testimony, Chapter XVII

24

III. 1

CONCLUSION 2

For the reasons discussed above, the Commission should not adopt TURN’s proposed cost 3

adjustments and related ratemaking proposals. In addition, the Commission should not adopt TURN’s 4

estimate of what TURN deems “replacement power” costs. 5

6

Witness Qualifications

1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF RICK FISHER 3

Q. Please state your name and business address for the record. 4

A. My name is Rick Fisher, and my business address is 2244 Walnut Grove Avenue, Rosemead, 5

California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Manager of Capital Reporting and Integration. I manage a team responsible for 8

special projects supporting systems and business process integration across the Controller’s 9

organization, with a core function of supporting the Capital Asset Accounting division. 10

Q. Briefly describe your educational and professional background. 11

A. I have a Bachelor of Science degree in Business Administration, with an emphasis in 12

Finance, Real Estate, and Law from California State Polytechnic University, Pomona, and a 13

Masters of Business Administration from the University of Southern California. I am a 14

member of the Society of Depreciation Professionals and have been qualified as a Certified 15

Depreciation Professional. 16

I joined Southern California Edison in the Capital Recovery Department in 1999 and from 17

1999-2006 I performed the role of a financial analyst. I was promoted to Manager of Capital 18

Recovery in 2006. My responsibilities included functions involving depreciation and nuclear 19

decommissioning accounting, depreciation studies, and the development of forecasting 20

models for plant additions, rate base, and depreciation expense in direct support of the 21

Company’s regulatory filings. In 2008 I accepted a position in the Investor Relations group at 22

Edison International, where my primary role was communicating the Company’s financial 23

and operational results with institutional equity and fixed income investors and analysts. In 24

2010 I rejoined Southern California Edison and assumed my current role as Manager of 25

2

Capital Reporting and Integration in the Financial Information Services division of the 1

Controller’s Organization. 2

Q. What is the purpose of your testimony in this proceeding? 3

A. The purpose of my testimony in this proceeding is to sponsor those portions of Exhibit No. 4

SCE-08, entitled SCE’S Rebuttal to TURN’s Testimony, as identified in the Tables of 5

Contents thereto. 6

Q. Was this material prepared by you or under your supervision? 7

A. Yes, it was. 8

Q. Insofar as this material is factual in nature, do you believe it to be correct? 9

A. Yes, I do. 10

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 11

judgment? 12

A. Yes, it does. 13

Q. Does this conclude your qualifications and prepared testimony? 14

A. Yes, it does. 15

3



OF COLIN E. CUSHNIE 3


A. My name is Colin E. Cushnie, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770. 6


A. I am the Director of the Portfolio Planning & Analysis Department in the Power Supply 8

organization. My department’s responsibilities include demand and price forecasting, 9

portfolio analysis and risk management, contract and solicitation valuations, portfolio 10

reporting, Congestion Revenue Rights acquisition, and fundamental modeling. 11


A. I earned a Bachelor of Arts Degree in both Economics and Business Administration from 13

Whittier College in 1986. I was hired by SCE in January 1987 and held various positions 14

related to the procurement of material, equipment, and services until October 1993. Since 15

October 1993, I have held positions of increased responsibility related to natural gas and 16

electrical energy planning, procurement, and regulatory support. In September 2004, I 17

assumed a position as a Director of Regulatory Affairs in SCE’s Regulatory Affairs & Policy 18

department. In February 2010, I assumed the position of Director of Energy Planning, a 19

position which transitioned to my current role in March 2013. In my current position, I 20

manage a staff of approximately forty-five energy professionals. 21


A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit No. SCE-23

08, entitled SCE’S Rebuttal to TURN’s Testimony, as identified in the Tables of Contents 24

thereto. 25


A. Yes, it was. 27

4


A. Yes, I do. 2


judgment? 4

A. Yes, it does. 5


A. Yes, it does. 7

5



OF PAUL T. HUNT, JR. 3


A. My name is Paul T. Hunt, Jr., and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770. 6


A. I am the Director of Regulatory Finance and Economics, supervising the Regulatory Finance 8

Division of the Treasurer’s Department. My present responsibility is to apply economic, 9

financial, and statistical analysis to regulatory issues and for internal corporate purposes. 10


A. I received a Bachelor of Arts degree in Economics from Pomona College in 1975, a Master 12

of Arts degree in Economics from Stanford University in 1976, and a Doctor of Philosophy 13

degree from Stanford University in 1981. I joined the Southern California Edison Company 14

as an Associate Economist in the Treasurer’s Department in July 1980. I was promoted to 15

Economist in 1982 and Senior Economist in 1984. In 1989, I transferred to the Regulatory 16

Policy and Affairs Department as a Regulatory Economics Consultant. I returned to the 17

Treasurer’s Department in 1996 as a Senior Economist. In 1997, I was promoted to Project 18

Manager. In 2000, I was promoted to Manager of Regulatory Finance and Economics. I was 19

promoted to my present position in 2010. 20

I have testified before the California Public Utilities Commission and the Federal 21

Energy Regulatory Commission. 22

In late 2009, I was invited to write, with a co-author, a book chapter on cost of capital 23

in regulated industries. The book chapter is titled “Cost of Capital in Regulated Industries,” 24

and it appears in Cost of Capital in Litigation: Applications and Examples, published by John 25

Wiley & Sons, Inc., in November 2010. (ISBN: 978-0-470-88094-4.) 26


6

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit No. SCE-1

08, entitled SCE’S Rebuttal to TURN’s Testimony, as identified in the Table of Contents 2

thereto. 3


A. Yes, it was. 5


A. Yes, I do. 7


judgment? 9

A. Yes, it does. 10


A. Yes, it does.12

7



OF JOSE LUIS PEREZ 3


A. My name is Jose Luis Perez, and my business address is 8631 Rush Street, Rosemead, CA 5

91770. 6


A. I manage the Generation Planning and Strategy organization. 8


A. I earned an MBA from the University of California, Irvine in 1997. I earned a Bachelor of 10

Science Degree in Civil Engineering from California State University, Long Beach in 1977. I 11

am a Registered Professional Engineer and a Licensed General Contractor in the State of 12

California. Prior to joining Edison, my professional background included various home office 13

and jobsite positions in the civil engineering and scheduling organizations of Bechtel Power 14

Corporation and the collection and analysis of construction cost data for publication in cost 15

estimating manuals for Marshall and Swift Publications. Since joining Edison in 1982, I have 16

held various management positions in the business planning groups of the Generation Business 17

Unit. In addition, I managed various projects, including SONGS Unit 1 decommissioning 18

shortly after permanent shutdown, and various activities in support of the industry restructuring 19

efforts. 20


A. The purpose of my testimony in this proceeding is to sponsor the portions of Exhibit No. SCE-22

08, entitled SCE’S Rebuttal to TURN’s Testimony, as identified in the Table of Contents thereto. 23


A. Yes, it was. 25


A. Yes, I do. 27

8


judgment? 2

A. Yes, it does. 3


A. Yes, it does.5

9



OF RUSSELL G. WORDEN 3


A. My name is Russell G. Worden, and my business address is 2244 Walnut Grove 5

Avenue, Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison 7

Company. 8

A. I am presently a Director of Regulatory Affairs in Edison’s External Relations 9

Department and the case manager for SCE in the current CPUC investigation of 10

the outages at the San Onofre Nuclear Generating Station (SONGS), investigation 11

(I.) 12-10-013. My responsibilities have previously included management of 12

SCE’s 2003, 2006, 2009 and 2012 general rate cases. I was responsible for 13

negotiating the phase of Edison’s Test Year 1995 General Rate Case Settlement 14

relating to the rate recovery of SONGS Units 2&3. Also, I was responsible for 15

negotiating the settlement that modified Edison’s ratemaking for the Palo Verde 16

Nuclear Generating Station. 17


A. I received an Associate of Arts degree from Cabrillo College, in Aptos, California 19

in 1974. I graduated from San Francisco State University in 1977 with a Bachelor 20

of Arts degree in Political Science, cum laude. After college, I joined the 21

Washington, D.C. staff of U.S. Senator Richard Stone (D-FL) where I served as a 22

Legislative Aide until December 1980. From January 1981 until March 1985, I 23

served as a Legislative Assistant to then Congressman Ron Wyden (D-OR). In 24

March 1985, I joined the Washington, D.C. office of Southern California Edison 25

as a Governmental Affairs Assistant, and in May 1988, I transferred to Edison’s 26

10

Revenue Requirements Department. I transferred to my current position in 1

August 2012. 2


A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit 4

No. SCE-08, entitled SCE’S Rebuttal to TURN’s Testimony, as identified in the 5

Table of Contents thereto. 6


A. Yes, it was. 8


A. Yes, I do. 10

Q. Insofar as this material is in the nature of opinion or judgment, does it represent 11

your best judgment? 12

A. Yes, it does. 13


A. Yes, it does. 15

16

Documents

SCE’S Rebuttal to TURN’s Testimony · 2 1 II. 2 RESPONSE TO TURN TESTIMONY 3 A. Response To Testimony Submitted By William Marcus 4 1. Summary Of Mr. Marcus’s Recommendations