Testimony On the 2016 Decommissioning Cost Estimate for Palo Verde Units 1, 2, & 3

Transcription

1 Application No.: Exhibit No.: Witnesses: XXX SCE-05 Jose L. Perez (U 338-E) Testimony On the 2016 Decommissioning Cost Estimate for Palo Verde Units 1, 2, & 3 Before the Public Utilities Commission of the State of California Rosemead, California March 1, 2016

2 Testimony On the Decommissioning Cost Estimate for Palo Verde Units 1, 2, & 3 Table Of Contents Section Page Witness I. INTRODUCTION...1 J. Perez II. PVNGS DECOMMISSIONING COST ESTIMATE...2 A. Overview...2 B. Decommissioning Cost Estimating Methodology...3 C. Decommissioning Assumptions And Schedule...4 D. PVNGS Decommissioning Cost Estimate SCE s 2016 Adjustments To The 2013 TLG Study...5 a) Class A LLRW Disposal Costs...6 b) Class B & C LLRW Disposal Costs...7 c) Spent Fuel Monitoring Costs...7 d) Contingency Reconciliation of the 2012 PVNGS DCE (2012 NDCTP) And 2016 PVNGS DCE (2015 NDCTP)...10 a) Class A LLRW Disposal Costs...11 b) Class B and C LLRW Disposal Costs...11 c) Spent Fuel Management Costs...12 d) Contingency...12 e) Miscellaneous...12 Appendix TLG Cost Study... Appendix 2 Witness Qualifications... -i-

3 Testimony On the Decommissioning Cost Estimate for Palo Verde Units 1, 2, & 3 List Of Tables Table Page Table II TLG Study and SCE s Share (Without Adjustments) 2013$ in Millions...5 Table II-2 Adjustments Made to 2013 TLG Decommissioning Cost Study 2013 $ in Millions...6 Table II-3 Reconciliation of SCE s PVNGS DCEs 2016 DCE vs DCE ii-

4 Testimony On the Decommissioning Cost Estimate for Palo Verde Units 1, 2, & 3 List Of Figures Figure Page Figure II-1 Changes to the PVNGS 2012 DCE $ in Millions iii-

5 I. INTRODUCTION This testimony provides information regarding SCE s 2016 Palo Verde Nuclear Generating Station Unit Nos. 1, 2, & 3 (PVNGS) 1 decommissioning cost estimate (DCE), which consists of SCE s share of PVNGS decommissioning expenses. The 2016 PVNGS DCE will be utilized in Exhibit SCE- 06 (Financial Testimony) to support the analysis regarding whether the PVNGS nuclear decommissioning trusts (NDTs) are sufficiently funded and whether additional ratepayer contributions are required. The 2016 PVNGS DCE is based on the decommissioning cost study prepared in 2013 by TLG Services, Inc. (TLG) for Arizona Public Service (APS), and subsequently provided to SCE. Although there are uncertainties associated with work not projected to commence until at least three decades from now, SCE has attempted to accurately estimate its share of PVNGS decommissioning expenses. After decommissioning is complete for PVNGS, SCE will return any remaining PVNGS (NDT) funds to customers. 2 In this testimony, SCE requests that the Commission find that the 2016 PVNGS DCE of $521.9 million (SCE share, 2013$) is reasonable. 1 SCE owns a 15.8% interest in the PVNGS. Arizona Public Service Company (APS) owns a 29.10% interest in PVNGS, and is the operating agent. The remaining non-operating owners are Salt River Project (17.49%), El Paso Electric Company (15.80%), Public Service Company of New Mexico (10.20%), the Southern California Public Power Authority (5.91%), and Los Angeles Department of Water and Power (5.70%). 2 CPUC Resolution E-3057, dated November 25, 1987, which adopted the Nuclear Decommissioning Master Trust agreements 1

6 1 2 II. PVNGS DECOMMISSIONING COST ESTIMATE A. Overview In 2013, APS (PVNGS operating agent) retained TLG to update the PVNGS decommissioning cost study last completed in APS directed TLG to perform a study at the same level of detail as previous PVNGS decommissioning cost studies. SCE s 2016 PVNGS DCE is based on the 2013 TLG decommissioning cost study, which organizes PVNGS decommissioning activities into five periods: (1) Pre-Shutdown; (2) Preparation; (3) Decommissioning Operations; (4) Site Restoration; and (5) Independent Spent Fuel Storage Installation (ISFSI) Operations and Decommissioning. The Pre-Shutdown period will involve activities to transition from plant operation to shutdown to decommissioning. Documents required for the shutdown and decommissioning of the units will be prepared and submitted to the Nuclear Regulatory Commission (NRC). The Preparation period will begin after plant shutdown and involve activities to prepare the units for decommissioning. During this period, the spent fuel pools and appurtenances will be isolated from the remaining portions of the plant. In the Decommissioning Operations period, the PVNGS units will be dismantled and decommissioned, including site common facilities. Plant systems will be drained, de-energized, and secured except for plant systems required for spent fuel pool operation. The spent fuel will be maintained in wet storage in each unit s spent fuel pool until it can be safely transferred to the PVNGS ISFSI or removed from the site by the U.S. Department of Energy (DOE). After the spent fuel pools are empty, the pools will be drained and decommissioned with the support systems. The next period is Site Restoration and will entail removal of all remaining plant structures, facilities, and structural foundations. Site restoration will be completed following the decommissioning of the ISFSI. The final period is ISFSI Operations and Decommissioning. The ISFSI will continue to be maintained and monitored until all the spent fuel has been removed from the site. Once all the spent fuel 2

7 has been removed by the DOE, the ISFSI will be dismantled and decommissioned. Any remaining radiological remediation will be performed as necessary to terminate the NRC operating licenses. The remaining site restoration work will be the last activity to be performed. B. Decommissioning Cost Estimating Methodology SCE s 2016 PVNGS DCE accounts for the unique features of the PVNGS facilities, including its nuclear steam supply systems, electric power generation systems, and site buildings and structures, respectively. The DCE also accounts for changes in decommissioning technology, regulation, and economics that may have been identified during the most recent triennial period. 3 To develop the 2013 TLG decommissioning cost study (the basis for SCE s 2016 PVNGS DCE), TLG used site drawings and associated documents to estimate material volumes, numbers, and sizes of components, and a unit cost factor method of estimating. After TLG identified item quantities and unit cost factors, they estimated the costs by multiplying the item quantities by their respective unit cost and difficulty factors. TLG estimated costs for project management, administration, equipment rental, security, and other time-dependent costs based on a critical path schedule. The PVNGS owners must decontaminate the PVNGS site to satisfy the NRC license termination criteria. However, they are not required to remove all improvements (such as non-contaminated underground foundations) from the site because the site is privately owned. In addition, the PVNGS owners may dispose non-contaminated concrete rubble from the decommissioning project at the PVNGS site. Therefore, TLG s cost study assumes that APS will: (1) abandon in place structures or foundations deeper than three feet below grade that are not required to be removed to meet the radiological criteria for NRC license termination, and (2) dispose of non-contaminated demolition materials at the PVNGS site. Thus, APS avoids removal and disposal costs for materials deeper than three feet below grade and disposal costs for non-contaminated materials regardless of where on site they were located during plant operation. 3 California Public Utilities Code

8 SCE used the 2013 TLG cost study as a resource to prepare SCE s 2016 PVNGS DCE, which provides SCE s estimated share of the PVNGS decommissioning expenses. Certain estimates in the TLG cost study require adjustments to be consistent with SCE s knowledge and experience gained during SONGS 1 decommissioning and with assumptions used for other aspects of the NDCTP. Therefore, consistent with SCE s prior PVNGS DCEs, approved by the Commission, SCE developed and applied appropriate adjustments to the 2013 TLG cost study to prepare the 2016 PVNGS DCE. The adjustments were applied to estimates associated with low level radiological waste (LLRW) disposal, spent fuel and ISFSI monitoring, and contingency. C. Decommissioning Assumptions And Schedule SCE s 2016 PVNGS DCE is based on decommissioning commencing promptly after the NRC operating licenses expire. 4 The 2016 PVNGS DCE assumes the DOE will start removing spent fuel from the U.S. nuclear industry in This is consistent with the assumption made in the 2016 San Onofre Nuclear Generating Station Unit No. 1 (SONGS 1) DCE that SCE is submitting in Exhibit SCE- 04, and with the SONGS 2&3 DCE that SCE plans to submit in late Based on studies developed from the DOE Acceptance Priority Ranking & Annual Capacity Report (DOE/RW-0567), dated July 2004, 5 SCE forecasts that the last spent fuel assemblies will be removed from the PVNGS ISFSI in The DCE forecasts that ISFSI demolition and removal, NRC license termination, and final site restoration will be completed at PVNGS within two years after removal of all spent fuel from the ISFSI. SCE s 2016 PVNGS DCE further assumes the use of existing technologies under current regulations and cost levels. 7 The DCE contains reasonable estimates of the scope and cost of future work to set aside sufficient funds. The DCE is not based on detailed planning studies because PVNGS 4 The NRC operating licenses for PVNGS 1, 2, & 3 will expire on June 1, 2045; April 24, 2046; and November 25, 2047, respectively. 5 The July 2004 DOE Acceptance Priority Ranking & Annual Capacity Report, and SCE s projections based on that DOE Report, are provided as Workpapers in this proceeding. 6 Assuming a DOE start date of 2028, SCE assumes that the DOE will remove spent fuel from PVNGS starting in See Footnote 2, supra. 4

9 decommissioning activities are not expected to be performed until many years in the future. The schedules or sequences of activities in the 2016 PVNGS DCE are not being presented for any purpose other than for cost estimation and planning in the 2015 NDCTP. D. PVNGS Decommissioning Cost Estimate Based on the assumptions stated above, Table II-1 provides the 2013 TLG cost study and SCE s share of the costs (without adjustments): Table II TLG Study and SCE s Share (Without Adjustments) 2013$ in Millions Line No. PVNGS TLG Study SCE Share 1 Unit Unit Unit ISFSI Other Facilities Total 2, SCE s 2016 Adjustments To The 2013 TLG Study Based on the 2013 TLG cost study, SCE s share for PVNGS decommissioning is $380.7 million (SCE Share, 2013$) before adjustments. To incorporate SCE s experience from SONGS 1 decommissioning and use assumptions consistent with other aspects of the 2015 NDCTP, SCE developed and applied appropriate adjustments to the 2013 TLG cost study. SCE explains these adjustments below. As shown in Table II-2 below, SCE s 2016 PVNGS DCE is $521.9 million (SCE Share, 2013$) after making the adjustments. 5

10 Table II-2 Adjustments Made to 2013 TLG Decommissioning Cost Study 2013 $ in Millions Line No. PVNGS SCE Share TLG Study SCE Adjustments 3 Class A LLRW Disposal Class B & C LLRW Disposal Spent Fuel Monitoring Contingency Total SCE Adjustments PVNGS DCE a) Class A LLRW Disposal Costs The 2013 TLG cost study estimates that more than 400,000 cubic feet of Class A low level radioactive waste (LLRW) will be generated from the dismantling and decommissioning of each of the PVNGS units. SCE understands that the 400,000 cubic feet of Class A LLRW represents the volume of material from each unit that will be removed from the plant. Based on SCE s SONGS 1 decommissioning experience and benchmarking of the volumes that were disposed of at other completed decommissioning projects, however, SCE believes the volume of Class A LLRW that will ultimately be disposed of will be greater due to packaging and shipping constraints. For example, it is challenging to use all available space within a container due to the various shapes, sizes, and volumes of waste being packaged. While decommissioning SONGS 1, SCE discovered that it initially underestimated: (1) the quantity of materials from the unit that would require disposal as Class A LLRW, and (2) the full cost to dispose of the increased quantity of Class A LLRW with packaging, shipping, and delivery of Class A LLRW shipments to the licensed disposal facility. ABZ 8 developed a 63.2% adjustment factor to be applied to the estimated volume of Class A LLRW to calculate a more accurate estimate of the LLRW volume to be disposed. SCE has utilized this 8 ABZ is a vendor SCE has used to develop other decommissioning estimates submitted by SCE in prior NDCTPs. 6

11 adjustment factor in prior DCEs approved and deemed reasonable by the Commission in NDCTPs. SCE applied the adjustment to the estimated volume of Class A waste in the 2013 TLG cost study, which resulted in an adjustment of $76.0 million (SCE share, 2013$) to the estimated disposal cost for PVNGS Class A LLRW. b) Class B & C LLRW Disposal Costs The 2013 TLG cost study disposal costs for Class B and C LLRW are based on the disposal facility rates for states outside of the Atlantic Interstate Low-Level Radioactive Waste Management Compact (Atlantic Compact) at the EnergySolutions LLRW disposal facility at Barnwell, South Carolina. 9 However, the Barnwell facility is not available for disposal of LLRW from states outside the Atlantic Compact. Therefore, SCE developed an adjustment for disposal at Waste Control Specialists (WCS) disposal facility in Andrews County, Texas, which is available both to Texas Compact states and to states that do not currently have access to disposal facilities within their own interstate LLRW disposal compacts. SCE anticipates that the PVNGS Class B and C LLRW will be shipped to the WCS Texas facility. This adjustment resulted in an increase of $8.0 million (SCE share, 2013$) to the estimated disposal cost for PVNGS Class B & C waste. c) Spent Fuel Monitoring Costs The 2013 TLG cost study includes costs for the transfer of PVNGS spent fuel to the DOE from the spent fuel pools and the ISFSI from 2045 through All other costs associated with the handling of the spent fuel and the maintenance and monitoring of the ISFSI are not included in the TLG study. The study assumes the costs for spent fuel canisters and overpacks, construction of an ISFSI shield wall, installation of an ISFSI crane and cask handling equipment, operation and maintenance of the ISFSI, ISFSI staffing, ISFSI security, and along with other costs will be reimbursed by DOE. These costs were not included in the 2013 TLG study. 9 The member states of the Atlantic Compact include Connecticut, New Jersey, and South Carolina. 7

12 The DOE has an ongoing contractual duty to accept spent fuel at each nuclear plant site and transport it to a permanent repository. The government vigorously litigates claims against the DOE to recover spent fuel maintenance costs; therefore, SCE has no information that supports an assumption that the DOE will assume all ISFSI costs incurred from some date certain until the DOE fulfills its contractual obligation to remove the fuel to a permanent disposal facility. SCE applied an adjustment to the 2013 TLG cost study to account for ISFSI costs that TLG excluded. The 2013 TLG study assumes that the DOE will begin removing spent fuel from the PVNGS pools in 2040, which presupposes a DOE start date of Based on this assumption, the 2013 TLG study assumes that the decommissioning project would incur the cost to transfer twenty-four canisters of PVNGS fuel from the pools to the ISFSI. Because SCE assumed a DOE start date of 2028, SCE assumed that the DOE would commence removing fuel from the PVNGS pools in This would result in decommissioning only incurring the cost to transfer two canisters of fuel from the pool to the ISFSI. SCE s adjustment, therefore, includes an allowance for this purpose. In addition, SCE s adjustment includes ISFSI monitoring and maintenance costs from , based on the assumption that the DOE commences removing spent fuel in 2028, at the acceptance rate specified in the July 2004 DOE Acceptance Priority Ranking & Annual Capacity Report. 10 This adjustment resulted in an increase of $31.2 million (SCE share, 2013$) to the estimated cost of spent fuel storage during the decommissioning period at PVNGS. d) Contingency The 2013 TLG cost study applied contingency factors ranging from 10% to 75% for various PVNGS decommissioning activities. SCE believes a 25% contingency factor is appropriate for industrial projects such as the decommissioning of PVNGS that are in a preliminary stage of development, scheduled several years in the future, prior to the development of detailed engineering 10 The 2013 TLG cost study assumed that the DOE would accept fuel at a slower acceptance rate as specified in the DOE s 1987 DOE Acceptance Priority Ranking & Annual Capacity Report. 8

13 studies or work plans or the issuance of contracts to perform work. 11 SCE has experience in decommissioning activities with SONGS 1 and has continued to use a contingency of 25% in the development of the DCEs for SONGS 1 and SONGS 2&3. Contingencies are applied to cost estimates to account for unknown or unplanned occurrences during the performance of a project. Contingencies are defined in the American Association of Cost Engineers Project and Cost Engineers Handbook as, specific provision for unforeseeable elements of cost within the defined project scope; particularly important where previous experience relating to estimates and actual costs has shown that unforeseeable events which will increase costs are likely to occur. The consensus in the industry literature, including sources from the DOE 12 and the Association for the Advancement of Cost Engineering International (AACE), 13 is that a contingency factor for cost estimates in this stage of development should fall within a range of 15% to 30%. In a previous NDCTP, PG&E prepared a paper entitled, Technical Position Paper for Establishing an Appropriate Contingency Factor for Inclusion in the Decommissioning Revenue Requirements, dated February Based on industry and regulatory documents, the position paper concludes that it is appropriate to add a contingency factor of 25% to estimated decommissioning costs because the 25% contingency factor provides reasonable assurance for unforeseen circumstances that could increase decommissioning costs, and should not be reduced or eliminated simply because foreseeable costs are low. For all of these reasons, SCE believes that a 25% contingency factor, applied to all estimated decommissioning costs including LLRW disposal costs, is both conservative and appropriate for use in the 2016 PVNGS DCE. Therefore, SCE adjusted the contingency factors in the TLG Study to 25%. 11 D , Section 6.2.1, page 83, Although SCE did not provide specific evidence to support its determination that 25% is the appropriate factor, 25% is well within the industry range and the facility [Palo Verde] is licensed to operate for at least thirty more years, a factor for increasing contingency. 12 See Chapter 11 of U.S. Department of Energy Decommissioning Implementation Guide DOE, G , March 28, See Association for the Advancement of Cost Engineering International (AACE) Recommended Practice No. 18R-97, at p. 2 of 9. 9

14 This resulted in an adjustment of $ 26.0 million (SCE share, 2013$) that is reflected in SCE s 2016 PVNGS DCE. 2. Reconciliation of the 2012 PVNGS DCE (2012 NDCTP) And 2016 PVNGS DCE (2015 NDCTP) The purpose of this section is to reconcile the differences between the adjusted estimates from the 2012 PVNGS DCE approved in the 2012 NDCTP and the 2016 PVNGS DCE presented by SCE in this 2015 NDCTP. The 2012 PVNGS was based upon TLG s 2010 cost study, and as discussed above, the 2016 PVNGS DCE is based on TLG s 2013 cost study. Table II-3 provides a summary reconciliation. Table II-3 Reconciliation of SCE s PVNGS DCEs 2016 DCE vs DCE Line Item Amount SCE PVNGS DCE (2010 $ in Millions) $ Escalation to 2013$ $ SCE PVNGS DCE (2013$ in Millions) $ Class A LLRW Disposal Costs ($27.8) 5 Class B and C LLRW Disposal Costs ($12.6) 6 Spent Fuel Management Costs $6.5 7 Contingency ($2.2) 8 Miscellaneous Costs ($4.5) SCE PVNGS DCE (2013 $ in Millions) $

15 Figure II-1 Changes to the PVNGS 2012 DCE $ in Millions a) Class A LLRW Disposal Costs The Class A LLRW adjustment that SCE made in the 2016 PVNGS DCE is less than the adjustment made in the 2012 PVNGS DCE. This is because TLG used a lower disposal rate in its 2013 TLG study than in its 2010 study. TLG used pricing based on the current rate structure of the EnergySolutions facility at Clive, Utah in its 2013 study, rather than the higher fees for the Barnwell, South Carolina facility used in in its 2010 study. b) Class B and C LLRW Disposal Costs The Class B and C LLRW adjustment that SCE made in the 2016 PVNGS DCE also is less than the adjustment made in the 2012 PVNGS DCE. This is primarily due to a decrease in the assumed waste volumes for Class B and C LLRW. The 2010 TLG study estimated 15,633 cubic feet of Class B and C waste from all three units and the 2013 TLG study estimates a waste volume of 7,431 cubic feet. The same burial rate was used in both TLG studies. 11

16 c) Spent Fuel Management Costs The basis for SCE s adjustment for PVNGS Spent Fuel Management costs is explained above. The basis for the increase in this adjustment in SCE s 2016 PVNGS DCE is due to two factors. First, the ISFSI monitoring costs provided in the 2013 TLG study increased relative to the ISFSI monitoring costs in the 2010 TLG study. These cost increases are reflected in SCE s annual 2016 spent fuel management adjustment. Second, due to the change in SCE s DOE start date assumption from 2024 to 2028, it was necessary for SCE to add spent fuel management costs for four additional years. d) Contingency The decrease in the contingency adjustment reflects the decreases to other portions of the DCE. e) Miscellaneous The TLG cost study was lower due to the lower Class A disposal cost discussed above as well as the decrease in the Class B and C waste volumes. 12

17 Appendix TLG Cost Study

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178 Appendix 2 Witness Qualifications

179 SOUTHERN CALIFORNIA EDISON COMPANY QUALIFICATIONS AND PREPARED TESTIMONY OF JOSE LUIS PEREZ Q. Please state your name and business address for the record. A. My name is Jose Luis Perez, and my business address is 2244 Walnut Grove Ave, Rosemead, CA Q. Briefly describe your present responsibilities at the Southern California Edison Company. A. I am a Principal Manager in the Nuclear Decommissioning Organization responsible for CPUC regulatory activities and financial planning & analysis for SONGS issues. Q. Briefly describe your educational and professional background. A. I earned an MBA from the University of California, Irvine in I earned a Bachelor of Science Degree in Civil Engineering from California State University, Long Beach in I am a Registered Professional Engineer in the State of California. Since joining Edison in 1982, I have held various management positions in nuclear generation business, finance, regulatory affairs, planning & strategy, and project controls organizations. In addition, I have managed various projects, including SONGS 1 decommissioning shortly after permanent shutdown and industry restructuring financial analysis. Prior to joining Edison, my professional background included various home office and jobsite positions in the civil engineering, nuclear power plant start-up, and project controls organizations of Bechtel Power Corporation and the collection and analysis of construction cost data for publication in cost estimating manuals for Marshall and Swift Publications. Q. What is the purpose of your testimony in this proceeding? A. The purpose of my testimony in this proceeding is to sponsor the portions of Exhibit SCE-05, Testimony On the 2016 Decommissioning Cost Estimate for Palo Verde Units 1, 2, & 3. Q. Was this material prepared by you or under your supervision? A. Yes, it was. 1 Appendix 2-1

180 Q. Insofar as this material is factual in nature, do you believe it to be correct? A. Yes, I do. Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best judgment? A. Yes, it does. Q. Does this conclude your qualifications and prepared testimony? A. Yes, it does. -2 Appendix 2-2