before the public utilities commission of the state of … · 2020. 3. 20. · ndts at $0.0 (zero),...

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

Joint Application of Southern California Edison Company (U 338-E) and San Diego Gas & Electric Company (U 902-E) For the 2018 Nuclear Decommissioning Cost Triennial Proceeding.

)) ) ) )

A.18-03-009

SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E) AND SAN DIEGO GAS &

ELECTRIC COMPANY’S (U 902-E) JOINT REPLY BRIEF FOR PHASE 3

WALKER A. MATTHEWS III ELIZABETH C. BROWN Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-6879 E-mail: [email protected]

ALLEN K. TRIAL Attorney for SAN DIEGO GAS & ELECTRIC COMPANY 8330 Century Park Court, CP32D San Diego, CA 92123 Telephone: (858) 654-1804 Facsimile: (619) 699-5027 E-mail: [email protected]

Dated: March 20, 2020

SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E) AND SAN DIEGO GAS & ELECTRIC COMPANY'S (U 902-E) JOINT REPLY BRIEF FOR PHASE 3

TABLE OF CONTENTS

Section Page

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I. INTRODUCTION AND SUMMARY OF ARGUMENTS .....................................................................1

A. The Commission Should Approve The SONGS 1 And SONGS 2&3 DCEs As Reasonable ......................................................................................................................2

Evidence Submitted By The Utilities Demonstrates That The DCEs Are Reasonable ..............................................................................................2

Cal Advocates and TURN Ignore Or Misconstrue Evidence ..................................3

The DCE Should Reflect All Legal Requirements, Known Costs, And Reasonable Contingency ..................................................................................4

TURN Misconstrues The Purpose Of The DCE ......................................................6

The Commission Should Limit Its Review To Phase 3 Scoping Memo Issues ............................................................................................................6

B. The Commission Should Approve The Utilities’ Other Unchallenged Requests ...............................................................................................................................7

C. Briefing Outline ...................................................................................................................7

II. SONGS 1 DECOMMISSIONING COST ESTIMATE AND CUSTOMER-CONTRIBUTION ANALYSES ......................................................................................................8

A. Overview of Issues/Recommendations ................................................................................8

B. Discussion ............................................................................................................................9

III. SONGS 2&3 DECOMMISSIONING COST ESTIMATE AND CUSTOMER-CONTRIBUTION ANALYSES ....................................................................................................11

A. Overview Of Issues/Recommendations .............................................................................11

B. Discussion ..........................................................................................................................12

The Commission Should Reject Cal Advocates’ Recommendations Regarding SONGS 2&3 Conduit Removal Costs .................................................12

The Commission Should Reject TURN’s Recommendations Regarding Contingency .........................................................................................14


TABLE OF CONTENTS (CONTINUED)

Section Page

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a) TURN Fails To Understand That The Scope Of Work May Need To Change, Resulting In Cost Increases That Will Be The Utilities’ Responsibility ......................................................................14

b) Contractor-Included Contingency Generally Covers The Contractors’ Performance Risk, But Does Not Cover The Utilities’ Scope And Regulatory Risks ......................................................16

c) Unexpected Conditions May Lead To Scope Changes Beyond The Agreed-Upon Contract Scope ...............................................17

d) The Contingency Factors Included For The DGC Agreement And Holtec Contract Are Reasonable ....................................19

(1) SCE Utilized Objective Criteria To Determine Contingency ...................................................................................20

(2) An Independent, Third-Party Expert Validated The Contingency ...................................................................................21

(3) TURN’s Ad Hominem Attacks Are Demonstrably False ...............................................................................................22

(4) The DCE Contents And Prior DCEs Show That The Utilities Do Not Manipulate The DCEs .........................................23

e) TURN’s Alternative Contingency Recommendation Is Faulty .........................................................................................................24

The Commission Should Reject TURN’s Recommendations To Remove $104.1 Million From The DCE Associated With SCE’s Extension Of The DGC Schedule ..........................................................................25

The Commission Should Reject TURN’s Recommendations To Eliminate $13.8 Million For Notice To Proceed Delay .........................................27

The Commission Should Reject TURN’s Recommendations To Eliminate $38.2 Million For Additional Remediation Costs .................................30

IV. MILESTONE FRAMEWORK ............................................................................................................32

V. DOE LITIGATION PROCEEDS .........................................................................................................33

A. The Commission Should Continue To Review SCE’s DOE Litigation Efforts In SCE’s ERRA Proceeding ..................................................................................33


TABLE OF CONTENTS (CONTINUED)

Section Page

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B. The Reporting Of Damages Claims To Line Items Within The DCE Would Serve No Beneficial Purpose .................................................................................35

C. SCE Has Explained The DOE Pick-Up Strategy Assumed In The DCE ..........................36

VI. RETURN OF EXCESS FUNDS .........................................................................................................38

A. The Utilities Have Already Submitted Information Demonstrating The Challenges In Identifying And Returning Perceived Excess Funds ..................................39

B. TURN’s Recommendation Is Premature At This Stage Of Decommissioning ..............................................................................................................40

VII. MISCELLANEOUS ...........................................................................................................................41

A. 2021 NDCTP Filing Date ..................................................................................................41

B. Miscellaneous TURN Recommendations ..........................................................................42

Advice Letter Reporting Requirements .................................................................42

DGC Amendments .................................................................................................42

Potential Savings From A Decision By The Navy ................................................43

Consolidation Of DCEs .........................................................................................44

C. The Issues Raised By A4NR Are Beyond The Scope Of This NDCTP ............................45

Consistency Of SONGS Decommissioning Plan With Public Trust Doctrine, the Coastal Act, and the California Constitution ...................................46

Radiological Release Criteria ................................................................................46

ISFSI Experts Team ...............................................................................................47

VIII. CONCLUSION .................................................................................................................................47


TABLE OF AUTHORITIES

Page

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Statutes 26 C.F.R. § 1.468A-5 (c)(2)(i) .................................................................................................................. 39 26 C.F.R. § 1.468A-5 (c)(2)(ii) ................................................................................................................. 39 26 C.F.R. § 1.468A-5(c)(1) ....................................................................................................................... 39 26 U.S. Code § 468A(e)(4) ....................................................................................................................... 39 Cal. Pub. Util. Code § 8321 ........................................................................................................................ 4 Cal. Pub. Util. Code § 8322(d) ................................................................................................................... 6 Cal. Pub. Util. Code § 8326 ........................................................................................................................ 5 Cal. Pub. Util. Code § 8327 ........................................................................................................................ 5

CPUCDecisions D.11-07-003 .............................................................................................................................................. 15 D.16-04-019 .......................................................................................................................................... 5, 41 D.18-11-034 ....................................................................................................................................... passim

CPUCRulesofPracticeandProcedure Rule 13.1 ..................................................................................................................................................... 1

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SUMMARY OF RECOMMENDATIONS

Southern California Edison Company (SCE) and San Diego Gas & Electric Company

(SDG&E) (collectively referred to as the Utilities) respectfully recommend that the Commission

find as reasonable:

(1) the 2017 San Onofre Nuclear Generating Station Unit 1 (SONGS 1) decommissioning

cost estimate (DCE) of $209.0 million (100% share, 2014 $) for remaining SONGS 1

decommissioning work;

(2) the 2017 SONGS Units 2&3 (SONGS 2&3) DCE of $4,479 million (100% share,

2014 $) for SONGS 2&3 decommissioning work;

(3) the Utilities’ request to maintain annual contributions to their respective SONGS 1

Nuclear Decommissioning Trusts (NDTs) at $0.00 (zero), based upon the 2017 SONGS 1 DCE,

current level of funding of the respective SONGS 1 NDTs, forecast returns on the NDTs, and

projected escalation rates at this time;

(4) the Utilities’ request to maintain annual contributions to their respective SONGS 2&3

NDTs at $0.0 (zero), based upon the 2017 SONGS 2&3 DCE, current level of funding of the

SONGS 2&3 NDTs, forecast returns on the NDTs, and projected escalation rates at this time;

(5) the Utilities’ proposed amendment to the Milestone Framework for reasonableness

reviews of SONGS 2&3 decommissioning costs for waste-disposal activities;

(6) the Utilities’ Cost-Categorization Guidelines; and

(7) the Utilities’ compliance with prior Commission decisions in the Nuclear

Decommissioning Costs Triennial Proceeding (NDCTP).

SDG&E respectfully recommends that the Commission find as reasonable:

(1) SDG&E’s estimate of $45.9 million (SDG&E share, 2014 $) for SDG&E-only

decommissioning costs.

1


STATE OF CALIFORNIA


)) ) ) )

A.18-03-009

SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) AND SAN DIEGO GAS &

ELECTRIC COMPANY’S (U 902-E) JOINT REPLY BRIEF FOR PHASE 3

Pursuant to Rule 13.1 of the California Public Utilities Commission’s (Commission)

Rules of Practice and Procedure and the July 10, 2019 “Administrative Law Judge’s Ruling

Correcting Modified Schedule for Phase 3 of the Proceeding Issued on July 5, 2019” (Ruling),

Southern California Edison Company (SCE) and San Diego Gas & Electric Company (SDG&E)

(collectively referred to as the Utilities) respectfully submit this Joint Reply Brief for Phase 3 of

the 2018 Nuclear Decommissioning Costs Triennial Proceeding (NDCTP).

I.

INTRODUCTION AND SUMMARY OF ARGUMENTS

In this Joint Reply Brief, the Utilities respond to opening briefs submitted by the Public

Advocates Office (Cal Advocates), The Utility Reform Network (TURN), and the Alliance For

Nuclear Responsibility (A4NR).

2

A. The Commission Should Approve The SONGS 1 And SONGS 2&3 DCEs As

Reasonable

Evidence Submitted By The Utilities Demonstrates That The DCEs Are

Reasonable

As summarized in the Utilities’ Joint Opening Brief, the Utilities submitted ample

evidence demonstrating the reasonableness of the SONGS 1 and SONGS 2&3 DCEs.1 Fulfilling

requirements established in prior NDCTP decisions, the Utilities’ testimony explained the

regulatory, contractual, technical, and engineering bases for estimated decommissioning costs,

and provided variance explanations against the two most-recently approved DCEs.2 A

reasonableness finding by the Commission is further supported by independent reports

completed by cost-estimating experts ABZ Incorporated (ABZ) and Carignan & Associates

(C&A), and expert testimony prepared by decommissioning experts Mr. Nicholas Capik and

Mr. Adam Levin.3 These reports and testimony comprehensively reviewed all aspects of the

DCEs (including the planned scope of work, schedule, contract status, underlying assumptions,

and contingency) and concluded that both the 2017 SONGS 1 and SONGS 2&3 DCEs are

reasonable.4 As discussed below, no intervenors substantively refuted these findings in their

testimony or opening briefs.

1 See generally Exhibit SCE-02 Rev 1 (supporting the 2017 SONGS 1 DCE); Exhibit SCE-03C (supporting the 2017 SONGS 2&3 DCE); Exhibit SDGE-03C-R (supporting the 2017 SONGS 1 and SONGS 2&3 DCEs). Cites within this Joint Reply Brief to confidential exhibits may also be reviewed in the non-confidential versions of the exhibits.

2 Id.; Exhibits SCE-12 and SCE-12C provide testimony comparing the 2017 DCEs to the two-most recently approved DCEs. No party challenged the variance explanations.

3 Exhibit SCE-01, pp. 17-18; Exhibit SCE-03C, pp. 9-12; Exhibit SDGE-03C-R, p. 2-12. 4 Id.

3

Cal Advocates and TURN Ignore Or Misconstrue Evidence

Notably, Cal Advocates and TURN did not address or challenge the financial,

technical, and engineering bases (e.g., labor rates, quantities, technical and engineering plans,

and other related assumptions) for the estimated costs. They instead recommended various

reductions to the DCEs, contrary to controlling law and Commission precedent, based on an

incomplete review of the evidentiary record, incorrect legal interpretations, and shortsighted

policy positions that ignore the Utilities’ legal obligations, known costs, and risks.

Cal Advocates, for example, failed to substantively address or review the terms of

the Utilities’ existing SONGS 1 and SONGS 2&3 conduit leases with the California State Lands

Commission (CSLC). Instead, they simply ignored controlling lease provisions altogether,

perfunctorily dismissing the Utilities’ legal obligations to remove the conduits if directed by the

CSLC, as though the obligations are irrelevant or non-existent. They are not.

As a further example, TURN’s opening brief directed ad hominem attacks

asserting the Utilities are biased to present inflated DCEs and that their professional engineering,

legal, and financial staffs and consultants are complicit in that effort.5 TURN’s rhetoric calls

SCE’s evaluations by professional estimators a “mirage.”6 Resorting to this type of petty

argument, TURN does not review the DCEs in a deliberative, substantive way. Rather, TURN

attempts merely to impugn the integrity of professionals who take very seriously their

professional and ethical obligations to comprehensively and accurately prepare and review DCEs

and supporting materials submitted in the NDCTP.7 TURN’s opening brief also raises several

5 TURN Opening Brief, pp. 11-12, 17. 6 Id. 7 The 2017 SONGS 1 and SONGS 2&3 DCEs were prepared by the Kenrich Group, a national

management consulting firm with substantial experience in the public utility industry, nuclear power plant construction and decommissioning, and other commercial and public construction projects. Kenrich’s consultants include accountants, financial analysts, and engineering. Exhibit SCE-02 Rev 1, p. B-8; Exhibit SCE-03C, p. B-11. SCE witness, Mr. Jose Perez, who sponsored testimony in

Continued on the next page

4

strawman arguments that mischaracterize the Utilities’ testimony and arguments, and then use

those mischaracterizations to justify its recommended reductions. One example is TURN’s

suggestion that the Utilities use a default contingency of 25% based on prior “cherry-picked”

Commission decisions in the NDCTP.8 This is plainly inaccurate. For many decommissioning

activities in the 2017 SONGS 1 and SONGS 2&3 DCEs, including work scopes under contracts,

the Utilities applied lower contingency factors than included in prior DCEs.9

The Commission should give no weight to TURN’s fallacious arguments and

mischaracterizations in this proceeding.

The DCE Should Reflect All Legal Requirements, Known Costs, And

Reasonable Contingency

Given the absence of a substantive basis for their proposed reductions, Cal

Advocates and TURN fundamentally do not challenge the reasonableness of the SONGS 1 and

SONGS 2&3 DCEs. Rather, the proposed reductions offer alternative, lowball DCEs based on

unfounded assumptions that certain activities will not need to be completed, or that uncertainties

and risks will never arise. This is not a sound approach to developing and reviewing DCEs, and

the Commission should reject it.

Under the California Nuclear Facilities Decommissioning Act of 198510

(Decommissioning Act) and established Commission precedent, DCEs must reflect all

Continued from the previous page

support of the SONGS 1 and SONGS 2&3 DCEs is a registered professional engineer in California. Exhibit SCE-02 Rev 1, p. A-1; Exhibit SCE-03C, p. A-1. In addition to his business and financial services management experience, Mr. Perez has significant experience preparing decommissioning estimates and proposals for nuclear powerplants across the United States. He also has managed the decommissioning activities at several plants, including SONGS 1 and the Rancho Seco nuclear power plant. A.16-03-004, Tr. Vol. 3, p. 316, line 12 to p. 317, line 11. Mr. Thomas S. LaGuardia of C&A, who supported SDG&E’s reasonableness finding, is a registered engineer in Connecticut, New York, New Jersey, and Virginia, and is also an AACEI Certified Cost Professional (CCP). Exhibit SDGE-03C-R, Attachment B, p. 33.

8 TURN Opening Brief, p. 17. 9 Exhibits SCE-3 and SCE-3C, p. 7. 10 Cal. Pub. Util. Code § 8321, et seq.

5

reasonably known costs and potential cost risks in order to confirm the Utilities’ NDTs are

sufficiently funded.11 The adoption of Cal Advocates’ and TURN’s proposed reductions would

ignore known legal requirements and cost risks, substantially distorting the Commission’s review

of the sufficiency of the Utilities’ NDTs, particularly if the proposed reductions were carried

forward in future DCEs. Past events such as 9/11 and recent events involving the coronavirus

(COVID-19) pandemic unfortunately demonstrate the significant impact external risks have on

planned events and projects, industries, markets, and the world economy, when those risks

materialize. They further illustrate the mistake of ignoring risks and effectively wagering that

they will never arise.

Putting aside real external risks such as these, it is important to remember that the

Utilities are only in year 6 of a nearly 40-year decommissioning project that involves the

dismantling and radiological decommissioning of a large, complex, two-unit nuclear powerplant

that operated for 30 years. To put the proposed reductions into context, Cal Advocates and

TURN seek to reduce the 2017 SONGS 2&3 DCE by more than 10% compared to the

Commission-approved 2014 DCE, notwithstanding that major decommissioning activities have

only just commenced and there are no material changes in regulatory or legal requirements, site

conditions, technology, and economic conditions justifying cost decreases. It is extremely

shortsighted at this early stage for Cal Advocates and TURN to argue for DCE reductions that

ignore legal requirements, known costs, and risks. The 2017 SONGS 1 and SONGS 2&3 DCEs

must reflect all legal requirements, known costs, and a reasonable contingency to account for

risks that could materially impact the SONGS decommissioning project scope and costs. It is

entirely premature to reduce the DCEs based on hopeful speculation that certain risks and costs

will not arise.

11 D.16-04-019, p. 16; Cal. Pub. Util. Code §§ 8326 and 8327.

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TURN Misconstrues The Purpose Of The DCE

The fact that costs are included in the DCE does not mean the Utilities will incur

the costs during decommissioning. The Utilities must justify all decommissioning expenditures

during NDCTP reasonableness reviews.

TURN seeks certain downward adjustments in the 2017 SONGS 2&3 DCE as a

mechanism to either disallow costs resulting from perceived imprudence (project delays) by the

Utilities12 or compel potential cost savings based on optimistic assumptions.13 Neither is an

appropriate use of a DCE. First, it is premature to reduce a DCE by deeming costs associated

with project delays as imprudent prior to the Commission’s reasonableness review of the

Utilities’ activities and associated costs. Second, as noted above, the Commission should adopt a

DCE reflecting all reasonably known costs and potential cost risks in order to confirm NDT

sufficiency, not adopt a deflated DCE distorting that review. This approach ultimately will

protect both the Utilities’ customers and shareholders from the financial risks posed by

decommissioning, consistent with the decommissioning cost-review framework established

under the Decommissioning Act.14 The DCE must reasonably identify all costs so that the

Commission fully understands these risks.

The Commission Should Limit Its Review To Phase 3 Scoping Memo Issues

Both TURN and A4NR make several recommendations regarding various issues

that are beyond the scope of Phase 3. For example, TURN reiterates various observations and

recommendations regarding the status and reasonableness of decommissioning activities to date,

12 TURN Opening Brief, p. 1 (recommending a reduction based on perceived unnecessary delays by SCE in commencing certain decommissioning activities).

13 Id., p. 1 (recommending a reduction based on achieving an optimistic schedule) 14 Cal. Pub. Util. Code § 8322(d) (noting that decommissioning costs introduce financial risk to both the

Utilities’ customers and shareholders).

7

advice letter reporting requirements, and return of potential excess NDT funds. A4NR raises

concerns regarding the timing of certain substructure removal work and the long-term use of the

SONGS site following decommissioning but offers no substantive recommendations (proposed

increases or decreases) in regard to the DCEs. The Commission should disregard these

extraneous issues in its Phase 3 decision.

B. The Commission Should Approve The Utilities’ Other Unchallenged Requests

Finally, the Utilities made several requests that no intervenors have opposed in their

testimony or opening briefs. These requests include: (1) a proposed amendment to the

Milestone Framework regarding the review of SONGS 2&3 waste-disposal costs in the

NDCTP;15 (2) Cost Categorization Guidelines, fulfilling the requirements of D.18-11-034;16 and

(3) testimony demonstrating the Utilities’ compliance with prior Commission NDCTP

decisions.17 In addition, no party has challenged SDG&E’s estimate of SDG&E-only costs for

decommissioning. The Commission should determine that each of these unchallenged requests

are reasonable.

C. Briefing Outline

The Utilities address Cal Advocates’, TURN’s, and A4NR’s opening briefs and

arguments in further detail in the remainder of this Joint Reply Brief. As provided in the

common briefing outline discussed by the parties following evidentiary hearings, the Utilities’

Joint Reply Brief is organized as follows:

Section II – SONGS 1 DCE and Customer-Contribution Analysis

Section III – SONGS 2&3 DCE and Customer-Contribution Analysis

15 Exhibit SCE-SDGE-01, pp. 1-5. 16 Exhibit SCE-11, pp. 1-8 and Appendix A; Exhibit SDGE-08, pp. 1-3 and Attachment A. 17 Exhibit SCE-13; Exhibit SDGE-08, pp. 6-11.

8

Section IV – Milestone Framework

Section V – Department of Energy (DOE) Litigation Proceeds

Section VI – Return of Excess Funds

Section VII – Miscellaneous Issues

Section VIII – Conclusion

II.

SONGS 1 DECOMMISSIONING COST ESTIMATE AND CUSTOMER-

CONTRIBUTION ANALYSES

A. Overview of Issues/Recommendations

The Utilities request that the Commission approve as reasonable the 2017 SONGS 1

DCE of $209.0 million (100% share, 2014 $).18 The Utilities also request that the Commission

maintain annual contributions at $0.0 for their respective SONGS 1 NDTs.19

The only issue raised regarding the 2017 SONGS 1 DCE pertains to Cal Advocates’

recommendation to remove $34 million from the 2017 SONGS 1 DCE for the full removal of the

SONGS 1 conduits.20 Otherwise, intervenors do not challenge any other portion of the

SONGS 1 DCE. In addition, intervenors do not challenge the Utilities’ $0.0 customer-

contribution request.

The Utilities respond to Cal Advocates’ recommendation below.

18 Exhibit SCE-02 Rev 1, p. 1; Exhibit SDGE-03C-R, p. 1. 19 Exhibit SCE-06, p. 3; Exhibit SDGE-04, p. 7. 20 Cal Advocates Opening Brief, p. 1; Exhibit CalAdvocates-02, p. 1.

9

B. Discussion

Cal Advocates argues that the Utilities did not provide new information required by

D.18-11-034 to support including SONGS 1 conduit removal costs in the DCE – principally, the

Lease Termination Agreement once finalized with the CSLC.21 Because discussions regarding

the termination agreement remain ongoing, the Utilities acknowledge they are unable to provide

a copy of the final agreement delineating their obligations regarding the conduits.22/23 However,

the Utilities’ inability to provide a final agreement should not change the Commission’s

conclusion that SONGS 1 conduit removal costs should be included in the 2017 SONGS 1 DCE.

Based upon the currently existing SONGS 1 conduit lease (Lease No. PRC 3193), there is no

doubt or confusion what the removal requirements will be. Section 2, Paragraph 10 of the lease

states, in part:

10. . . . [P]ermanent disposition of the authorized facilities [the remaining conduits] will be pursuant to a future Lease Termination Agreement that will detail Lessee’s obligations and responsibilities for any abandoned facilities, including but not limited to, . . . removal of any remaining facilities to the extent that they become a public safety hazard at any time in the future; and Lessee’s obligation to provide sufficient financial assurance to guarantee faithful performance of the Lease Termination Agreement.24

Cal Advocates ignores this provision altogether. But the provision supports two

conclusions. First, for as long as any portion of the SONGS 1 conduits remains abandoned in

21 Cal Advocates Opening Brief, pp. 2-4. 22 SCE continues to negotiate the lease termination agreement with the CSLC but will provide a copy

when it is finalized. 23 Although SCE was unable to submit new information regarding the SONGS 1 lease termination

agreement, SCE has submitted the new SONGS 2&3 conduit lease (Lease No. PRC 6785.1 dated March 21, 2019), which requires the Utilities to remove the SONGS 2&3 conduits if directed to do so by the CSLC. The Utilities discuss the SONGS 2&3 lease’s requirement in further detail in Section III. Although the SONGS 1 termination agreement has not been finalized, it is reasonable to conclude it will contain terms similar to the SONGS 2&3 lease.

24 Exhibit SCE-16, p. 5 (Lease No. PRC 3193.1) (Emphasis added).

10

place, the Utilities will remain liable for the cost to remove them. Second, the Utilities will be

required to provide financial assurance that they will be able to fulfill this liability. The Utilities

must therefore not only recognize this liability; they must provide assurance that sufficient

decommissioning funding exists and has been set aside exclusively for this purpose. No facts

have emerged to indicate this liability will not be included in the Lease Termination Agreement

once finalized.25

In addition, while the Commission expressed its expectation for the final agreement to be

provided, the Commission also stated in D.18-11-034 that “we expect future DCEs to include

information that is known or reasonably should be known to SCE at the time the DCE is

prepared.”26 Thus, the Commission unequivocally established that known or reasonably

anticipated costs should be included in the DCE. Here, the conduit removal costs are precisely

the type of costs that the Commission directed SCE to include in a DCE. Regardless of how far

into the future SCE may be ordered by the CSLC to fully remove the conduits in the event they

become a public hazard, SCE will remain obligated to do so. Therefore, the Utilities must

continue to include the work scope and associated cost for the full removal of the SONGS 1

conduits in the DCE.

Further, notwithstanding the uncertain timing and contingent nature of the liability, the

Utilities are required to include the estimated cost of this liability in their financial statements

under the Asset Retirement Obligation provisions of Generally Accepted Accounting Principles

(GAAP).27 Given that GAAP recognizes this obligation as a liability, it reasonably follows that

the conduit removal costs should be included in the DCE as a known cost. Cal Advocates’

recommendation to exclude the conduit removal costs from the 2017 SONGS 1 DCE would

25 Exhibit SCE-15, p. 2. 26 D.18-11-034, p. 68 (Emphasis added). 27 Exhibit SCE-02 Rev. 1, p. 8, fn. 25.

11

cause SCE to be out of compliance with the Commission’s direction to include all known or

reasonably anticipated costs in the DCE. The Utilities respectfully urge that the better approach

is to include the cost in the DCE until the liability is extinguished.

The Commission should also consider that there is no harm to customers in including

conduit-removal costs in the DCE. The purpose of the DCE is to identify decommissioning

obligations and costs. Customers will not be harmed if the costs are included in the DCE but

ultimately not used. Removing the costs from the DCE, on the other hand, would distort the

Commission’s review of the DCE and assessment of whether the Utilities’ NDTs are sufficiently

funded.

III.

SONGS 2&3 DECOMMISSIONING COST ESTIMATE AND CUSTOMER-

CONTRIBUTION ANALYSES

A. Overview Of Issues/Recommendations

The Utilities request that the Commission approve as reasonable the 2017 SONGS 2&3

DCE of $4,479 million (100% share, 2014 $).28 The Utilities also request that the Commission

maintain annual customer contributions at $0.0 for their respective SONGS 2&3 NDTs.29

Cal Advocates recommends that the Commission reduce the 2017 SONGS 2&3 DCE by

$91.6 million by removing SCE’s estimate for the full removal of the SONGS 2&3

intake/discharge conduits.30 TURN recommends several reductions to the SONGS 2&3 DCE,

including removing: (1) all contingency in the DCE for the DGC Agreement; (2) all contingency

in the DCE for the Holtec Contract; (3) undistributed costs of $104.1 million associated with

28 Exhibit SCE-03C, p. 1; Exhibit SDGE-03C-R, p. 1. 29 Exhibit SCE-06, p. 3; Exhibit SDGE-04, p. 7. 30 Cal Advocates Opening Brief, pp. 2 and 4; Exhibit CalAdvocates-02, pp. 1, 5.

12

SCE’s extension of the DGC schedule; (4) $13.8 million related to delay payments owed under

the DGC Agreement based on perceived imprudent delays by SCE to commence

decommissioning activities; and (5) $38.2 million associated with additional remediation costs.31

No intervenor opposes the Utilities’ $0.0 customer-contribution request for their respective

SONGS 2&3 NDTs.

The Utilities respond to Cal Advocates’ and TURN’s recommendations below.

B. Discussion

The Commission Should Reject Cal Advocates’ Recommendations

Regarding SONGS 2&3 Conduit Removal Costs

The Commission should reject Cal Advocates’ recommendation to remove $91.6

million from the 2017 SONGS 2&3 DCEs for the full removal of the SONGS 2&3 conduits.

Applying the same argument offered in support of its recommendation regarding the SONGS 1

conduits, Cal Advocates ignores that the SONGS 2&3 conduits are covered under a separate

lease agreement (Lease No. PRC 6785.1 dated March 21, 2019). The lease expressly requires

SCE to provide a performance guaranty and a separate performance surety bond for SCE’s

performance of all lease conditions, including removal of the SONGS 2&3 conduits if directed to

do so. SCE submitted the existing SONGS 2&3 lease into evidence, and it confirms these

obligations in several sections:

Section 2 (Special Provisions) Paragraphs 1 and 18(b) – “Nothing in this lease

shall be interpreted to restrict or waive Lessor’s [the CSLC’s] right or ability

31 TURN Opening Brief, pp. 1-2; SCE understood that TURN’s direct testimony recommended additional reductions of $26.5 million for craft escalation labor ($13.2 million) and fuel transfer operations (FTO) support ($13.3 million). But TURN’s opening brief does not make these recommendations and the Commission should thus deem them to be forfeited.

13

to require Lessee [SCE and SDG&E] . . . to remove any and all structures . .

.”32

Section 3 (General Provisions) Paragraph 10 – Lessee [SCE and SDG&E]

shall provide a surety bond . . . to guarantee to Lessor [CSLC] the faithful

observance and performance by Lessee [SCE and SDG&E] of all of the terms,

covenants and conditions of this Lease.”33 The amount of the bond is $75

million.34

Performance Guaranty – “[SCE] unconditionally guarantees to the State of

California, acting by and through the State Lands Commission (“State”) the

full and punctual performance by SCE of all of SCE’s obligations. . .”35

It makes little sense to remove SONGS 2&3 conduit removal costs from the 2017

DCE when these obligations are specified in a lease agreement. Because the conduit removal

costs are known or reasonably anticipated, they must be included in the DCE. The Commission

should reject Cal Advocates’ recommendation to exclude the SONGS 2&3 conduit removal costs

from the 2017 DCE.

On a related note, this same reasoning should apply to the SONGS 1 conduits. It

would be illogical to assume that the CSLC would include these requirements in the

SONGS 2&3 lease (requirement of a performance guarantee and performance bond) but remove

all of SCE’s liability for the adjacent SONGS 1 conduits.

32 Exhibit SCE-16, pp. 25 and 30. 33 Id., p. 41. 34 Id., p. 3. 35 Id., Exhibit E, p. 185.

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The Commission Should Reject TURN’s Recommendations Regarding

Contingency

TURN’s opening brief raises a litany of arguments in support of its

recommendation to remove contingency included in the 2017 SONGS 2&3 DCE for the DGC

Agreement and Holtec Contract. But the underlying premise of TURN’s argument is that the

contingency should be removed because the DGC Agreement and Holtec Contract are fixed-

price contracts.36 TURN reasons that the contingency is unnecessary due to the “all-

encompassing scope and fixed price associated with these contracts.”37 The Commission should

reject this argument for several reasons discussed below.

a) TURN Fails To Understand That The Scope Of Work May Need To

Change, Resulting In Cost Increases That Will Be The Utilities’

Responsibility

TURN misses the point of the contingency included in the DCE for the

DGC Agreement and Holtec Contract, by either ignoring or failing to understand that the scope

of work may need to be changed, resulting in additional costs that will be the Utilities’

responsibility. The DGC Agreement and Holtec Contract scopes are not “all-encompassing” as

described by TURN.

For the DGC Agreement, for example, the Utilities must include

contingency in the DCE for cost changes resulting from changed circumstances or scope changes

not addressed in the original scope of DGC Agreement that may emerge as the decontamination

and dismantling (D&D) effort unfolds. Site conditions (including radiological contamination

levels) may not be as originally assumed, requiring additional work, with the Utilities potentially

36 TURN Opening Brief, pp. 7-9. 37 Id., p. 6.

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responsible for the cost increases. In addition, situations such as new regulatory requirements,

litigation, etc., may require changes in decommissioning plans or scope. These changes may

involve cost increases that must be paid by the Utilities under the DGC Agreement. Stated

another way, the scope of the DGC Agreement may need to be changed due to a variety of

circumstances, and therefore the cost may need to be adjusted. Indeed, the DGC Agreement

identifies several circumstances that could require a change order to be paid by the Utilities.38

The 20% contingency included in the 2017 SONGS 2&3 DCE for the DGC Agreement is

precisely for this purpose. The same reasoning holds equally true for contingency in the DCE

for the Holtec Contract, albeit the 15% contingency is at an appropriate lower amount given that

the ISFSI project is further along and nearing completion.

In addition, TURN ignores widely-accepted cost-estimating principles,

including those endorsed by its own witness, Mr. Bruce Lacy, in the Independent Panel Report

he co-sponsored in the 2009 NDCTP.39 The report stated that “every estimate involving future

activities must consider risk” in the adoption of an appropriate contingency.40 The report

specifically noted that “[c]osts for contingency is added to estimates in preparation for undefined

future events within scope of a project or specific endeavor but not yet part of the negotiated

contract.”41 This is what the 2017 SONGS 2&3 DCE plainly does. In shorthand, contingency is

added to the DCE for undefined future events that are not yet part of the negotiated DGC

Agreement and Holtec Contract.

There are several examples of changed circumstances or conditions not

within the scope of the DGC Agreement and ISFSI Contract that could be subject to

contingency, including:

38 See DGC Agreement, Article VI, Section 6.3(a). 39 Exhibit TURN-20, pp. 40-42; D.11-07-003 (adopting the Independent Panel’s recommendations). 40 Exhibit TURN-20., p. 40. 41 Id., p. 41.

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California Coastal Commission (CCC) coastal development permit (CDP)

mitigation requirements

More stringent radiological release criteria adopted by NRC

Enhanced security requirements from NRC

Changed waste disposal requirements by NRC, federal, or state government

External events such as coronavirus (COVID-19)

The Utilities must include a reasonable contingency in the SONGS 2&3 DCE for the DGC

Agreement and Holtec Contract to account for scope risks that are not covered within those

contracts, but that could materially impact the SONGS decommissioning project scope and costs.

It would be imprudent to remove the contingency on the assumption that the risks and costs will

not arise.

b) Contractor-Included Contingency Generally Covers The Contractors’

Performance Risk, But Does Not Cover The Utilities’ Scope And

Regulatory Risks

TURN further argues that the DGC Agreement and Holtec Contract

include embedded contingency added by the contractors in their bid to cover various

performance risks assigned to the contractors.42 While the Utilities agree that contractors’ bids

may include contingency to cover their performance risk,43 TURN is incorrect that the

contingency covers all risks. The contractor-included contingency does not cover the Utilities’

risks.44

42 TURN Opening Brief, pp. 9-10. 43 Exhibit SCE-15, pp. 6-7; Exhibit SDGE-09, p. 7. 44 Exhibit SCE-15, p. 6; Exhibit SDGE-09, p. 7.

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As discussed in the Independent Panel Report, four types of risks warrant

the inclusion of contingency within an estimate: (1) performance risk, (2) scope risk,

(3) regulatory risk, and (4) financial risk.45 For the DGC Agreement and Holtec Contract, the

fixed price/fixed scope addresses performance and financial risks, by generally putting those

risks on the contractors. But the fixed price/fixed scope does not address certain scope and

regulatory risks such as unknown site conditions, new regulatory requirements, litigation, etc.,

that may require additional changes in the plans or scope. TURN actually admits this point in its

opening brief: “To the extent that any risks associated with the DGC contract merit contingency,

they involve scope changes.”46 The contingency for the DGC Agreement and Holtec Contract

included in the 2017 SONGS 2&3 DCE addresses this risk. Based on TURN’s own admission,

the Commission should determine that the contingency included in the DCE for these contracts is

reasonable.

c) Unexpected Conditions May Lead To Scope Changes Beyond The

Agreed-Upon Contract Scope

TURN cites cross-examination testimony provided by SDG&E witness,

Mr. Adam Levin, to support its assertion that contractor-included contingency covers unexpected

scope changes during a project. But TURN misinterprets Mr. Levin’s testimony,47 which only

stated that it was his “expectation” that a contractor would complete additional work resulting

from minor unexpected changes.48

45 TURN Exhibit 20, p. 40. 46 TURN Opening Brief, p. 15. 47 TURN also misses the point of Mr. Levin’s rebuttal testimony regarding “optimal performance” and

contingency. Mr. Levin did not say that contingency is needed for suboptimal contractor performance. He confirmed that would be the contractor’s risk. Tr. Vol. 3 (Levin), p. 326, line 26 to p. 327, line 3. Rather, Mr. Levin stated that contingency is needed to cover “unknown, but expected to occur, costs,” including contract amendments that may arise.

48 Tr. Vol. 3 (Levin), p. 332, lines 16-25.

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TURN ignores Mr. Levin’s rebuttal testimony, which clarified that

contractor-included contingency is “solely applicable to the scope of work agreed to by SCE and

the vendor” – that is, the agreed-upon contract scope, not “potentially-emergent work” outside

the contract scope.49 Mr. Levin also emphasized that he was referring to the contractor’s

performance risk and not to the Utilities’ scope and regulatory risks.50 TURN also ignores

SCE’s testimony, which further explained that any contractor-included contingency does not

cover the Utilities’ risk for scope changes.51

In addition, TURN overlooks an important nuance in Mr. Levin’s

testimony. Mr. Levin was only referring to minor unexpected changes – that is, “a little bit

more” work that would not materially change the contractors’ obligations and costs.52 He was

not referring to material unexpected changes or force majeure events that could cause a

contractor to seek payment for completing additional work not contemplated under the contract.

A recent decision from the 6th Circuit on a decommissioning project

underscores this point. Eagle Supply and Mfg., L.P. v. Bechtel Jacobs Co., LLC, 868 F.3d 423

(6th Cir. 2017) concerned a dispute over decommissioning of the Manhattan Project site in Oak

Ridge, Tennessee. The United States Department of Energy (DOE) retained Bechtel Jacobs as

the general contractor, who then subsequently entered into a subcontract with Eagle Supply to

perform part of the work. A dispute arose between Bechtel Jacobs and Eagle Supply when more

contaminated soil than expected was encountered by Eagle Supply, increasing Eagle Supply’s

costs to complete the work. When Eagle Supply sought recovery of the costs in litigation,

Bechtel Jacobs asserted that Eagle Supply failed to provide timely notice of the differing site

conditions as required in the contract. However, the trial court rejected the defense and awarded

49 Exhibit SDGE-09, p. 7. 50 Tr. Vol. 3 (Levin), p. 334, lines 15-16. 51 Exhibit SCE-15, p. 7. 52 Tr. Vol. 3 (Levin), p. 333, lines 16-18.

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Eagle Supply additional compensation, concluding that Bechtel Jacobs had not shown that it had

been prejudiced by Eagle Supply’s failure to provide timely notice. The Sixth Circuit upheld the

damages award.

The point to be drawn here is that although the Utilities certainly will seek

to enforce the DGC Agreement’s and Holtec Contract’s pricing terms, it should not be

overlooked that courts and arbitration tribunals often decide to compensate a contractor for

significant additional work and costs resulting from material unexpected conditions,

notwithstanding clear contract language that may suggest otherwise.53 The contingency in the

2017 SONGS 2&3 DCE for the DGC Agreement and Holtec Contract accounts, in part, for this

litigation-related scope risk.54 The Commission should determine that the contingency is

reasonable for this purpose.

d) The Contingency Factors Included For The DGC Agreement And

Holtec Contract Are Reasonable

TURN also asserts that the contingency factors included in the 2017 DCE

for the DGC Agreement and Holtec Contract are unreasonable because SCE claimed to but did

not apply objective criteria when determining them. In support, TURN resorts to ad hominem

arguments calling SCE’s contingency evaluation a “mirage” and “biased,”55 and suggesting that

SCE inflated the contingency “to ensure that estimated costs are equivalent to the projected trust

53 Quantum meruit is an equitable remedy that courts apply frequently when there is no written contract to perform the work or extra work was performed. It is an equitable theory “that a contract to pay for services rendered is implied by law for reasons of justice.” . A claim for quantum meruit is proven if the moving party demonstrates a) it performed services for the defendant; b) the reasonable value of those services; c) the services were rendered at the request of the defendants; and d) the services are unpaid. Patterson Builders v. Hsu, No. B286315, Cal. App. 2019 WL 5558259 at *3 (Cal. App. 2nd Div. Oct. 29, 2019)

54 Exhibit SCE-15, p. 7. 55 TURN Opening Brief, pp. 11-12.

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fund balance.”56 TURN’s empty rhetoric and baseless arguments (utter nonsense) have

absolutely no basis in the record, and the Commission should reject them the following reasons.

(1) SCE Utilized Objective Criteria To Determine Contingency

SCE identified in its testimony the specific objective criteria used

to determine contingency. SCE explained that the criteria included consideration of the technical

complexity, contracting status, estimating approach, and timing of each work scope.57 This

objective criteria resulted in SCE’s cost-estimating experts’ determining a range of different

contingency factors (10%, 15%, 20%, or 25%) for the cost categories included in the 2017

SONGS 2&3 DCE.58 SCE further explained that for work scope that has been contracted (the

DGC Agreement and Holtec Contract), SCE applied lower contingency factors than applied in

prior DCEs.59 Contrary to TURN’s characterization otherwise, SCE’s contingency evaluations

were very much tethered to objective criteria that resulted in lower contingencies in many

instances.60

TURN’s opening brief acknowledges the lower contingencies for

other cost categories in the DCE: (1) 10% for Service Level Agreements (SLA) and

Undistributed Labor; (2) 15% for Undistributed Non-Labor and ISFSI/Fuel Transfer Operations

(FTO).61 But it is evident that TURN does not understand the objective criteria used to

56 Id. 57 Exhibit SCE-03C, p. 7. 58 Exhibit SCE-03C, p. 8, Table II-1. 59 Id. 60 TURN suggests that SCE’s Vice President’s role in approving the DCE negated SCE’s use of

objective criteria. TURN Opening Brief, p. 12. But there is no evidence that any contingency values were changed because of his direction. No changes were made. As Mr. Jose Perez testified, the contingency was determined by SCE’s professional staff and consultants. Tr. Vol. 3 (Perez), p. 295, lines 17-27. The DCE ultimately is approved by SCE’s Vice President. Tr. Vol. 3 (Perez), p. 296, lines 21-27.

61 TURN Opening Brief, p. 12.

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determine the contingencies when TURN says it is “inexplicable” that the DCE applies a greater

contingency percentage for the fixed-price DGC Agreement than these other categories.62 The

lower contingencies for these categories make perfect sense. SCE had more experience (at least

three to four years) with these cost categories at the time the 2017 DCE was prepared. On the

other hand, the DGC Agreement was new and major decommissioning activities had not yet

commenced. Given these facts, a slightly higher 20% contingency on the DGC Agreement is

justified and reasonable. The 20% contingency is accounting for potential changes in the scope

of work not covered by the DGC Agreement.

TURN conflates an Independent Panel Report recommendation

that actual data be reviewed to “remove embedded contingency and preclude unnecessary

contingency” to argue that the 2017 DCE does not account for and remove any embedded

contingency included in the DGC Agreement and Holtec Contract.63 TURN does not understand

that the recommendation does not apply here. Any embedded contingency included by the

contractors in these contracts is part of the contract price. It therefore cannot be removed.

Further, as noted above, the contractor-included contingency does not cover the Utilities’ risks.

The Utilities must add contingency to account for their scope and regulatory risks, which are not

covered under the DGC Agreement and Holtec Contract.

(2) An Independent, Third-Party Expert Validated The

Contingency

It is also important to recognize that the objective criteria used to

determine contingency (i.e., the technical complexity, contracting status, estimating approach,

and timing of each work scope) and SCE’s final contingency evaluations were validated by a

62 Id. 63 TURN Opening Brief, p. 13.

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third-party independent cost-estimating expert, a fact TURN not-so coincidentally ignores.

ABZ’s managing director, Mr. Nicholas Capik, specifically reviewed the contingency included

in the 2017 DCE, the basis used to allocate contingency, the change in contingency from

previous DCEs, and the basis for such changes.64 He concluded that the “contingency is

reasonable for the current project state.”65 This includes the contingency included for the DGC

Agreement and Holtec Contract.

(3) TURN’s Ad Hominem Attacks Are Demonstrably False

In addition, TURN’s ad hominem allegations of “bias”66 and

“inflated contingency”67 are baseless, and contrary to observable facts. The 2014 SONGS 2&3

DCE included a 25% contingency on all decommissioning activities.68 In comparison, the 2017

SONGS 2&3 DCE lowered the contingency for several categories of work, including near-term

work that was well-defined and work under contract.69 Indeed, a lower 10%, 15%, and 20%

contingency was applied to well over half of the costs in the 2017 DCE. This is hardly evidence

of “bias” or an “inflated contingency.” It is the opposite.

TURN also ignores that the 2017 SONGS 2&3 DCE’s composite

contingency factor is almost 10% lower than the 25% contingency included in the 2012 and 2014

SONGS 2&3 DCEs.70 Instead, TURN advances a misleading argument regarding a so-called

“effective contingency.” TURN argues that the DGC included a 17-22% contingency in its

contract bid and that, under SCE’s approach in the DCE, the “effective contingency for the DGC

64 Exhibit SCE-03C, p. 11. 65 Id., p. 12. 66 Id. 67 Id. 68 Exhibit SCE-03C, p. 7. 69 Exhibit SCE-03C, p. 7. 70 Exhibit SCE-03C, p. 8.

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contract [is] 37-42%.”71 This argument is speculative and specious. TURN is in no position to

try to calculate an “effective contingency.” Indeed, no party except the DGC knows what

contingency the DGC included in its bid. Moreover, due to the competitive bidding process used

to select the DGC, the actual amount of contractor-included contingency may in fact be much

lower than TURN assumes. What is more, as discussed in detail above, the contractor-included

contingency only covers the DGC’s performance risk and does not cover the Utilities’ risk for

scope changes and cost increases not covered in the DGC Agreement, including those caused by

unknown site conditions, new regulatory requirements, litigation, etc.

(4) The DCE Contents And Prior DCEs Show That The Utilities

Do Not Manipulate The DCEs

Finally, the Utilities did not manipulate any aspect of the 2017

DCE to “ensure that estimated costs are equivalent to the projected trust fund balances,” as

alleged by TURN.72 The attack is grossly offensive to the professional integrity and ethics of the

Utilities’ staff and consultants who are charged with comprehensively and accurately preparing

and reviewing the DCEs and supporting materials submitted in the NDCTP. TURN’s allegation

is plainly untrue. As noted above, the Utilities applied lower contingency factors than included

in prior DCEs.73 The 2017 SONGS 2&3 DCE total (bottom line amount) is less than projected

71 TURN Opening Brief, p. 14. 72 TURN Opening Brief, p. 12. TURN also argues that the Utilities seek to establish “the highest

possible cost benchmarks for [] future reasonableness review[s]” so that when recorded costs underrun the benchmark, the negative variance demonstrates good performance. TURN Opening Brief, pp. 5-6. TURN ignores that the Commission has declined to adopt a reasonableness presumption solely because recorded costs for an activity are less than estimated in the DCE. The Commission has made clear that the Utilities must justify the reasonableness of all decommissioning costs. D.18-11-034, pp. 22, 54, 67, and Conclusion of Law No. 26. In addition, the implicit solution to address TURN’s purported concern is to adopt a lowball DCE or no DCE, which would not make sense. The Commission should adopt a DCE reflecting all reasonably known costs and potential cost risks in order to confirm NDT sufficiency, not adopt a deflated DCE distorting that review.

73 Exhibits SCE-3 and SCE-3C, p. 7.

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trust fund balances, which is why the Utilities have requested zero customer contributions.

There were no attempts to manipulate inflated DCEs to match trust fund balances.

e) TURN’s Alternative Contingency Recommendation Is Faulty

TURN hedges its zero-contingency recommendation with an alternative

that the Commission reduce the contingency for the DGC Agreement and Holtec Contract.74 But

the alternative contingency amount proposed by TURN is based on a faulty calculation and is

untethered to any credible cost-estimating analysis.75 TURN suggests that the contingency

amount included for the Holtec Contract be divided by the total project costs to date (including

recorded costs), yielding a contingency of 5.6%.76 TURN then proposes using 5.6% as the

contingency for the DGC Agreement, and arbitrarily cuts this figure in half to derive a proposed

contingency of 2.8% for the Holtec Contract.77 TURN hedges further in its opening brief,

upping the proposed contingency to 3-8% for the DGC Agreement.78

This approach is nonsensical. As a threshold matter, the underlying

calculation using total project costs is flawed, as this would suggest SCE needs contingency

amounts for portions of the project that are already completed.79 In addition, TURN applies an

incorrectly derived contingency calculation for one project already underway and then applies it

to a completely unrelated project not even started at the time the DCE was prepared – an apples-

to-oranges exercise. TURN fails to explain how its defective Holtec-contingency calculation

should apply to the DGC Agreement; nor does TURN explain why it should be reduced in half

74 TURN Opening Brief, p. 14; Exhibit TURN-17C, pp. 15-16. 75 Exhibit SCE-15, p. 8. In fact, TURN does not identify any industry cost-estimating guidance to

support either its zero-contingency recommendation or alternative. 76 TURN Opening Brief, p. 14; Exhibit TURN-17C, pp. 14. 77 TURN Opening Brief, p. 14; Exhibit TURN-17C, p. 16. 78 TURN Opening Brief, p. 14. 79 Exhibit SCE-15, p. 8.

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for the Holtec Contract. It is not appropriate to assess contingency in this way. Rather, the

appropriate way to determine contingency is to do what the Utilities did in the 2017 SONGS 1

and SONGS 2&3 DCEs, when they considered the technical complexity, contracting status,

estimating approach, and timing of each work scope to determine the appropriate contingency to

be applied to various cost categories.80

The Commission Should Reject TURN’s Recommendations To Remove

$104.1 Million From The DCE Associated With SCE’s Extension Of The

DGC Schedule

The 2017 SONGS 2&3 DCE provides a 10-year D&D performance period from

2019 through 2028.81 The DGC Agreement, signed in December 2016, provides an

approximately 7.5-year D&D performance period from 2018 through mid-2025.82 Noting the

schedule difference of 2.5 years, TURN recommends that the Commission adopt the shorter

DGC Agreement schedule and remove $104.1 million of associated undistributed costs

(primarily 2.5 years of SCE Labor costs) from the 2017 DCE.83 The primary basis for TURN’s

recommendation is that SCE is supposedly ignoring the following Commission guidance: “We

expect SCE to incorporate DGC contract milestones into the 2018 DCE, and we will carefully

consider whether SCE’s contractual expectations from its DGC are aligned with schedule and

costs estimates presented in the proposed DCE in the 2018 NDCTP.”84 TURN interprets the

guidance as though it were an absolute requirement for the DCE to reflect the DGC’s 7.5-year

schedule. It is not, and the Commission should reject this recommendation.

80 Exhibit SCE-03C, p. 7. 81 Exhibit SCE-15, p. 11. 82 Id. 83 TURN Opening Brief, p. 1. 84 Id., p. 18.

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The Commission’s guidance should not be construed as requiring the Utilities to

blindly incorporate the DGC Agreement’s schedule into the DCE without deliberate

consideration as to whether doing so makes sense. The 7.5-year schedule in the DGC

Agreement reflects the DGC’s most-optimistic work plan.85 It is reasonable for SCE to have

agreed to this schedule in the DGC Agreement, because if achieved, it will provide customer

benefits. To present a reasonable DCE, however, the Utilities believe it is prudent to adjust the

D&D schedule to 10 years based on industry experience in prior decommissioning projects.86 As

SCE explained in testimony, prior DCEs assumed that reactor vessel internals (RVI)

segmentation, a critical path decommissioning activity, would be performed in series (one unit

after the other) over a period of approximately 3 years.87 In contrast, the DGC Agreement

schedule assumes that RVI segmentation will be performed in parallel (both units concurrently)

over a period of 1.3 years, which has never been successfully completed within the industry.88

RVI segmentation will be an extremely complex and challenging undertaking.89 For this reason

among others, the Utilities retained its 10-year schedule in the 2017 SONGS 2&3 DCE.90 A 10-

year schedule is reasonable91 and indeed shorter than those adopted in prior SONGS 2&3

DCEs.92

85 Exhibit SCE-15, p. 11 86 Id. 87 Id. 88 Id. 89 Id. 90 Id. The 10-year schedule also provides sufficient time for other challenging activities, including

completing additional remediation activities; segregating, handling, and packaging concrete rubble; and closing out the project. Exhibit SCE-03C, p. B-57.

91 A reasonableness finding is also supported by ABZ’s independent review. Exhibit SCE-03C, p. 11 (“ABZ reviewed the schedule for decommissioning activities, identified critical path activities, and ability to manage delays in performance of major activities. ABZ compared this schedule to previous SONGS schedules and evaluated the proposed activity lengths to relative to recent decommissioning projects. ABZ concluded that the schedule allowed adequate time to complete required activities.”).

92 Id.

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In addition, TURN’s recommendation to remove 2.5 years of undistributed costs

from the DCE is out of scope for this NDCTP.93 By seeking to remove the costs associated with

the longer 10-year schedule, TURN essentially is arguing that any schedule extensions deviating

from the DGC’s 7.5 year schedule are unreasonable.94 It is premature to deem costs associated

with potential schedule delays as unreasonable. The Utilities should have the opportunity to

demonstrate the reasonableness of its schedule and costs in a future NDCTP.

For these reasons, the Commission should approve the schedule presented in the

DCE and allow the $104.1 million (100% share, 2014 $) of associated undistributed costs.

The Commission Should Reject TURN’s Recommendations To Eliminate

$13.8 Million For Notice To Proceed Delay

The DGC Agreement included a potential cost of $13.8 million (100% share,

2014 $) in the event SCE was unable to obtain a coastal development permit (CDP) from the

CCC and issue SDS a Notice to Proceed (NTP) with decommissioning activities by January

2018.95 While completing the 2017 DCE, SCE was aware that it would not obtain the CDP by

this date and would need to make this payment to SDS to support their on-site activities during

the additional time needed for environmental reviews.96 Therefore, the 2017 SONGS 2&3 DCE

included the $13.8 million of NTP delay costs. It would have been imprudent for SCE to

exclude the costs from the DCE given that it was evident additional time would be needed and

costs incurred. The Commission should allow the costs to be included in the DCE, because they

are known, incurred costs.

93 Exhibit SDGE-09, pp. 5-6. 94 Id. 95 See DGC Agreement Exhibit X. 96 Amendment 8, Delay of NTP Phase II, was executed on December 13, 2017.

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TURN, however, argues that SCE was imprudent and the NTP delay costs should

be removed because the costs were “a direct result of SCE’s failure to timely recognize the need

for a CDP for the DGC to commence Phase II work.”97 As an initial matter, TURN is incorrect

that SCE failed to timely recognize the need for a CDP. That assertion is not supported by any

evidence, and TURN does not cite any. Indeed, the regulatory record at the CSLC and CCC

demonstrates that SCE has actively pursued several SONGS-related exemption requests,

environmental reviews, and permits with these agencies since SCE announced the SONGS

shutdown in June 2013.98 This record further reflects that SCE has appropriately prioritized the

timing of these reviews and permits in coordination with the CSLC and CCC. SCE has explained

this record to TURN and is unsure why TURN persists in repeating this mistruth. The fact that

TURN continues to present this argument without any record evidence is both troubling and

telling. If its assertion was true, TURN would cite to evidence.

In addition, the delays should not be attributed to imprudence by the Utilities.

These agencies have limited resources, must meet various statutory requirements, and must

balance various environmental issues and other applications. SCE does not have the ability to

control the timing of agencies’ processes or decisions on decommissioning issues, which are

obviously of great interest to many stakeholders. The Independent Panel Report that Mr. Lacy

co-authored in the 2009 NDCTP recognized this reality, noting that there are challenges in

97 TURN Opening Brief, p. 20. 98 The CSLC and CCC maintain information regarding SONGS activities on their website at

https://www.slc.ca.gov/ and https://www.coastal.ca.gov/ (search for SONGS or SONGS decommissioning on the website). These activities, among other things, include their review of the SONGS 2&3 Offshore Large Organism Exclusion Device Installation Project; Disposition of Offshore Cooling Water Conduits for SONGS 1; SONGS ISFSI Expansion Project; and the SONGS 2&3 Decommissioning Project.

29

forecasting what state authorities may impose in connection with decommissioning.99 TURN

now asks the Commission to overlook the prior statement of its witness.

By recommending the removal of NTP delay costs from the 2017 DCE, despite

the fact that they are known, incurred costs, TURN essentially argues that the costs should be

deemed unreasonable prior to the reasonableness review of recorded costs.100 But it is premature

to deem the costs as unreasonable in this phase of the NDCTP, which is reviewing the DCE, not

recorded costs. When reviewing the DCE, the Commission should assess the obligation to

perform each decommissioning activity and the estimated cost of the activity. Whether an

activity was itself reasonable for the Utilities to undertake should be addressed when the

recorded costs are reviewed for reasonableness. Here, the DCE appropriately included costs the

Utilities were obligated to pay under the DGC Agreement. The Utilities should have the

opportunity to demonstrate the reasonableness of the recorded costs, including those associated

with delay payments, in a future NDCTP consistent with the approved Milestone Framework.

For these reasons, the Commission should reject TURN’s recommendation to

remove $13.8 million of NTP delay costs from the 2017 SONGS 2&3 DCE.

99 A.09-04-009, March 1, 2011 Filing by Southern California Edison Company of Independent Panel Report, Attachment A, p. 6 (Nicholas Capik, Geoffrey Griffiths, and Bruce Lacy, Report on Nuclear Decommissioning, dated February 28, 2011).

100 TURN seeks to use the DCE as a sword to argue imprudence. TURN argues that NTP delay costs should be removed from the DCE because the delay was caused by the Utilities’ imprudence. TURN says the Utilities can still incur the costs and submit them for reasonableness review. But TURN would have the opportunity to use an adopted DCE reduction to argue that the costs have already been deemed imprudent, given that the proffered basis for the reduction was imprudence .

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The Commission Should Reject TURN’s Recommendations To Eliminate

$38.2 Million For Additional Remediation Costs

TURN recommends the removal of $38.2 million for additional remediation costs

included in the 2017 SONGS 2&3 DCE.101 According to TURN, the costs: (1) were not

identified or explained until SCE submitted rebuttal testimony and (2) are speculative and

another form of contingency that should be removed.102 TURN further claims that SCE did not

compare the 2017 DCE with the two most-recent approved DCEs to allow an understanding of

the remediation costs as required by D.18-11-034.103 TURN is wrong on all counts, and its

inaccurate assertions on this issue are puzzling given that the information regarding this activity

and costs have been available to TURN for two years.

First, SCE identified the additional remediation costs and provided the required

comparison (variance explanation) in Exhibit SCE-03C, submitted two years ago in March 2018

when SCE filed A.18-03-009.104 SCE compared the 2014 and 2017 SONGS 2&3 DCEs, and

explained the increase in estimated costs for Decontamination, Demolition, and Dismantling

activities (DGC Agreement) in the 2017 DCE was due to activities necessary for “additional

radiological decontamination to achieve a lower release criteria and the costs to procure

acceptable backfill material.”105 The 2014 SONGS 2&3 DCE assumed a 25 mrem release

criteria and the 2017 SONGS 2&3 DCE assumed a lower release criteria.106 The additional

remediation is necessary to achieve this lower criteria. SCE pointed out that the increased costs

101 TURN Opening Brief, p. 21. 102 TURN Opening Brief, pp. 21-22. 103 TURN Opening Brief, p. 22. 104 Exhibit SCE-03C, pp. 20-21. Exhibit SCE-12C also compared the 2017 SONGS 2&3 DCE to the

2012 and 2014 SONGS 2&3 DCEs. 105 Exhibit SCE-03C, pp. 20-21. 106 Exhibit SCE-03C, p. 21, fn 31.

31

for additional remediation was more than offset by a decrease in undistributed DGC staffing

costs.107

Perhaps TURN simply missed this testimony through error. But contrary to its

assertion that it was not until SCE’s 2020 rebuttal testimony that the additional remediation costs

were identified, the testimony explaining these costs and providing the required DCE

comparison was in fact available – two years ago.

Second, TURN is wrong that the additional remediation costs are speculative and

another form of contingency. The 2017 SONGS 2&3 DCE assumes a lower radiological release

criteria than utilized in the DGC Agreement.108 Without the additional remediation assumed in

the DCE, the remaining subgrade structures could contain some level of contamination,

preventing the material from being disposed at a clean waste facility during Phase III.109 This

conclusion is based on engineering judgment, not speculation. Therefore, SCE included costs for

the additional remediation (removal and disposal of contaminated material) plus backfill

necessary to achieve the DCE’s assumption that all remaining subgrade structures will be

disposed of at a clean waste facility. Of this amount, $38.2 million relates solely to the

additional remediation activities (without backfill and contingency). The activities are required

to decommission SONGS 2&3 to an “as clean as practical” criteria, as assumed in the 2017

DCE. For this reason, the Commission should not remove the additional remediation costs from

the DCE. The costs are for decontamination activities reasonably within the scope of

decommissioning.

107 Id. 108 Exhibit SCE-03C, p. 21, fn. 31. 109 Exhibit SCE-15, p. 14.

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IV.

MILESTONE FRAMEWORK

The Utilities developed a proposed amendment to the Milestone Framework regarding

the review of SONGS 2&3 waste-disposal costs in the NDCTP. As explained in Exhibit SCE-

SDGE-01, the Utilities’ proposed amendment will result in better clarity of the project costs and

performance, and avoid creating false, misleading variances that will hinder the Commission’s

reasonableness reviews of distributed activities.110 The approach also maintains the principle

that reasonableness reviews of waste-related costs should not occur without project

performance.111 In testimony, TURN recommended that parties should renew discussions

regarding the proposed amendment.112 But in its opening brief, TURN has changed course and

now states that it does not oppose the proposed amendment.113 No other intervenor objected to

the proposed amendment. For these reasons, the Commission should approve the proposed

amendment to the Milestone Framework as proposed in Exhibit SCE-SDGE-01.114

In its opening brief, TURN makes two additional recommendations that the Commission

should: (1) clarify that the Utilities will be obligated to justify their decision to pursue a “strategy

of full payment for partial performance;” and (2) require SCE to report in each NDCTP on the

progress of waste removal relative to the total expected amounts of waste associated with the

project.115 The Utilities disagree with TURN’s characterization of the Utilities’ strategy. TURN

does not acknowledge the cash flow requirements for a project of this length and magnitude. It

110 Id., p. 5. 111 Id. 112 Exhibit TURN-17C, p. 3. 113 TURN Opening Brief, p. 27. 114 D.18-11-034, Appendix 1 (SONGS Decommissioning Reasonableness Framework) provides in

Section III(f) that the Milestone Framework should be flexible to allow for the addition of new activities and that any changes to the Milestone Framework are subject to the Commission’s review and approval.

115 TURN Opening Brief, p. 27.

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is unreasonable to expect any contractor to complete a decade-long decommissioning project for

a 2,250 MW two-unit power plant and wait until the end of the project to receive the bulk of the

payment, as implicitly suggested by TURN. It is necessary for the Utilities to provide milestone

payments as key work activities are completed. This reasonable milestone-payment approach is

consistent with industry practices and makes sense. Nevertheless, the Utilities understand their

obligations to justify their decisions during NDCTP reasonableness reviews and will do so for

waste-related costs, in accordance with the Milestone Framework. The Utilities do not object to

providing progress on waste-removal activities, but the Utilities should provide the updates in the

fall and spring advice letters, not in the NDCTP. The Utilities’ advice letters already provide

updates on in-progress project activities. The NDCTP should focus on reviewing the Utilities’

DCE updates and recorded costs.

V.

DOE LITIGATION PROCEEDS

A. The Commission Should Continue To Review SCE’s DOE Litigation Efforts In

SCE’s ERRA Proceeding

TURN recommends that the reasonableness review of DOE litigation should be moved

from ERRA to the NDCTP.116 The Commission should reject this for two reasons.

First, the adoption of this recommendation would harm customers by substantially

delaying the processing of customer refunds for damages awards received from the DOE. SCE

submits the damages awards for review in ERRA, which is an annual proceeding. It is

reasonable to conclude that an annual proceeding will provide an opportunity to process the

refunds more quickly once received, as opposed to deferring review to the next occurring

116 TURN Exhibit 17, p. 31.

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NDCTP.117 Second, SCE is concerned that the proposal would further burden the NDCTP with

an extraneous issue that could exacerbate delays. TURN is dismissive of this issue, but recent

NDCTPs have taken 2-3 years to litigate to a final decision. Given the amount of time it already

takes to litigate NDCTPs, the NDCTP should not be burdened with an additional review of

SCE’s litigation against the DOE.

TURN also implies that PG&E is able to refund DOE damages awards faster than SCE

because PG&E submits DOE damages awards for Commission review in the NDCTP.118 This is

misleading. In fact, PG&E was able to refund DOE damages awards on an annual basis because

PG&E reached a settlement with DOE in 2012 that provided for the payment of annual damages

awards. This result had nothing to do with type of proceeding in which PG&E submitted the

awards for Commission review. An annual DOE settlement is not available for SCE at this time.

Even if this approach was available, it only addresses the first problem identified by SCE (i.e.,

timing), but does not address the overburdening of the NDCTP.

TURN’s justification for moving the review of SCE’s DOE litigation from ERRA to the

NDCTP is that there has been a supposed “drop-off in recovery rates” in recent claims, and the

Commission should therefore apply greater scrutiny to litigation.119 But TURN does not explain

why this greater scrutiny cannot (or should not) occur in ERRA. Indeed, annual scrutiny in

ERRA should be better than triennial scrutiny in the NDCTP under TURN’s logic. In addition,

there is nothing preventing TURN from intervening in the ERRA to obtain more information

regarding SCE’s litigation efforts. Had TURN done so, SCE would have explained that the

supposed “drop-off in recovery rates” for the recent 2014-2016 claims was, in part, due to the

fact that under an agreed-upon settlement, the DOE was paying damages awards much sooner

117 SCE has been using this process since 2012 when it submitted the 1998-2005 damages award for review in A.12-04-001.

118 TURN Opening Brief, p. 30. 119 TURN Opening Brief, p. 28.

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than they otherwise would have paid if SCE had been required to litigate the claims through

appeals (a period of 3 to 5 years). Due to the time-value of money (interest is not available in

litigation against the government), it made sense for SCE to agree to a settlement process

providing immediate, discounted payment of damages as opposed to waiting additional years.

This benefitted SCE customers, who ultimately received the damage awards via refunds

processed through ERRA.

B. The Reporting Of Damages Claims To Line Items Within The DCE Would Serve

No Beneficial Purpose

TURN also recommends that the Commission require SCE to track all DOE damages

claims to line items within the DCE.120 The Commission should reject this recommendation

because it would provide no beneficial purpose.

The proffered reason for SCE to provide information in this suggested format is that it

would facilitate a reasonableness review of the damages claims.121 But it is important to

recognize that spent fuel management costs are already tracked by DCE line item and subject to

review for reasonableness in the NDCTP. Any Commission review of the damages awards SCE

obtains should not result in a second reasonableness review of the underlying SNF costs,

rendering it unnecessary for SCE to report the damages by DCE line item.

In addition, the review of DOE damages claims and awards has nothing to do with how

costs are categorized by DCE line items.122 For this reason, TURN’s recommended format for

reporting the awards would not facilitate reasonableness reviews of SCE’s litigation against the

DOE. TURN conflates spent nuclear fuel (SNF) management costs in the DCE with costs that

120 TURN Opening Brief, p. 31. 121 Id. 122 Exhibit SCE-15, p. 27.

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may be claimable, let alone recoverable, from the DOE.123 Indeed, there are several large

categories of SNF costs in the DCE that are not claimable against the government.124 For

example, fuel characterization costs are identified in the DCE as SNF costs.125 But these costs

are not claimable as damages against the DOE because SCE would have incurred these costs

even if the government had timely performed its contractual obligations.126 In short, there is not

a line-to-line correspondence between DCE spent fuel management costs and DOE damages

awards. Therefore, the recommended format for reporting DOE damages awards would not

serve a beneficial purpose. The only purpose it would serve is data-dumping, which benefits no

one.

When the Commission reviews the reasonableness of SCE’s DOE litigation efforts, the

review should examine the entirety of the litigation and damages recovery, not individual

components of the claim tied to DCE line items. Completing a review in this manner is

consistent with how the Commission reviews other litigation activities. The Commission, for

example, typically does not review individual causes of action or delve into the line-by-line

specifics of a claim for reasonableness. The Commission need not (and should not) do so here.

C. SCE Has Explained The DOE Pick-Up Strategy Assumed In The DCE

In the 2017 SONGS 2&3 DCE, SCE assumed that in 2028 the DOE would begin

performing its contractual obligations to pick-up SNF from commercial reactor sites

nationally.127 SCE further assumed that the DOE would first pick-up SONGS 1 and

SONGS 2&3 SNF from the on-site ISFSI followed by the pick-up of SONGS 1 SNF from

123 Id. 124 Id. 125 Id. 126 Id. 127 Exhibit SCE-03C, p. B-55.

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General Electric’s (GE) storage facility in Morris, Illinois. This sequence departed from prior

DCEs that had assumed the SONGS 1 SNF stored at the GE Morris facility would be picked up

first.

In its opening brief, TURN recommends that SCE should explain the basis for this

strategy.128 TURN argues that this approach will increase total spent fuel management costs

because GE Morris storage costs are more than double the SONGS ISFSI costs over the same

period of time.129 TURN also suggests that the strategy could jeopardize the recovery of these

costs from the DOE.130

TURN ignores that SCE has already explained that SCE is seeking to remove the SNF

stored at SONGS first in order to recognize a broad range of stakeholders who have advocated

removing the fuel offsite from SONGS as rapidly as possible. In addition, TURN ignores that the

resequencing does not increase the 2017 SONGS 1 and SONGS 2&3 DCEs in comparison to

prior DCEs, albeit it does increase the GE Morris costs that are recovered in SCE’s ERRA.

TURN also is incorrect that the re-sequencing of the pick-up of fuel from SNF could

jeopardize SCE’s claims against the DOE. When DOE commences performing, SCE will have

the flexibility to determine which spent nuclear fuel should be accepted by DOE based upon all

relevant considerations, regardless of the actual age of the spent fuel. Article V.E. of the DOE

Standard Contract, for example, provides in part that SCE “shall have the right to determine

which SNF and/or HLW is delivered to DOE. . . .”131 In addition, TURN’s arguments about

possible government defenses to future damages claims are entirely speculative, and without

basis. Indeed, SCE expects to pursue full recovery of both SONGS and Morris SNF storage

128 TURN Opening Brief, p. 32. 129 Id., p. 33. 130 Id. 131 10 C.F.R. § 961.11.

38

costs—there is no “either/or” dichotomy at play, nor implicated by the DCE assumptions

regarding DOE performance.

In any event, TURN’s request that the pick-up strategy issue be discussed in the 2021

NDCTP is premature. The assumed DOE start date is 2028, at present, and is likely to be

extended in the next DCE. There is no need or benefit to addressing this issue in the 2021

NDCTP, given that spent fuel management issues nationally (including the potential availability

of interim offsite storage sites) are likely to evolve significantly over the next decade. To the

extent the Commission is interested in further information regarding this issue, it should defer

the issue to an NDCTP closer to the assumed DOE start date once further information becomes

available.

VI.

RETURN OF EXCESS FUNDS

TURN recommends that “SCE and SDG&E should be directed to investigate options for

identifying excess funds in the decommissioning trusts and making excesses available for return

to ratepayers prior to the termination of the SONGS site license in 2051.”132 TURN further

recommends that the Utilities present their analysis in the 2021 NDCTP.133 According to TURN,

the investigation will facilitate the timely return of any excess funds once identified.134 TURN

ignores the information the Utilities have already provided on this issue.

132 TURN Opening Brief, p. 3. 133 TURN Opening Brief, p. 34. 134 Id.

39

A. The Utilities Have Already Submitted Information Demonstrating The Challenges

In Identifying And Returning Perceived Excess Funds

TURN’s recommendation is problematic because the Internal Revenue Code (Tax Code)

and related Treasury regulations do not currently contain provisions that specifically allow for

the withdrawal of potentially excess funds from the qualified nuclear decommissioning trust

(QNDT) prior to final decommissioning of the nuclear unit site.135 The current Tax Code and

related Treasury regulations limit the withdrawal of funds from a QNDT only for purposes of

paying decommissioning costs of the nuclear unit and administrative costs of the trust.136/137

Consistent with these tax provisions, Internal Revenue Service (IRS) Private Letter Rulings

200737001 and 200737002 ruled that if perceived excess funds were removed from a QNDT

before substantial completion of the related unit, the IRS would use its authority and discretion

granted in 26 C.F.R. §1.468A-5(c)(1) to disqualify the QNDT “in its entirety.”138 The Treasury

regulations define “substantial completion” as occurring “on the date on which all Federal, state,

local, and contractual decommissioning requirements are fully satisfied (the substantial

completion date).”139

Even if the Tax Code or Treasury regulations included provisions that specifically

permitted potentially excess funds to be withdrawn from QNDTs prior to final decommissioning

of the site, TURN’s recommendation is premature because no funds have currently been

135 Exhibit SCE-15, p. 28; Exhibit SDGE-09, pp. 16-17. 136 26 U.S. Code § 468A(e)(4); 26 C.F.R. § 1.468A-5(c)(1). 137 The notion in the tax rules of “excess” amounts in a QNDT relates only to annual contribution

payments (which SCE is no longer making) made into a QNDT that are more than the amount permitted by a taxpayer’s annual schedule of ruling amount, and require any such excess amounts to be withdrawn from the QNDT by the tax return due date in order to avoid disqualifying the favorable tax status of the QNDT. See 26 C.F.R. § 1.468A-5 (c)(2)(ii) and 26 C.F.R. § 1.468A-5 (c)(2)(i). This situation is not applicable here.

138 Private Letter Rulings 200737001 and 200737002, p. 7. 139 Proposed C.F.R. § 1.468A-5 (d)(3).

40

designated as excess, and it would be imprudent to identify any excess NDT funds until further

decommissioning work has been completed. A more accurate analysis of potentially excess

funds might be possible after the Navy specifies the final site restoration and radiological

decontamination standards for SONGS and the work has been completed (including removal of

the ISFSI).140

In addition, TURN’s recommendation is contrary to Nuclear Regulatory Commission

(NRC) guidance. NRC Staff has issued regulatory guidance that the return of excess

decommissioning trust funds will not be allowed until the NRC 10 CFR Part 50 license has been

terminated. For SONGS, the earliest this is forecast to occur is 2051.141

B. TURN’s Recommendation Is Premature At This Stage Of Decommissioning

TURN’s response to these issues is to speculate about excess funds resulting from:

(1) various potential cost savings achieved through early completion of decommissioning

activities and reduced site restoration requirements; (2) adverse tax rulings regarding the

withdrawal of trust funds for spent fuel management costs; and (3) higher trust-fund investment

returns than forecasted.142 However, TURN fails to consider that a meaningful, more-definitive

assessment regarding excess funds would be too speculative until the SONGS decommissioning

process is substantially complete. Therefore, the recommendation is decades premature.

As noted earlier in this brief, SONGS decommissioning is only in year 6 of a nearly 40-

year project. There are significant inherent scope, cost, and economic uncertainties that could

impact the decommissioning project and sufficiency of trust funds (whether held as qualified or

non-qualified). TURN singularly focuses on customers who have contributed to the NDTs, and

140 Exhibit SCE-15, pp. 28-29. 141 Exhibit SDGE-09, p. 15. 142 TURN Opening Brief, pp. 36-37.

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ignores future customers who would have to contribute to the NDTs if funds were unwisely

returned prematurely. It will always be possible that some money will remain in the NDTs at

final License Termination. But similarly, there will always be a risk that the NDTs will be

insufficient if funds are returned prematurely, requiring contributions from future customers. The

Utilities believe that Commission policy should seek to minimize the risk that contributions from

future customers will be required to complete decommissioning. Assuming there may be

intergenerational inequity (either not providing refunds to past customers or seeking

contributions from future customers), it is preferable to protect the latter.

In D.16-04-019, the Commission declined to adopt the same recommendation from

TURN. TURN has offered no new evidence in the 2018 NDCTP demonstrating why the issue

needs to be addressed in any NDCTP within the next decade. The issue of excess funds should

not be addressed until the SONGS decommissioning project is substantially complete.

VII.

MISCELLANEOUS

A. 2021 NDCTP Filing Date

Cal Advocates recommends that the Utilities file their 2021 NDCTP application in

May 2022, not in May 2021.143 The Utilities oppose the recommendation. The only reason to

consider the proposal is if the Commission was unable to issue a final decision in this proceeding

by the end of the year. A decision by the end of 2020 would give the Utilities sufficient time to

incorporate any direction provided in that decision in the 2020 SONGS 1 and SONGS 2&3 DCE

updates and their May 2021 application. The Utilities are confident that the Commission will be

able to issue a final decision within this timeframe.

143 Cal Advocates Opening Brief, p. 2.

42

Cal Advocates suggests that a delay is warranted because the removal of the conduits has

been delayed.144 Cal Advocates’ purported rationale for moving the NDCTP filing date by one

year does not make sense and would disrupt the review schedule established under the Milestone

Framework. The conduits will not be removed during this one-year period.

B. Miscellaneous TURN Recommendations

TURN makes several miscellaneous recommendations not addressed in sections above.

SCE addresses those recommendations in this portion of the brief.

Advice Letter Reporting Requirements

TURN recommends that “[i]n its semi-annual Advice Letters, SCE should be

required to include updates on the schedule impacts of performance delays for any Major Project

covered by the Milestone Framework.”145 The Commission has considered this recommendation

before, and ordered parties to meet and confer regarding advice letter reporting requirements

related to schedule delays and progress reports on key activities. Following the completion of

the meet-and-confer process, the Utilities agreed to provide updates on these issues in their

advice letters. There is no need for the Commission to re-address the issue in its final Phase 3

decision. In any event, the Utilities do not oppose providing updates on schedule delays and has

been doing so.

DGC Amendments

TURN recommends that “[a]s part of future reasonableness reviews, SCE should

be directed to identify each amendment to the DGC contract that affects costs and schedule.” 146

144 Cal Advocates Opening Brief, p. 5. 145 TURN Opening Brief, p. 3. 146 Id.

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The Utilities comply with the Commission’s NDCTP decisions and already addresses significant

variances in their testimony for reasonableness review proceedings of recorded costs. The

Utilities will augment their current practice to include a discussion of relevant DGC Agreement

amendments that produce significant variances, as part of future reasonableness review

proceedings, according to the schedule identified in the Milestone Framework. The Utilities note

that there may be certain amendments that have a non-material impact in relation to overall DGC

Agreement costs, which exceed $1 billion.

Potential Savings From A Decision By The Navy

TURN recommends that, in the next NDCTP, “SCE should identify the potential

savings from a decision by the U.S. Navy to accept the SONGS site at the conclusion of the

Phase II activities by the DGC.”147 TURN further recommends that “SCE should also identify

how the Commission or other state agencies may be able to assist in obtaining a determination

from the Navy favorable to customers and protective to the environment.”148

TURN’s recommendation regarding the identification of potential savings is

premature. The Navy needs to conduct a National Environmental Policy Act (NEPA) review in

order to determine the final site restoration requirements. Based on the current SONGS

decommissioning plan and schedule, the NEPA review will not occur until 2035. Therefore, the

identification of potential savings, if any, cannot occur until the NEPA process concludes. Any

analysis prior to that time would necessarily be speculative and subject to significant change.

At bottom, TURN is seeking to identify perceived savings that could potentially

be returned to customers as excess funds. As noted above, a determination of excess funds

cannot be definitively made until several decades into the future when decommissioning is

147 Id. 148 Id.

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substantially complete. Furthermore, perceived savings in one cost category should not be

construed as final savings. On the contrary, savings in one cost category should be available for

use to offset a shortfall in another cost category. The funds should be considered fluid (available

for various uses), not irrevocably tied to a given activity.

In regard to TURN’s second recommendation, the Utilities do not object to state

agencies participating in the NEPA process once initiated.

Consolidation Of DCEs

TURN recommends that the SONGS 1 and SONGS 2&3 DCEs “should be

consolidated in future NDCTPs to the extent practicable.”149

The Utilities were already planning to develop one document containing the

DCEs for SONGS 1 and for SONGS 2&3 for submittal in the next NDCTP. The document will

consolidate common assumptions but still provide DCE line items by unit. To the extent that

TURN is suggesting a more extensive integration of the SONGS 1 and SONGS 2&3 cost

estimates into a single estimate, further discussions are warranted, as the Utilities believe that

such an integration would not provide benefits and in fact may complicate the Commission’s

review. The units have separate histories and are in different stages of decommissioning, making

TURN’s recommendation at best premature.150 In addition, the Utilities must report recorded

costs and variances by unit. The consolidation of the DCEs would complicate this reporting.

Furthermore, the Utilities must maintain costs separately, by unit, because the ownership

structures of SONGS 1 and SONGS 2&3 are different. Finally, the trust funds are separated by

unit and the associated trust fund calculations need to be by unit. All of these challenges show

149 TURN Opening Brief, p. 3. 150 TURN’s recommendation would be akin to recommending the consolidation of PG&E’s Humboldt

Bay and Diablo Canyon DCEs into one estimate. This would not make sense.

45

that consolidation must be carefully considered, prior to adoption of a more extensive

integration.

The Commission should allow the Utilities to submit the single document

contemplated above, before considering the need for any greater consolidation.

C. The Issues Raised By A4NR Are Beyond The Scope Of This NDCTP

In its opening brief, A4NR recommends that the Commission require the Utilities’ future

NDCTP applications to: (1) explain in detail the consistency of any changes in scope and

schedule of the SONGS decommissioning plan with the scope and schedule of public access to

coastal resources as guaranteed by the Public Trust Doctrine, the Coastal Act, and the California

Constitution;151 (2) assume that the License Termination Plan filed with the NRC for each of the

SONGS units will incorporate a best-in-class radiation standard that meets the most stringent

standard previously approved by the NRC for a decommissioned commercial nuclear plant;152

and (3) contain a detailed discussion and evaluation of the recommendations of the ISFSI

Experts Team and accompanying strategic plan.153

As an initial matter, these issues generally are not within the scope of Phase 3. Indeed,

A4NR does not make any specific recommendations as to how their recommendations impact

the DCEs, either through specific proposed reductions or increases. For this reason, the

Commission need not address or consider A4NR’s recommendations in its Phase 3 decision.

In addition, the recommendations generally involve issues addressed by other state

agencies. The proper proceedings for A4NR to have recommended substantive changes to the

SONGS decommissioning project plan and schedule were during the CSLC’s review of SCE’s

151 A4NR Opening Brief, p. 8. 152 Id., p. 13. 153 Id., p. 16.

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lease renewal application for the SONGS 2&3 offshore conduits and the CCC’s review of SCE’s

application for a CDP for SONGS 2&3 decommissioning. In those proceedings, the CSLC

certified the Environmental Impact Report (EIR) and the CCC issued the CDP, which allowed

for D&D activities to commence. Indeed, A4NR submitted written comments regarding its

recommendations in both of those proceedings, and the CSLC and CCC appropriately considered

A4NR’s recommendations.154

The Utilities briefly address A4NR’s specific recommendations below:

Consistency Of SONGS Decommissioning Plan With Public Trust Doctrine,

the Coastal Act, and the California Constitution

SONGS is situated on an easement/lease within property owned by the Navy.

Ultimately, the Navy is responsible for determining the long-term use of the property once the

easement/lease has been terminated. A4NR will have an opportunity to participate in the Navy’s

NEPA process once initiated and should raise issues in the NEPA process regarding the long-

term use of the property under the Public Trust Doctrine and any other state or federal statute

A4NR believes is applicable. The Commission should not adopt A4NR’s recommendation on

this issue.

Radiological Release Criteria

As noted earlier in this Joint Reply Brief, the 2017 SONGS 2&3 DCE assumes

that SCE will decontaminate the SONGS site to a radiological level that is lower than the 25

154 See John L. Geesman letter to Cynthia Herzog, “SONGS Decommissioning Project Draft EIR Comments,” dated August 16, 2018; CSLC’s Responses in, “SONGS Units 2 and 3 Decommissioning Project Final EIR,” dated February 2019, at pages II-157 through II-161; and Rochelle Becker letters to Ms. Dayna Bochco, “Application No. 9-19-0194 (Southern California Edison, San Diego County)” dated June 7, 2019 and September 6, 2019.

47

mrem release criteria assumed in the 2014 DCE.155 As explained above, SCE included $38.2

million (100% share, 2014 $) for the additional remediation (removal and disposal of

contaminated material) necessary to achieve this lower decontamination criterion and reflect the

assumption in the DCE that all remaining subgrade structures will be disposed at a clean waste

facility following the completion of the current DGC Phase II scope. The Utilities believe this

standard will be sufficient to meet the Navy’s site restoration requirements. The Commission

should not adopt A4NR’s recommendation on this issue.

ISFSI Experts Team

The Utilities have no objection to submitting testimony providing a detailed

discussion and evaluation of the recommendations of the ISFSI Experts Team and accompanying

strategic plan. The Utilities will do so in a future NDCTP (either the 2021 or 2024 NDCTP),

pending the completion of the plan.

VIII.

CONCLUSION

The Utilities submitted ample evidence demonstrating the reasonableness of the 2017

SONGS 1 DCE and SONGS 2&3 DCE, $0.0 customer-contribution request, and proposed

amendment to the Milestone Framework. Cal Advocates’ and TURN’s recommended reductions

to the DCEs are without merit. The proposed reductions to the DCEs would artificially reduce

the DCEs by removing costs for activities reasonably within the scope of decommissioning and

subject to regulatory and legal requirements that SCE complete them.

TURN and A4NR make several observations and recommendations regarding various

issues that are beyond the scope of Phase 3, including issues regarding the status and

155 Exhibit SCE-03C, p. 21, fn 31.

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reasonableness of decommissioning activities to date, advice letter reporting requirements, return

of potential excess NDTs, the timing of certain substructure removal work, and the long-term use

of the SONGS site following decommissioning. The Commission generally should disregard

these extraneous issues in its Phase 3 decision.

Based upon the evidence presented by the Utilities, the Commission should find as

reasonable:

(1) the 2017 San Onofre Nuclear Generating Station Unit 1 (SONGS 1) decommissioning

cost estimate (DCE) of $209.0 million (100% share, 2014 $) for remaining SONGS 1

decommissioning work;

(2) the 2017 SONGS Units 2&3 (SONGS 2&3) DCE of $4,479 million (100% share,

2014 $) for SONGS 2&3 decommissioning work;

(3) the Utilities’ request to maintain annual contributions to their respective SONGS 1

Nuclear Decommissioning Trusts (NDTs) at $0.00 (zero), based upon the 2017 SONGS 1 DCE,

current level of funding of the respective SONGS 1 NDTs, forecast returns on the NDTs, and

projected escalation rates at this time;

(4) the Utilities’ request to maintain annual contributions to their respective SONGS 2&3

NDTs at $0.0 (zero), based upon the 2017 SONGS 2&3 DCE, current level of funding of the

SONGS 2&3 NDTs, forecast returns on the NDTs, and projected escalation rates at this time;

(5) the Utilities’ proposed amendment to the Milestone Framework for reasonableness

reviews of SONGS 2&3 decommissioning costs for waste-disposal activities;

(6) the Utilities’ Cost Categorization Guidelines; and

(7) the Utilities’ compliance with prior Commission decisions in the Nuclear

Decommissioning Costs Triennial Proceeding (NDCTP).

SDG&E respectfully recommends that the Commission find as reasonable:

(1) SDG&E’s estimate of $45.9 million (SDG&E share, 2014 $) for SDG&E-only

decommissioning costs.

49

Respectfully submitted,

WALKER A. MATTHEWS III ELIZABETH C. BROWN /s/ Walker A. Matthews By: Walker A. Matthews III

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-6879 E-mail: [email protected]

ALLEN K. TRIAL /s/ Allen K. Trial________________ By: Allen K. Trial Attorney for: SAN DIEGO GAS & ELECTRIC COMPANY 8330 Century Park Court, CP32D San Diego, CA 92123 Telephone: (858) 654-1804 Facsimile: (619) 699-5027 E-mail: [email protected]

March 20, 2020


STATE OF CALIFORNIA


)) ) ) )

A.18-03-009

CERTIFICATE OF SERVICE

I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I have this day served a true copy of SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E) AND SAN DIEGO GAS & ELECTRIC COMPANY’S (U 902-E) JOINT REPLY BRIEF FOR PHASE 3 on all parties identified on the attached service list for A.18-3-009. Service was effected by transmitting the copies via e-mail to all parties who have provided an e-mail address.

Executed on March 20, 2020, at Rosemead, California.

/s/ Gina Leisure Gina Leisure

SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

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Parties

WALKER A. MATTHEWS, III ALLEN K. TRIAL ATTORNEY AT LAW ATTORNEY SOUTHERN CALIFORNIA EDISON COMPANY SAN DIEGO GAS & ELECTRIC COMPANY 2244 WALNUT GROVE AVENUE / PO BOX 800 8330 CENTURY PARK COURT, CP32D ROSEMEAD, CA 91770 SAN DIEGO, CA 92123 FOR: SOUTHERN CALIFORNIA EDISON COMPANY FOR: SAN DIEGO GAS & ELECTRIC COMPANY

MICHELLE SCHAEFER MATTHEW FREEDMAN CALIF PUBLIC UTILITIES COMMISSION ATTORNEY LEGAL DIVISION THE UTILITY REFORM NETWORK ROOM 4107 785 MARKET STREET, 14TH FL. 505 VAN NESS AVENUE SAN FRANCISCO, CA 94103 SAN FRANCISCO, CA 94102-3214 FOR: TURN FOR: PUBLIC ADVOCATES OFFICE

JOHN L. GEESMAN ATTORNEY DICKSON GEESMAN LLP 1999 HARRISON STREET, STE. 2000 OAKLAND, CA 94612 FOR: ALLIANCE FOR NUCLEAR RESPONSIBILITY

Information Only

ELIZABETH BEAVER MRW & ASSOCIATES, LLC REGULATORY AFFAIRS EMAIL ONLY SAN DIEGO GAS & ELECTRIC COMPANY EMAIL ONLY, CA 00000

Page 1 of 3CPUC - Service Lists - A1803009

3/20/2020https://ia.cpuc.ca.gov/servicelists/A1803009_85397.htm

EMAIL ONLY EMAIL ONLY, CA 00000

BRUCE LACY LAURA L. KRANNAWITTER LACY CONSULTING GROUP, LLC CALIF PUBLIC UTILITIES COMMISSION 433 WILEY BLVD., NW MARKET STRUCTURE, COSTS AND NATURAL GAS CEDAR RAPIDS, IA 52405 320 West 4th Street Suite 500 FOR: TURN Los Angeles, CA 90013

DANIEL W. DOUGLASS CASE ADMINISTRATION ATTORNEY SOUTHERN CALIFORNIA EDISON COMPANY DOUGLASS & LIDDELL 8631 RUSH STREET 4766 PARK GRANADA, SUITE 209 ROSEMEAD, CA 91770 CALABASAS, CA 91303

CASE ADMINISTRATION NATALIE WOODSON SOUTHERN CALIFORNIA EDISON COMPANY SOUTHERN CALIFORNIA EDISON COMPANY 8631 RUSH STREET 8631 RUSH STREET ROSEMEAD, CA 91770 ROSEMEAD, CA 91770

CENTRAL FILES WENDY D. JOHNSON SAN DIEGO GAS AND ELECTRIC COMPANY REGULATORY CASE MGR 8330 CENTURY PARK COURT, CP31E SAN DIEGO GAS & ELECTRIC COMPANY SAN DIEGO, CA 92123 8330 CENTURY PARK COURT, CP32F SAN DIEGO, CA 92123

DAVID WEISMAN ROCHELLE BECKER OUTREACH COORDINATOR EXECUTIVE DIRECTOR ALLIANCE FOR NUCLEAR RESPONSIBILITY ALLIANCE FOR NUCLEAR RESPONSIBILITY PO BOX 1328 EMAIL ONLY SAN LUIS OBISPO, CA 93406 EMAIL ONLY, CA 93406

DAVID PECK DAVID ZIZMOR CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION PRESIDENT BATJER MARKET STRUCTURE, COSTS AND NATURAL GAS ROOM 5215 AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

MARYAM GHADESSI ROBERT HAGA CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION MARKET STRUCTURE, COSTS AND NATURAL GAS ADMINISTRATIVE LAW JUDGE DIVISION AREA 4-A ROOM 5006 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

TRUMAN L. BURNS YAKOV LASKO CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION ENERGY COST OF SERVICE & NATURAL GAS BRA ENERGY COST OF SERVICE & NATURAL GAS BRA ROOM 4205 ROOM 4101 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214



CASE COORDINATION KELSEY PIRO PACIFIC GAS AND ELECTRIC COMPANY CASE MGR. PO BOX 770000; MC B9A, 77 BEALE STREET PACIFIC GAS AND ELECTRIC COMPANY SAN FRANCISCO, CA 94105 77 BEALE STREET, B23 SAN FRANCISCO, CA 94105

MICHAEL CADE JENNIFER POST ANALYST PACIFIC GAS & ELECTRIC COMPANY BUCHALTER, A PROFESSIONAL CORPORATION PO BOX 770000, MAIL CODE B30A 55 SECOND STREET, SUITE 1700 SAN FRANCISCO, CA 94177 SAN FRANCISCO, CA 94105

LINDSEY HOW-DOWNING ATTORNEY LAW OFFICES OF LINDSEY HOW-DOWNING 3060 EL CERRITO PLAZA, NO. 175 EL CERRITO, CA 94530

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