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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
-i-
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
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 (CONTINUED)
Section Page
-ii-
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
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 (CONTINUED)
Section Page
-iii-
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
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 AUTHORITIES
Page
-iv-
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
-v-
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
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
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.
6
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.
14
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.
15
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.
16
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.
17
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.
18
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.
19
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.
20
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.
21
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.
22
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.
23
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.
24
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.
25
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.
26
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.
27
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.
28
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 .
30
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.
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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.
41
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.
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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.
48
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
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
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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PROCEEDING: A1803009 - EDISON AND SDG&E - F FILER: SAN DIEGO GAS & ELECTRIC COMPANY LIST NAME: LIST LAST CHANGED: FEBRUARY 19, 2020
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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
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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
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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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