BEFORE THE GEORGIA PUBLIC SERVICE COMMISSION
IN THE MATTER OF: GEORGIA POWER COMPANY’S TWENTIETH/TWENTY- DOCKET NO. 29849 FIRST SEMI-ANNUAL VOGTLE CONSTRUCTION MONITORING REPORT
DIRECT TESTIMONY
AND EXHIBITS
OF
SHEMETHA Q. JONES
ON BEHALF OF THE
GEORGIA PUBLIC SERVICE COMMISSION
PUBLIC INTEREST ADVOCACY STAFF
November 22, 2019
Table of Contents Page I. INTRODUCTION...... 1 II. PURPOSE OF ASSIGNMENT ...... 2 III. DISCUSSION OF PROJECT COST REVIEW PROCESS ...... 5 IV. DISCUSSION OF THE ADMINISTRATIVE CLAIM ...... 12 V. DISCUSSION OF REVIEW PROCEDURES AND CONTROLS ...... 14 VI. FINDINGS BASED UPON REVIEW ...... 14 VII. RECOMMENDATIONS ...... 15
1 I. INTRODUCTION
2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A. My name is Shemetha Q. Jones, and I am an analyst for the Georgia Public
4 Service Commission (“Commission” or “PSC”) on the Vogtle Construction
5 Monitoring Docket 29849. My business address is 244 Washington Street, S.W.,
6 Atlanta, Georgia, 30334.
7 Q. MRS. JONES, PLEASE STATE YOUR EDUCATIONAL BACKGROUND
8 AND WORK EXPERIENCE.
9 A. I received a Master of Science degree in Accounting from the University of New
10 Orleans and am a Certified Public Accountant. I received a Bachelor of Science
11 degree in Chemistry from Spelman College. Before joining the Commission in
12 2010, I worked as a tax consultant/tax associate in the private sector for three and
13 a half years. I have been assigned to the Vogtle Monitoring Team for over four
14 and a half years. Prior to joining this team, I worked at the Commission for five
15 years as an analyst in the Energy Efficiency and Renewable Energy Group
16 (“EERE”). Also, I have served on the Public Interest Advocacy Staff for the 2013
17 IRP, 2010 IRP, and 2010 Rate Case and as a member of the Commission’s
18 Advisory Staff in the 2019 and 2013 Rate Case.
19 Q. HAVE YOU EVER TESTIFIED BEFORE THIS COMMISSION?
20 A. Yes, I have testified in Docket No. 36499, Georgia Power’s 2013 DSM (“Demand
21 Side Management”) Certification and in Docket No. 29849, Georgia Power
22 Company’s 14th, 16th, 17th, 18th, and 19th Vogtle Construction Monitoring
23 proceedings.
1 Q. WHOM ARE YOU REPRESENTING IN THIS PROCEEDING?
2 A. I am representing the Commission’s Public Interest Advocacy Staff (“Staff”).
3 II. PURPOSE OF ASSIGNMENT
4 Q. WHAT WAS YOUR ASSIGNMENT IN THIS PROCEEDING?
5 A. My assignment in this proceeding was to review Georgia Power Company’s
6 (“Company” or “GPC”) share of the monthly Vogtle Units 3 & 4 Site
7 Construction Management Costs and Owner’s Costs included in the
8 Twentieth/Twenty-First Semi-Annual Vogtle Construction Monitoring Report for
9 the twelve-month reporting period July 1, 2018 through June 30, 2019
10 (“Reporting Period”). In addition to reviewing the monthly cost data, I also
11 reviewed the Company’s accounting procedures and guidelines. The purpose of
12 this detailed review was to confirm that Vogtle Units 3 & 4 costs were supported
13 by adequate documentation and confirmed by Company personnel responsible for
14 reviewing the costs charged to the Vogtle Units 3 & 4 Construction Project
15 (“Project”) Construction Work In-Progress Account (“CWIP”). In addition, I
16 reconciled the Project costs as filed by the Company with this Commission
17 against the Company’s general ledger accounts. During this process, I provided
18 feedback to the Company and Staff regarding the review and reconciliation of the
19 Project costs in addition to noting any problems that were found in the monthly
20 reports and to make any further recommendations with respect to the organization
21 and confirmation of costs included in the Reporting Period.
2
1 Q. DID YOU PERFORM AN AUDIT OF THE VOGTLE 3&4 PROJECT
2 COSTS?
3 A. No, I did not perform an audit. Staff only performed a review of project costs.
4 Therefore, I cannot give an opinion1 on whether there were any material
5 misstatements of the Company’s reported project costs or issues with the
6 accounting controls and procedures in place because providing an opinion is
7 outside the scope of a review. I reviewed, among other documents, project
8 reported costs, invoices, internal audit reports, external audit reports, and the
9 Company’s accounting procedures & guidelines. I also made inquiries as
10 necessary and became familiar with internal controls. While a review does share
11 the goal of an audit, which is to provide a level of assurance that there are no
12 material misstatements with project costs or financial statements, a review is not
13 conducted with the same level of investigation or analysis as an independent audit
14 described on the next page. Therefore, a review only provides limited assurance
15 while an audit provides reasonable assurance that the financial statements, or
16 costs, are free from material misstatement.
17 Q. WHO IS THE COMPANY’S EXTERNAL AUDITOR?
18 A. Deloitte & Touche LLP (“Deloitte”) has been the Company’s auditor since 2002.
19 They are responsible for auditing the Company’s financial statements and giving
20 an opinion on the financial statements.
1 An opinion is a written statement by an auditor that describes whether a Company’s financial statements or costs are in accordance to Generally Accepted Accounting Principles (GAAP). It also describes the basis for the opinion (refer to lines 10-18 on page 4).
3
1 Q. DID DELOITTE PERFORM A SPECIFIC AUDIT OF THE COSTS
2 CHARGED TO THE VOGTLE PROJECT?
3 A. No. Deloitte audited the financial statements of the Company as a whole.
4 Q PLEASE EXPLAIN DELOITTE’S ROLE.
5 A. Deloitte performed an audit of the Company’s annual financial statements for the
6 year ended December 31, 2018 and 2017. Deloitte conducted the audit in
7 accordance with the standards of the Public Company Accounting Oversight
8 Board (“PCAOB”). PCAOB standards require that they plan and perform the
9 audit to obtain reasonable assurance that the financial statements are free from
10 material misstatement, whether due to error or fraud. The audit examined
11 evidence supporting the information in the financial statements on a test basis,
12 and the audit by Deloitte evaluated the accounting principles used and significant
13 estimates made by management as well as the overall presentation of the financial
14 statements. Deloitte was also engaged to audit Southern Company’s internal
15 control over financial reporting for the same period. Deloitte stated that in its
16 opinion the financial statements presented fairly, in all material respects, the
17 financial position of the Company as of December 31, 2018 and 2017 (and the
18 results of its operations and its cash flows for each of the three years in the period
19 ended December 31, 2018) in conformity with accounting principles generally
20 accepted in the United States of America. Also, Deloitte stated in its opinion
21 Southern Company maintained, in all material respects, effective internal control
4
1 over financial reporting as of December 31, 2018, based on criteria established in
2 Internal Control – Integrated Framework (2013) issued by COSO2.
3 Q. DID GPC ENGAGE A COMPANY TO PERFORM AUDIT SERVICES
4 RELATED TO THE VOGTLE PROJECT DURING THE REPORTING
5 PERIOD?
6 A. Yes. The Company hired Revenew to perform audit services related to costs
7 incurred from Westinghouse Electric Company (“WEC”) under the Services
8 Provider Agreement (“SPA”). The audit was completed in July 2019 for the
9 period of December 2017 through November 2018.
10 III. DISCUSSION OF PROJECT COST REVIEW PROCESS
11 Q. PLEASE DESCRIBE SOME OF THE VARIOUS REPORTS OR OTHER
12 DOCUMENTS PROVIDED BY THE COMPANY THAT YOU REVIEWED
13 THAT SUPPORT THE COST DATA PROVIDED IN THE PROJECT’S
14 MONTHLY STATUS REPORTS.
15 A. I reviewed a number of reports included in the Company’s Monthly Financial
16 Records Cost Notebooks that provide support for the compilation of the Vogtle
17 Units 3 & 4 Project costs in the Project Monthly Status Reports. Some of the
18 reports that were reviewed include:
19 (1) WEC Invoice Review Binder, which contains WEC’s Invoices for
20 the Reporting Period under the SPA.
2 Committee of Sponsoring Organizations of the Threadway Commission
5
1 (2) The Owner’s Cost/Project Cost Review Binders contain invoices
2 during the reporting period mostly related to time and materials
3 contract work, contract labor, legal fees, and consulting services.
4 (3) Bechtel Statement Cost Review Binder, which contains the Bechtel
5 Construction Contract Invoices and Monthly Funding Requests for
6 the Reporting Period.
7 (4) Monthly Construction Work in Progress Balances, Beginning and
8 End of Month for each month of the Reporting Period as reported
9 in the Monthly Budget Update to the PSC.
10 (5) Various supporting Pivot Table Reports extracted from the
11 Company’s general ledger used to support reconciliations of the
12 detailed Additions, Accruals/Reversals, and amounts closed to the
13 Plant in Service Ledger Account included in the Monthly Status
14 Reports.
15 Q. WITH REGARD TO YOUR REVIEW OF THE MONTHLY CWIP
16 BALANCES, BEGINNING AND END OF MONTH FOR THE
17 REPORTING PERIOD, WERE THERE ANY NEW COST CATEGORIES
18 ADDED TO BREAKOUT THE MONTHLY CWIP BALANCES?
19 A. No. The categories were the same as in the 19th VCM reporting period.
20 Q. PLEASE DISCUSS THE REVIEW PROCESS OF THE CWIP BALANCES
21 CONDUCTED BY STAFF.
22 A. I reviewed the various reports noted on the previous page to reconcile the monthly
23 Vogtle 3 & 4 CWIP costs included in supplemental reports to the summary
6
1 reports and analyzed the month-to-month roll forward of costs for the Reporting
2 Period. These costs are contained in the electronic general ledger that rolls up to
3 the Project’s Monthly Status Reports. The monthly detailed reporting
4 documentation served to support the Project’s Monthly Status Reports. These
5 reports provided information related to capital expenditures recorded by the
6 Company. These costs were recorded in CWIP Sub-Accounts 307 and 308 and
7 then rolled up into FERC Account 107–CWIP.
8 Q. DOES THE COMPANY USE VARIOUS SOFTWARE MODELS THAT
9 CAPTURE AND EXTRACT COSTS TO CONFIRM ACCOUNTING AND
10 ASSIGNMENT OF THOSE COSTS INCURRED FOR THE PROJECT?
11 A. Yes. The Company uses various software models including Oracle, which
12 contains the general ledger and many of the modules that interface with it such as
13 Power Plant. These applications provide journal voucher information for queries
14 of data using Microsoft Excel, SSAT3, SOFIA4 and SARA5 to isolate and track
15 costs including, e.g., Ad Valorem Taxes and legal costs that are generated and
16 reported on the various pivot tables.
17 Q. DID YOU SUBMIT ANY DATA REQUESTS TO THE COMPANY TO
18 ASSIST IN YOUR REVIEW OF THE COMPANY’S PROJECT
19 CONSTRUCTION COST REPORTING?
3 SSAT is the Single Source Accrual Tool which is linked to Oracle Financials. 4 SOFIA is the Southern Financial Information Access System and is an on-line, end-user query tool that provides access to the Data Repository in the Oracle General Ledger application which shows actuals and budget costs. 5 SARA is the Southern Accounting Reporting Application that creates monthly financial reports.
7
1 A. Yes. I submitted formal data requests STF-158, STF-167, STF-168, STF-171,
2 and STF-172 requesting the most current internal and external audit reports in
3 addition to performance audit reports that addressed findings associated with the
4 audit of accounting and financial reporting of the Project construction costs. I
5 submitted data requests for specific information included in the monthly cost
6 notebooks. I also requested information on any changes in accounting procedures,
7 guidelines or instructions since the last filing, and Project costs associated with
8 the Company’s deferred assets and liabilities for the reporting period.
9 Q. WHAT OVERSIGHT ACTIVITIES DOES THE COMPANY CONDUCT
10 AS PART OF ITS INTERNAL REVIEW PROCESS?
11 A. As part of its internal review process, the Company completes a detailed checklist
12 of the job tasks for each month. These pages, contained in the front of each
13 monthly Project Cost Notebook entitled “GPC Nuclear Development Financial
14 Management Monthly Procedure Check List,” include a check-off of various
15 financial/accounting tasks. This monthly check-off review is attested to by the
16 GPC Nuclear Development Accounting Manager, GPC Nuclear Development
17 Financial Manager, and the GPC Nuclear Development Commercial Director.
18 Company personnel have indicated previously that this process serves as a
19 continuing monthly internal oversight of the accounting process for the Project
20 and is in response to Sarbanes-Oxley (“SOX”) 404 Controls.
21 Q. WERE THERE ANY INTERNAL AUDIT REPORTS ISSUED BY THE
22 COMPANY OR SOUTHERN COMPANY SERVICES (“SCS”) THAT
8
1 ADDRESSED CONSTRUCTION COSTS FOR THE REPORTING
2 PERIOD?
3 A. Yes.
4 Q. DID ANY OF THE INTERNAL AUDIT REPORTS CONTAIN
5 REPORTABLE FINDINGS?
6 A. Yes. As noted in the Company response to STF-158-4, there were reportable
7 findings associated with the Vogtle 3&4 Scheduling Assessment, Vogtle 3&4
8 Contractor Compliance-Williams Specialty Services, Vogtle 3&4 Accruals
9 Assessment, and Vogtle 3&4 Bechtel Contract Administration audit. It should
10 be noted that Reportable findings require a resolution action plan by
11 management (management response). However, for Other observations the
12 intent is to strive for continuous improvement by elevating these issues to
13 identify any potential weaknesses in process or controls for management’s
14 attention.
15 Q. PLEASE BRIEFLY DISCUSS THE AUDIT REPORTS MENTIONED
16 ABOVE.
17 A. The objective of the Vogtle 3&4 Scheduling Assessment was to assess the
18 adequacy and effectiveness of the procedures, operating guidelines, and process
19 documentation in place for management of the project schedule. For the Vogtle
20 3&4 Contract Administration, the goal was to verify that vendor billings from
21 Williams Specialty Services were accurate and pursuant to the terms and
22 conditions of the contractual agreement. In the Vogtle 3&4 Accruals Assessment,
23 Internal Auditing assessed the process used by the Company and SNC to accrue
9
1 for costs associated with the Vogtle 3&4 construction project. The objective of
2 the Bechtel Contract Administration Audit was to assess the adequacy and
3 effectiveness of the SNC/Owner’s processes and controls in place to comply with
4 the terms and conditions of the Bechtel Construction Completion Agreement.
5 More information on the reports and the findings can be found in attachments
6 STF-158-4-c, STF-158-4-d, STF-158-4-f, and STF-158-4-j.
7 Q. HAS THE COMPANY CONTINUED TO MAINTAIN ITS PROFICIENCY
8 IN THE ORGANIZATION AND REPORTING OF ITS FINANCIAL AND
9 ACCOUNTING DATA IN THE MONTHLY FINANCIAL RECORDS
10 COST NOTEBOOKS?
11 A. Yes.
12 Q. IS THE COMPANY’S COST NOTEBOOK CROSS-REFERENCING AND
13 ORGANIZATION PROCESS SUFFICIENT FOR STAFF TO CONDUCT
14 ITS REVIEW?
15 A. Yes. At this point in the continuing review, Staff believes that the Company
16 maintains satisfactory cross-referenced and organized cost notebook data in order
17 for the Staff to complete its review.
18 Q. DID YOU REVIEW THE OWNER’S COST/PROJECT COST
19 NOTEBOOKS FOR THE TWENTIETH/TWENTY-FIRST VCM
20 REPORTING PERIOD?
21 A. Yes, I reviewed the 2nd Quarter, 3rd Quarter, and 4th Quarter notebooks for 2018. I
22 also reviewed the 1st Quarter and 2nd Quarter notebooks for 2019.
10
1 Q. PLEASE SUMMARIZE THE COMPANY’S REVIEW PROCESS OF
2 OWNER’S COSTS/PROJECT COSTS INVOICES.
3 A. As noted in TS Attachments STF-158-10 and STF-171-8, GPC Nuclear
4 Development Financial Services performs a quarterly review of invoices
5 classified as Owner’s Cost, Transmission, Procurement, Construction Support,
6 Construction Subcontractors, Construction Distributables, Field Non-Manual
7 (“FNM”) Labor and Project Management for Commission reporting purposes and
8 primarily pertain to work managed by SNC. The report on the review for 2nd
9 quarter 2018 was provided in TS Attachment STF-158-10-a, 3rd quarter 2018 in
10 STF-158-10-b, 4th quarter 2018 in STF-171-8-a, and 1st quarter 2019 in STF-171-
11 8-b. GPC Nuclear Development Financial Services selected invoices for testing
12 based on random and judgmental sampling techniques. Their sample included
13 invoices for work performed by vendors for project cost efforts, time and
14 materials (“T&M”) contract work, contract labor, legal fees, and consulting
15 services.
16 Q. WERE THERE FINDINGS BASED UPON THE COMPANY’S NUCLEAR
17 DEVELOPMENT FINANCIAL SERVICES REVIEW?
18 A. There were immaterial findings in the 2nd and 3rd quarter of 2018 related to
19 transmission and incorrect billings to subcontractors. However, there were no
20 reportable findings for 4th quarter 2018 and 1st quarter 2019. (The review for the
21 2nd quarter of 2019 is currently in progress).
11
1 Q. WERE THERE ANY OBSERVATIONS MADE BY NUCLEAR
2 DEVELOPMENT FINANCIAL SERVICES IN THE 4TH QUARTER 2018
3 AND 1ST QUARTER 2019?
4 A. Yes. The issues identified were remediated and resolved.
5 IV. DISCUSSION OF THE ADMINISTRATIVE CLAIM
6 Q. STAFF MENTIONED IN THE 19TH VCM THAT THE COMPANY FILED
7 AN ADMINISTRAIVE CLAIM IN REGARDS TO THE RGP AUDIT OF
8 WEC. PLEASE EXPLAIN IF ANY FUNDS WERE RECEIVED.
9 A. On August 30, 2018, the Company filed an administrative claim for $51.66
10 million to recover costs due from WEC pertaining to the RGP audit. Since the
11 filing of the administrative claim, the Company and WEC continued to work
12 together to come to a resolution. In the second quarter of 2019, the Company
13 received $30.17 million from WEC, which primarily consisted of funds from the
14 WEC IAA bank account as a result of a settlement agreement.
15 Q. PLEASE RECONCILE THE $30.1 MILLION RECEIVED BY THE
16 COMPANY TO THE ADMINISTRATIVE CLAIM AMOUNT OF $51.6
17 MILLION THAT WAS FILED IN THE 19TH VCM?
18 A. In the 19th VCM, the Company stated that it expected to receive additional
19 supporting documentation from WEC that will substantiate some of the costs that
20 were in dispute. On August 26, 2019, the Company stated in data response STF-
6 The amount of the claim filed at 100% was $112.9 million of which GPC’s portion is $51.6 million.
7 This represents GPC’s percentage of the claim, which is 45.7% of $65.9 million (the total amount received).
12
1 168-1 that it had enough evidence to support approximately $21.5 million from
2 the documentation received from WEC, which represents the difference.
3 Therefore, the Company has confirmed that these expenditures were actually
4 spent on the Project.
5 Q. IS THE $21.5 MILLION THE SAME AMOUNT THAT THE COMPANY
6 IS NOW REQUESTING VERIFICATION & APPROVAL FOR IN THE
7 CURRENT VCM FILING THAT WAS DEFERRED IN THE 19TH VCM?
8 A. Yes.
9 Q. WAS STAFF ABLE TO REVIEW THE SUPPORTING
10 DOCUMENTATION?
11 A. Yes. Staff met with the Company to discuss and review some of the supporting
12 documentation. In addition, Staff reviewed summary information that showed the
13 supporting documentation totaled approximately $21.5 million.
14 Q. IS THE ADMINISTRATIVE CLAIM NOW RESOLVED?
15 A. Yes. The Company is no longer seeking recovery from WEC and has released all
16 claims and interests to amounts included in the administrative claim.
17 Q. DISCUSS THE FINDINGS OF THE REVENEW AUDIT.
18 A. There were some issues identified in the audit which included supporting
19 documentation missing for certain expenditures. The Company is working with
20 WEC to resolve the issues. Nevertheless, the magnitude of the expenditures
21 lacking documentation found in the Revenew audit is on a smaller scale than the
22 RGP audit.
13
1 V. DISCUSSION OF REVIEW PROCEDURES AND CONTROLS
2 Q. DOES THE COMPANY CONTINUE TO MAINTAIN OVERSIGHT OF
3 ITS VARIOUS CONTROLS AND PROCEDURES TO ENSURE
4 ACCURATE REPORTING OF PROJECT COSTS?
5 A. The Company is continuing to maintain oversight of its controls and procedures to
6 ensure that Project costs are being properly recorded as indicated by the GPC
7 Nuclear Development Financial Management Monthly Procedure Check List,
8 Internal Auditing Assessments, and the quarterly Project Cost Review. Also, the
9 Company regularly updates and/or adds new accounting desktop procedures8as it
10 deems necessary to ensure procedures are followed correctly.
11 VI. FINDINGS BASED UPON REVIEW
12 Q. PLEASE DISCUSS YOUR FINDINGS BASED UPON YOUR REVIEW OF
13 THE COMPANY’S REPORTING AND RECORDING OF THE PROJECT
14 CONSTRUCTION COSTS FOR THE REPORTING PERIOD.
15 A. Based upon my review of the Vogtle Units 3 & 4 Project cost data reported in the
16 Company’s Monthly Financial Records Cost Notebooks for the Reporting Period,
17 I can provide limited assurance that there is no material misstatement with the
18 reported Project costs or issues with the accounting controls and procedures in
19 place and followed by the designated representatives of the Company at this time.
8 Accounting guidelines related to employee’s job tasks, STF-158-23.
14
1 VII. RECOMMENDATIONS
2 Q. DO YOU HAVE ANY SPECIFIC RECOMMENDATIONS FOR FUTURE
3 REVIEWS?
4 A. Yes. As the construction of the Project continues, I recommend that the Company
5 continue to keep Staff apprised, as it has done in the past, of any and all changes
6 in the reporting of the Project’s costs from the lower detailed support to the
7 summary reports. This will allow Staff to complete its analysis in a timely and
8 thorough manner and to assess whether accounting guidelines and procedures are
9 being properly followed.
10 Q. DOES STAFF RECOMMEND THE $21.5 MILLION REQUESTED BY
11 THE COMPANY TO BE VERIFIED AND APPROVED?
12 A. Since the Company has confirmed that the funds were spent on the project, Staff
13 recommends approval of the costs.
14 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
15 A. Yes.
16
17
18
19
20
15
BEFORE THE GEORGIA PUBLIC SERVICE COMMISSION
IN THE MATTER OF GEORGIA POWER COMPANY’S TWENTIETH AND TWENTY-FIRST SEMI-ANNUAL VOGTLE CONSTRUCTION MONITORING REPORT
DOCKET NO. 29849
PUBLIC DISCLOSURE
DIRECT TESTIMONY AND EXHIBITS
OF STEVEN D. ROETGER
WILLIAM R. JACOBS, JR., PhD.
ON BEHALF OF THE
GEORGIA PUBLIC SERVICE COMMISSION
PUBLIC INTEREST ADVOCACY STAFF
NOVEMBER 22, 2019
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1
2 Table of Contents
3 I. INTRODUCTION ...... 2
4 II. PROJECT STATUS...... 7
5 III. THE APRIL 2019 REBASELINE ...... 13
6 IV. CONSTRUCTION STATUS...... 18
7 V. IMPACTS OF OVERLY AGGRESSIVE SCHEDULE ...... 28
8 VII. REGULATORY ISSUES ...... 30
9 VIII. RECOMMENDATIONS ...... 33
10
11
12 Exhibits:
13 STF-SDR-1 Resume of Steven D. Roetger
14 STF-WRJ-1 Resume of William R. Jacobs, Jr., Ph.D.
15
1
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 I. INTRODUCTION
2 Q. PLEASE STATE YOUR NAMES, TITLES AND BUSINESS ADDRESSES.
3 A. My name is Steven D. Roetger. I am the lead analyst for the Georgia Public
4 Service Commission (“Commission”) Staff Public Interest Advocacy Team for the
5 Vogtle Construction Monitoring Docket 29849. My business address is 244
6 Washington Street, S.W., Atlanta, Georgia, 30334. My name is William R.
7 Jacobs, Jr., Ph.D. I am an executive consultant with GDS Associates, Inc. My
8 business address is 1850 Parkway Place, Suite 800, Marietta, Georgia, 30067.
9
10 Q. MR. ROETGER, PLEASE SUMMARIZE YOUR EDUCATIONAL
11 BACKGROUND AND EXPERIENCE.
12 A. I hold a Bachelor of Business Administration degree from Georgia State
13 University. I have been employed by the Georgia Public Service Commission
14 since September of 2008, primarily in the capacity as the team leader for the Plant
15 Vogtle Unit 3 and 4 Project under Docket 29849. Also, I was a member of the
16 Public Interest Advocacy Staff team for the Plant Vogtle Unit 3 and 4 Certification
17 (Docket 27800), and a Commissioner Advisory Staff team member for various
18 other proceedings. Prior to joining the Commission, I held various positions in
19 either an accounting or finance capacity for firms in different industries. My
20 resume is included in Exhibit STF-SDR-1.
21
2
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Q. DR. JACOBS, PLEASE SUMMARIZE YOUR EDUCATIONAL
2 BACKGROUND AND EXPERIENCE.
3 A. I received a Bachelor of Mechanical Engineering in 1968, a Master of Science in
4 Nuclear Engineering in 1969 and a Ph.D. in Nuclear Engineering in 1971, all from
5 the Georgia Institute of Technology. I am a registered Professional Engineer and a
6 member of the American Nuclear Society. I have more than forty years of
7 experience in the electric power industry including more than twelve years of
8 nuclear power plant construction and start-up experience. I have participated in the
9 construction and start-up of seven nuclear power plants in this country and
10 overseas in management positions including start-up manager and site manager.
11 As a loaned employee to the Institute of Nuclear Power Operations (“INPO”), I
12 participated in the Construction Project Evaluation Program, performed operating
13 plant evaluations and assisted in development of the Outage Management
14 Evaluation Program. Since joining GDS Associates, Inc. in 1986, I have
15 participated in rate case and litigation support activities related to power plant
16 construction, operation and decommissioning. I have evaluated nuclear power
17 plant outages at numerous nuclear plants throughout the United States. I served on
18 the management committee during construction of Plum Point Unit 1, a 650
19 Megawatts Electric (“MWe”) coal fired power plant. As a member of the
20 management committee, I assisted in providing oversight of the Engineering,
21 Procurement and Construction (“EPC”) contractor for this Project. I have assisted
22 the Georgia Public Service Commission as the Independent Construction Monitor
3
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 in providing oversight of the Vogtle 3 and 4 Project since August 2009. My
2 resume is included in Exhibit STF-WRJ-1.
3
4 Q. WHOM ARE YOU REPRESENTING IN THIS PROCEEDING?
5 A. We are representing the Commission’s Public Interest Advocacy Staff (“Staff”)
6 team in this matter.
7
8 Q. MR. ROETGER, WHAT IS YOUR INVOLVEMENT WITH THE VOGTLE
9 3 AND 4 PROJECT?
10 A. Since Docket No. 27800, I have been directly involved in the oversight of the Plant
11 Vogtle Unit 3 and 4 Project (“Project”) as lead analyst of the Staff Team. I have
12 closely monitored the Project with Dr. Jacobs since certification. Among other
13 oversight, along with Dr. Jacobs, I monitor the Project areas that either have
14 realized schedule delays or show a risk of potentially experiencing delay or
15 increased Project cost. I have testified in the Eighth through Nineteenth Semi-
16 Annual Vogtle Construction Monitoring (“VCM”) proceedings.
17
18 Q. DR. JACOBS, WHAT IS YOUR INVOLVEMENT WITH THE VOGTLE 3
19 AND 4 PROJECT?
20 A. I am the Commission’s Independent Construction Monitor (“CM”) for the Project.
21 My duties are to assist the Staff Team in its regulatory oversight of all aspects of
22 the Project and to keep the Commission informed of significant Project issues or
23 changes in the Project forecast Cost and Schedule as they occur. In addition, I
4
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 keep the Commission informed of significant challenges to the Project that could
2 impact the Project forecast Cost and/or Schedule. I have presented testimony in
3 the Plant Vogtle Unit 3 and 4 Certification (Docket 27800) and the First through
4 the Nineteenth Semi-Annual VCM proceedings describing the construction
5 monitoring activities, the status of the Project and any concerns or significant
6 issues.
7
8 Q. WHAT IS YOUR ASSIGNMENT IN THIS PROCEEDING?
9 A. Our assignment is to present the results of the Staff’s oversight from certification
10 of the Project to the present with emphasis on the time period covered by the
11 Twentieth and Twenty-First Semi-annual VCM Report, July 1, 2018 to June 30,
12 2019. In this testimony, we present our analysis of the current status of the Project
13 and discuss at a high level the status of the most recent forecast Schedule and Cost
14 provided by the Company and identify risks and areas of concern for the Project.
15 Details of the schedule and cost analyses are provided in the testimony of Mr. Don
16 Grace. Finally, we make a recommendation regarding Georgia Power Company’s
17 (“Company”) request for verification and approval of costs incurred during the
18 period in the amount of $1.248 billion.
19
20 Q. PLEASE DESCRIBE THE CONSTRUCTION MONITORING PROGRAM
21 THAT THE STAFF TEAM HAS IMPLEMENTED TO MONITOR THE
22 CONSTRUCTION OF THE VOGTLE 3 AND 4 PROJECT.
5
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 A. The Staff Team continues to actively monitor the Project. Monitoring activities
2 include monthly meetings between Staff and Company personnel to discuss
3 Project status and regular trips to the Vogtle Project site to observe the Monthly
4 Project Review (“MPR”) meeting and to witness firsthand construction activities’
5 progress. We review the Company’s Weekly Metrics reports, Monthly Update
6 Reports including addenda, and submit data requests to the Company for
7 additional information. The Team has continued its review of the Company’s
8 process for handling Project invoices from WEC1 and Bechtel2, and other
9 Company contractors. This includes review of the Project cost control procedures
10 and sampling of processed invoices. Other activities conducted by the Staff Vogtle
11 Construction Monitoring Team include:
12 Review of Monthly status reports issued by Bechtel and Westinghouse; 13 Review of the Company’s Semi-Annual VCM Reports; 14 Preparation of discovery requests for additional information as needed 15 following review of the monthly status reports, semi-annual 16 construction monitoring reports or meetings with the Company; 17 Attendance at management briefings by the Vogtle Construction 18 Review Board; 19 Participation in Nuclear Regulatory Commission (“NRC”) public 20 meetings in person and via conference call as appropriate; 21 Review of public correspondence between the Company and the NRC;
1 Westinghouse provides the engineering, design, and applicable analyses for the Design Certification Document (“DCD”). 2 Bechtel is the construction contractor.
6
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Review of correspondence between the Contractor and the Company; 2 Review of trade articles and journals related to new nuclear power plant 3 development; 4 Witnessing significant construction activities.
5 In addition, as described in our testimony in the Nineteenth VCM, the Vogtle
6 Project monitoring activities by Staff and the Construction Monitor have been
7 augmented by the addition of the Vogtle Monitoring Group (“VMG”) personnel to
8 the Staff team. VMG activities include a fulltime experienced construction
9 manager stationed at the Vogtle site and detailed schedule and cost analyses as
10 presented in Mr. Grace’s testimony.
11
12 II. PROJECT STATUS
13 Q. PLEASE DESCRIBE THE CURRENT STATUS OF THE PROJECT.
14 A. Construction continues on the Vogtle Project with SNC’s emphasis being on
15 completion of systems for turnover to the Initial Test Program (“ITP”) Group.
16 Through September 2019, the total Project is reported to be 81.3% complete
17 compared to a plan of 82.3% which are based on a weighted average of the Project
18 components as shown below:
Project Phase September 2019 September 2019
Plan Actual
Engineering 98.7% 98.6%
7
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
Procurement 97.5% 97.1%
Construction 74.5% 73.0%
Bechtel 71.5% 69.3%%
Direct Subs 80.2% 79.8%%
I&C/Cyber Security 98.9% 98.7%
Initial Test Program 19.8% 17.4%
Total Project 82.3% 81.3%
1
2 Q. HAS THE PROJECT ACCOMPLISHED MAJOR CONSTRUCTION
3 MILESTONES DURING THE 20TH – 21ST VCM PERIOD?
4 A. Yes, several significant construction milestones have been accomplished during
5 the 20th – 21st VCM period. These milestones include:
6 Set Unit 3 Containment Vessel Top Head;
7 Commence Unit 3 Initial Energization;
8 All Major Modules Delivered to Site;
9 Set Unit 4 Reactor Vessel and Pressurizer;
10 Complete the Raw Water and Cooling Water Intake Structure.
11 However, in spite of achieving these construction milestones, construction
12 progress on the Project fell far behind the production needed to achieve what was
13 called the +21-month schedule with a Unit 3 COD of April 14, 2019. In our
14 testimony in the 19th VCM we identified many concerns with the Project’s ability
15 to meet the required production while transitioning the Project from the bulk
8
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 construction mode to system completion and turnover. We concluded that “Staff
2 believes that the +21-month schedule is highly unlikely to be achieved.” As
3 discussed in the next section of this testimony, the challenges to construction
4 production and system turnover necessitated the development of a new baseline
5 schedule in April 2019.
6
7 Q. DOES SNC USE MILESTONES TO ASSESS PROGRESS ON THE
8 PROJECT?
9 A. Yes. At the end of each year SNC develops a series of quarterly milestones that
10 are to be met the following year.
11
12 Q. DOES STAFF HAVE ANY CONCERNS WITH THE USE OF
13 MILESTONES AS A PRIMARY MEANS OF DETERMINING THE
14 STATUS OF WORK COMPLETED ON THE PROJECT?
15 A. Yes. Each milestone must be carefully selected so that it is indicative of actual
16 work performed. For example, SNC selected ‘Start of Integrated Flush’ as a Major
17 Milestone to be accomplished in the third quarter of 2019. SNC did meet this
18 Major Milestone. The issue, however, is that the ‘Start’ of any activity could
19 constitute the laying of only several feet of cable or installing one pipe hanger.
20 The critical milestone, in Staff’s opinion, is not the ‘Start’ of an activity but rather
21 the ‘Finish’ of an activity.
22
9
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Q. CAN INAPPROPRIATE MAJOR MILESTONES MASK THE ACTUAL
2 PROGRESS ON THE PROJECT?
3 A. Yes. Please see the table below.
Hours Ahead (Behind) Plan vs. Milestones Met 1st Qtr 2nd Qtr(1) 3rd Qtr 4th Qtr(2) Number of Milestones 4 3 3 5 Met Milestones 4 3 3 3
Cumulative Unit 3 Plan vs. Actual(3) (988,000) (141,896) (533,242) (639,512) Cumulative Unit 4 Plan vs. Actual (289,901) 84,610 137,415 116,213 Cumulative BOP(4) Plan vs. Actual (28,331) 12,440 88,536 106,304
Total deficit hours (1,306,232) (44,846) (307,291) (416,995) (5) Source 3/31 SC 6/30 SC 9/29 SC 3/31 SC
(1) April 2019 Baseline; pushed deficit hours to the future; shifted COD from April to May 2021 and 2022. (2) 4th quarter ends 12/31/2019; cumulative hours as of 10/31/2019 (3) Plan hours; ahead of Plan positve number; behind Plan negative number (4) Balance of Plant (5) 4 SC = Scorecard
5 As shown on this Table, all Major Milestones selected by SNC have been achieved
6 as of the filing of this testimony. However, the backlog of hours to complete the
7 Project since the second quarter have steadily increased during 2019 and, in Staff’s
8 opinion, will continue to increase.
9
10 Q. WHY DOES THE DEFICIT IN HOURS DECREASE IN THE SECOND
11 QUARTER?
10
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 A. This is due to the April 2019 Baseline. The deficit hours prior to the April 2019
2 Baseline were re-distributed to future months.
3
4 Q. DOES STAFF BELIEVE THIS DEFICIT IN EARNED HOURS TO BE
5 ACCURATE?
6 A. No. As is shown in the Don Grace testimony, the assumed unit rates in the 2019
7 Baseline are, for many commodities, understated. If actual experienced unit rates
8 are substituted for the assumed unit rates, the deficit would be larger. Actual
9 experienced unit rates by commodity are discussed in more detail in the Don Grace
10 testimony.
11
12 Q. HOW LARGE HAS THE DEFICIT FOR UNIT 3 ELECTRICAL
13 COMMODITIES GROWN SINCE THE APRIL 2019 BASELINE TO
14 DATE?
15 A. Please see the graph below. As shown, the current deficit is approximately
16 640,000 hours.
11
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1
2
3 Q. HOW HAVE THE CUMULATIVE BACKLOG OR SURPLUS OF
4 PLANNED HOURS BY COMMODITY AND UNIT 3 AND UNIT 4 FAIRED
5 SINCE THE APRIL 2019 BASELINE?
6 A. The first graph below represents Unit 3 and the second graph represents Unit 4.
7 For Unit 3 Above Ground Piping and Electrical have fallen behind the April 2019
8 Baseline almost since its issuance. For Unit 4, Electrical and Civil, since August,
9 have shown a negative trend.
12
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 2
3 4
5 III. THE APRIL 2019 REBASELINE
6 Q. WHY WAS A NEW SCHEDULE BASELINE NEEDED IN APRIL 2019?
7 A. As Staff has continually stated since the Sixth VCM and as affirmed in INPO
8 Principle for Excellence in Nuclear Construction No. 4, schedules must be realistic
13
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 and understood. A realistic schedule drives many critical elements of project
2 management including construction priorities, procurement needs and staffing
3 requirements. In addition, comparison of the Project status to a realistic schedule
4 allows project management to identify problem areas and develop possible
5 mitigation strategies. Without a realistic, achievable schedule, project
6 management is typically in a poor position to support all the disciplines needed for
7 a project. Project management often finds itself fighting fires because long range
8 planning is not effective to identify upcoming problems with sufficient time and
9 resources to take proper corrective actions. By the end of 2018, it was clear that
10 the Project Schedule was not realistic or achievable and thus was not a viable
11 management tool. Staff believes another consequence of not having such a
12 schedule was that it was difficult for stakeholders to determine the true completion
13 status of work and the work that remains.
14
15 Q. PLEASE DESCRIBE THE RESULTS OF THE APRIL 2019 SCHEDULE
16 REBASELINE3.
17 A. The work done on the April 2019 Baseline resulted in some improvements when
18 compared to the June 2018 baseline. These improvements are discussed in Staff’s
19 July 30, 2019 report on the April 2019 Vogtle Unit 3 and 4 Re-baseline of Forecast
20 Cost and Schedule and include:
3 Staff will refer the prior re-baselined Integrated Project Schedule (“IPS”) and Estimate at Completion (“EAC”) as the June 2018 Baseline and the April 2019 Baseline.
14
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Integration of sub-contractor work;
2 Additional detail in construction and ITP schedule logic;
3 Additional resource loading;
4 Reduction in the number of hard constraints;
5 Verification of to-go commodity quantities.
6 However, the primary result of the April 2019 Baseline was a relatively small
7 change in the forecast CODs from April 14, 2021 to May 23, 2021 for Unit 3 and
8 from April 25, 2022 to May 23, 2022 for Unit 4.
9
10 Q. IN ITS JULY 30, 2019 REPORT, STAFF IDENTIFIED SEVERAL
11 CONCERNS WITH THE APRIL 2019 BASELINE. HAVE THESE
12 CONCERNS BEEN REALIZED IN THE PERIOD SINCE YOUR JULY
13 30TH REPORT?
14 A. Yes, they have. Only four months after issuance of the April 2019 Baseline, it is
15 no longer relevant to the Project. The actual status of construction is many hours
16 behind the April 2019 Baseline and system turnovers to ITP are several months
17 delayed. In Staff’s opinion, the April 2019 Baseline is no longer a relevant
18 benchmark for SNC and Bechtel to manage, or status. the Project. Many System
19 turnovers are 90 days or more later than shown in the April 2019 Baseline. In
20 other words, in the four months since the April 2019 Baseline was established,
21 these system turnovers have slipped 90 days.
22
15
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Q. DOES STAFF EXPECT THIS TREND OF UNDER-EARNING CRAFT
2 HOURS AND DELAYS WITH SYSTEM TURNOVERS TO CONTINUE?
3 A. Yes. Without significant improvements in production, productivity and planning
4 i.e. a realistic schedule forecast, Staff believes this trend will continue.
5
6 Q. HOW DID SNC MEET THE ‘START INTEGRATED FLUSH’
7 MILESTONE ACTIVITY?
8 A. The Project managed to achieve the “Start Integrated Flush (“IF”)” milestone by
9 using the Partial Release for Test (“PRT”) process, which allows some testing to
10 be done on piping and components that are not turned over to ITP as scheduled, by
11 performing a flush on a small length of pipe. Use of the PRT process and the
12 negative impacts is described later in this testimony.
13
14 Q. WHY IS ACTUAL CONSTRUCTION PROGRESS SIGNIFICANTLY
15 BEHIND THE APRIL 2019 BASELINE ONLY FIVE MONTHS AFTER
16 THE BASELINE WAS ISSUED?
17 A. In our opinion, the primary reason that construction progress is far behind the
18 April 2019 Baseline is that the schedule assumptions including unit rates were,
19 from the outset, unrealistic and unachievable. As a result, in order to meet the
20 April 2019 Baseline, the unit rates used to develop the April 2019 Baseline were
21 not achievable and were not based on experienced actual unit rates that have been
22 achieved on the Project to date.
23
16
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Q. PLEASE EXPLAIN THE TERM UNIT RATE AND WHY IT IS
2 RELEVANT TO THIS DISCUSSION.
3 A. A unit rate is the estimate of the number of hours required to complete installation
4 of a unit of commodity such as feet of pipe or cable. For the April 2019 Baseline,
5 the unit rates were based, with a few minor exceptions, on the unit rates
6 established by Fluor and Westinghouse in 2017 and incorporated in the Bechtel
7 contract which, as shown in Mr. Grace’s testimony, are much lower than the actual
8 experienced unit rates achieved on the Project. The use of unrealistically low unit
9 rates results in fewer man-hours and implies shorter activity durations than are
10 realistic or achievable. This usually leads to delays in system turnovers because
11 completion of construction is later than planned.
12
13 Q. DOES STAFF ANTICIPATE ANOTHER RE-BASELINE IN THE NEAR
14 FUTURE?
15 A. Yes, Staff anticipates that a new forecast of Schedule and Cost will be issued in
16 early 2020.
17
18 Q. WHAT IS STAFF’S EXPECTATION FOR THE SCHEDULE RE-
19 FORECAST?
20 A. Staff expects that the upcoming reforecast may again be overly aggressive and
21 result in small, incremental delays to the forecast CODs of both units. Staff’s
22 concern is that the forthcoming re-baseline will again be unrealistic and therefore
23 become irrelevant within a short period of time after issuance. It may logically lay
17
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 out the activities to complete Unit 3 and 4 but the explicit production and
2 productivity assumptions may again be overly aggressive.
3
4 Q. CAN BECHTEL BE FINANCIALLY AT RISK FOR THE DELAY OF
5 COMMERCIAL OPERATION OF THE UNITS?
6 A. No. Bechtel and for the most part, all of the sub-contractors working on the site,
7 will be made whole because of the Time and Materials nature of these contracts.
8 The Company agreed with the characterization that Bechtel gets paid for every
9 hour worked. (Transcript, Abramovitz, p. 58). Bechtel does have an “At Risk” fee
10 in their contract. However, Bechtel has the opportunity to submit construction
11 trends to protect that fee.
12
13 IV. CONSTRUCTION STATUS
14 Q. PLEASE PROVIDE THIS COMMISSION AN UPDATE ON THE
15 CONSTRUCTION STATUS OF THE VOGTLE PROJECT.
16 A. Unfortunately, it is difficult to provide such an update because there is no relevant
17 baseline schedule against which to compare the current status of the Project. As of
18 September 2019, SNC states that construction was 73.0% complete. However,
19 without a realistic Schedule we cannot confirm the percent complete. Staff can
20 state that because it is significantly behind the schedule established in the April
21 2019 Baseline and because many more hours than planned are being required to
18
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 complete construction activities, the percent may not accurately represent the
2 balance of work needed to attain the May CODs.
3
4 Q. BASED ON STAFF’S KNOWLEDGE CAN STAFF PREDICT WITH ANY
5 CERTAINTY WHEN THE CODS WILL BE ACHIEVED?
6 A. This question could be answered if the schedule was realistic. But without an IPS
7 based on realistic and achievable unit rates, an estimate of Project completion is
8 simply an educated guess. When asked if the Company used actual rates that
9 might have projected a more realistic duration on unit rate, Company Witness
10 Abramovitz responded by stating that, “…we did not change the unit rates from
11 2018. (Transcript, Abramovitz p. 57). The status of direct construction on the
12 Project, which is primarily the nuclear island, the power block and some Balance
13 of Plant for Units 3 and 4, is shown in the figure below.
19
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1
2 This figure shows that the overall Project is falling behind the April 2019 baseline.
3 As shown below the situation is worse when looking at Unit 3 in isolation.
4
5
20
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1
2 As shown above, the divergence of the green line from the dotted line represents
3 direct construction falling behind the April 2019 Baseline.
4
5 Q. WHAT IS THE PRIMARY DRIVER FOR THE CONSTRUCTION
6 SCHEDULE?
7 A. The primary driver of the construction schedule is to meet the required system
8 turnovers to ITP.
9
10 Q. HOW HAS THIS FOCUS ON SYSTEM TURNOVERS IMPACTED THE
11 PROJECT?
21
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 A. The construction focus on system turnovers has negatively impacted the Project’s
2 ability to meet the required earned hours to support the Project Schedule. Work
3 related to system completion is tedious and typically results in fewer earned hours.
4 The most efficient approach to earning hours is in bulk construction where, for
5 example, all the electrical cables needed in a given area are pulled at the same time
6 rather than pulling just a few cables needed for a specific system turnover. SNC
7 has stated that its primary approach is to support system completion and turnover
8 to support the ITP Schedule. Since adoption of that approach, the Project has not
9 achieved the required earned hours each month.
10
11 Q. HOW DOES SNC PROPOSE TO RECOVER THE CURRENT DELAYS
12 COMPARED TO THE APRIL 2019 BASELINE?
13 A. Many Project documents state that schedule mitigation activities are being
14 implemented or schedule mitigation activities are being evaluated to recover the
15 current delays. We have heard this terminology many times throughout the course
16 of the Vogtle Project and our observation and experience has been that the Project
17 has implemented many mitigation strategies and improvement plans with little to
18 no significant impact on recovery of delays on the Project. At best, these plans
19 tend to prevent further delays in construction or system turnovers, but have not
20 been able to recover existing schedule delays.
21
22 Q. SNC HAS STATED THAT IT WILL UTILIZE “MANAGEMENT TIME”
23 TO MAINTAIN THE CURRENT SCHEDULE. WHAT IS
22
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 “MANAGEMENT TIME” AND WHAT IS YOUR OPINION OF ITS USE
2 TO MAINTAIN THE CURRENT SCHEDULE?
3 A. SNC has identified some periods in the current schedule in which they believe that
4 less time will be required during that period to complete the scheduled activities
5 than what is shown in the schedule. This is more typically called “schedule float”
6 but it is called “management time” on the Vogtle Project. SNC believes that
7 of management time is available in the Unit 3 Schedule between Open
8 Vessel Testing (“OVT”) and COD. Our first observation is that the management
9 time identified by the Company is based on everything going perfectly in the
10 remaining construction and commissioning testing activities. SNC’s position
11 seems to be that while to date the Project has incurred delays at every point, in the
12 future, construction and testing activities will be completed within the time allotted
13 in the Schedule. As a former startup manager at two nuclear plants, I (Dr. Jacobs)
14 assure you that everything will not go perfectly. Problems will be found with
15 equipment and systems that will require time to correct and re-test.
16
17 Q. HAS ITP ENCOUNTERED PROBLEMS TO DATE DURING THE EARLY
18 TESTING ACTIVITIES?
19 A. Yes, ITP has encountered numerous problems during the early phase of flush and
20 hydro and component testing. These problems include:
21 Numerous leaks in the fire protection system during initial hydro testing;
22 High vibrations on the spent fuel system pumps during initial component
23 testing;
23
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Current imbalance issue on the Normal Residual Heat Removal pump motor
2 during initial testing;
3 Numerous issues with system valves;
4 Control circuits for 6.9kV/480V transformer not installed;
5 Numerous issues with circuit breakers.
6
7 Q. IN YOUR EXPERIENCE, HAS THE PROJECT ENCOUNTERED AN
8 ABNORMAL AMOUNT OF PROBLEMS DURING INITIAL TESTING?
9 A. No, the level of problems encountered has not been abnormal to date. One of the
10 major objectives of the Test Program is to find problems and correct them. We
11 mention these examples of problems found during testing to emphasize the point
12 that it is not realistic to assume that testing will be completed within the scheduled
13 durations and that schedule float or management time will be available during the
14 testing windows. In addition, the late turnover of systems to ITP will result in
15 compression of the time available to complete many preoperational tests. As these
16 preoperational tests stack up, the capability of ITP to complete them during the
17 Scheduled durations will be challenged.
18
19 Q. AS THE PROJECT HAS ENTERED THE EARLY TESTING PHASE,
20 PLEASE BRIEFLY DESCRIBE THE TESTING REQUIRED TO START
21 UP A NUCLEAR POWER PLANT.
22 A. The equipment that makes up a nuclear power plant is divided into many systems.
23 The Vogtle Units are each broken down into approximately 104 systems. Some
24
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 systems contain only electrical equipment while other systems consist of piping,
2 valves, pumps and other mechanical equipment along with the electrical equipment
3 required to operate these components. Testing typically begins with cleaning
4 piping systems, called flushing and testing the piping systems to ensure they are
5 capable of withstanding the designed pressures, called hydrostatic testing or
6 hydros. Then individual components such as pumps and valves are tested to
7 ensure they are operating within design parameters.
8 As systems are completed and turned over from construction, Pre-operational
9 Testing can begin. Pre-operational Tests confirm the functionality of the full
10 system and verify the system operates per design. Completion of Pre-operational
11 Testing leads to a significant test called Hot Functional Testing (“HFT”). During
12 HFT, the Reactor Coolant System is operated at normal operating temperature and
13 pressure and a large portion of the plant is tested in an integrated fashion to verify
14 that plant systems and the integrated plant operates per design prior to fuel load.
15 The final steps in the Startup Program are loading the nuclear fuel and then testing
16 the plant at increasing power levels leading to 100% power and finally
17 Commercial Operation.
18
19 Q. WITH THE TURNOVER OF SYSTEMS APPROXIMATELY THREE
20 MONTHS BEHIND SCHEDULE, HOW HAS SNC CONTINUED WITH ITP
21 ACTIVITIES AND MET MAJOR MILESTONES SUCH AS START
22 INTEGRATED FLUSH?
25
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 A. The Project uses a process called Partial Release for Test (“PRT”). The PRT
2 process allows jurisdictional control of a portion of a system to be transferred to
3 ITP to conduct testing activities prior to final turnover of that system. Once the
4 testing activities are complete, ITP returns jurisdictional control to Construction to
5 complete the system. This process allows ITP to conduct flushing, hydro and
6 component testing activities prior to turnover of a complete or partial system.
7
8 Q. IS THE PRT PROCESS A REASONABLE APPROACH TO CONDUCT ITP
9 ACTIVITIES?
10 A. It is reasonable to use the PRT process to conduct some testing activities prior to
11 turnover. The question is a matter of to what degree it should be used. On the
12 Vogtle Project, a large portion of the testing activities to date have been conducted
13 using the PRT process rather than on systems that have been turned over to ITP as
14 originally contemplated. SNC has stated that they are using the PRT process to
15 mitigate the impact of the late system turnovers. For example, the Project met the
16 major milestone of ‘Start Integrated Flush’ by using the PRT process to turnover a
17 small portion of piping for flushing and have used the process to continue with
18 Integrated Flushing activities. Use of the PRT allows some testing to be done
19 sooner than could otherwise be accomplished due to the late system turnovers from
20 Construction. However, meeting major milestones using this process can give a
21 false impression of the status of the Project. In addition, extensive use of the PRT
22 process greatly complicates and impedes Construction due to the change in
23 jurisdictional control to ITP and then back to Construction. Construction is often
26
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 left waiting to get back into a system to complete it while ITP completes its testing
2 activities. It would be much more efficient to fully complete a system and then
3 turn the system over to ITP for testing rather than changing jurisdictional control
4 multiple times between construction and ITP by using the PRT process.
5
6 Q. IN ADDITION TO THE NEGATIVE IMPACT ON CONSTRUCTION
7 EFFICIENCY AND PRODUCTION, WHAT OTHER CONCERNS DO YOU
8 HAVE ABOUT THE EXCESSIVE USE OF THE PRT PROCESS?
9 A. Conducting testing in locations in which construction is also underway requires
10 close coordination and control of equipment to ensure that construction and/or
11 operating personnel are not in danger. Two recent examples from the Project
12 highlight this concern:
13 On 11/8/2019 night shift ITP was conducting a test on the Chemical and
14 Volume System. A valve was not in the required closed position and water
15 entered the room where electricians were working. Two electricians were
16 injured while trying to exit the room.
17 On 11/7/2019 while restoring the PXS system after conducting a flush, argon
18 gas was vented from Core Makeup Tank A into a room where construction
19 personnel were working. An air quality alarm went off and the room was
20 evacuated.
21 The more the PRT process is used and construction personnel are working in close
22 proximity to testing activities, the more likely these types of events are to occur.
27
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 V. IMPACTS OF OVERLY AGGRESSIVE SCHEDULE
2 Q. DOES STAFF BELIEVE THERE ARE RISKS ASSOCIATED WITH THE
3 USE OF AN OVERLY AGGRESSIVE SCHEDULE?
4 A. Yes. First, Staff does agree with SNC that the Schedule should be challenging to
5 ensure that all parties involved in the completion of the Project are pushed to
6 perform to their utmost efficiency. However, Staff is of the opinion that the Target
7 CODs of May 2021 and 2022 are not reasonable. The primary reason for this
8 belief is discussed in the Grace Testimony regarding unattainable assumed unit
9 rates in the April 2019 Baseline.
10
11 Q. WHAT IS THE PRIMARY RISK THAT STAFF SEES WITH AN OVERLY
12 AGGRESSIVE SCHEDULE?
13 A. Lack of accountability for completion of activities. The April 2019 Baseline is one
14 of the critical metrics by which SNC can hold Bechtel and all other sub-contractors
15 accountable for work production. Staff believes that it is essential for activity
16 durations to be reasonable and achievable. With the absence of these two qualities
17 for activity durations, completion dates begin to shift to the right (they are delayed)
18 without much questioning from line management.
19
20 Q. HAS STAFF WITNESSED THIS LACK OF QUESTIONING REGARDING
21 SHIFTS TO THE RIGHT OF ACTIVITY COMPLETION DATES?
28
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 A. Yes. Staff has been present in many meetings where an activity date is declared
2 unachievable by the responsible manager. Most often the team is told that the
3 completion date can be met X number of days in the future without any challenge
4 from leadership in the room. This practice is then often repeated until a reasonable
5 date is finally declared.
6
7 Q. WOULD IT BE REASONABLE TO HOLD A MANAGER RESPONSIBLE
8 FOR COMPLETING AN ACTIVITY WHEN THE DURATION OF THAT
9 ACTIVITY IS UNREASONABLY SHORT?
10 A. No, it would not.
11
12 Q. ARE THERE OTHER POTENTIAL NEGATIVE IMPACTS THAT CAN
13 DEVELOP AS A RESULT OF AN OVERLY AGGRESSIVE SCHEDULE?
14 A. Yes. For the most part they are self-explanatory and are listed below:
15 Low staff morale; 16 Staff attrition; 17 High absenteeism; 18 The need for accelerated procurement; 19 Construction and Engineering’s inability to close work packages; 20 Future bow wave of work that must be completed in an ever shrinking time- 21 frame. 22
23 Q. WHAT IS THE CONSEQUENCE OF THE LAST BULLETED ITEM
24 ABOVE?
25 A. Essentially it takes the overly-aggressive Schedule and inserts even more work into
26 what time remains.
29
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 Q. WHEN MUST ESSENTIALLY ALL CONSTRUCTION BE COMPLETE
2 FOR UNIT THREE?
3 A. With very few exceptions construction must be complete just prior to fuel load. In
4 order for nuclear fuel to be on site at Unit 3, Unit 3 and the majority of Balance of
5 Plant structures must be incorporated into the Station’s (Unit 1, Unit 2, and Unit 3)
6 security perimeter. At that time, it would be very difficult to plan for efficient
7 egress of craft workers into Unit 3. Fuel load is scheduled for November of 2020
8 which equates to about one year to finish all construction.
9
10 VII. REGULATORY ISSUES
11
12 Q. HAS THE DEFINITION OF COMMERCIAL OPERATION BEEN
13 DEFINED IN A STIPULATION BETWEEN THE COMPANY AND
14 STAFF?
15 A. Yes. From the stipulation adopted by the Commission dated October 20th, 2016
16 between Staff and the Company line items twelve and thirteen state Commercial
17 Operation (per unit) has been defined as follows:
18 The Projects, consisting of Units 3 and 4, will be placed into retail 19 rate base on December 31, 2020 or upon reaching commercial 20 operation whichever is later. 21 22 Commercial Operation of a Unit as used in this Stipulation will be 23 defined as the Unit being fully dispatchable on demand at the 24 stated Net Electrical Output of 1,102MWe of the Unit. For 25 ratemaking purposes, the Units will not be included in base rates
30
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 until December 31, 2020 or when the Units reach Commercial 2 Operation, whichever is later. 3
4 Q. DOES THIS DEFINITION CONTEMPLATE ANY FINANCIAL
5 ACCOUNTING CRITERIA FOR DECLARING COMMERCIAL
6 OPERATION?
7 A. No. If it did contemplate financial accounting criteria the Stipulation
8 would have expressly stated so. It is Staff’s opinion that for each of the
9 Units to be placed into base rates each Unit, mutually exclusive of the
10 other, must perform as stated in the Stipulation. Furthermore, because
11 these Units are nuclear generation, the dispatch is to be assumed twenty-
12 four hours a day, seven days a week, until a scheduled outage is required.
13 As the newly completed AP1000 Sanmen 2 has demonstrated, simply
14 because a Unit starts producing power does not mean that the Unit will
15 function as intended. It is important that the Units have demonstrated that
16 they work as intended before ratepayers are asked to pay for them.
17
18 Q. ARE THERE OTHER CRITERIA UNDER WHICH PROJECT
19 COSTS ARE GOVERNED BY STIPULATIONS?
20 A. Yes. From the same Stipulation line items four and five state the burden
21 of proof for disallowance of costs are borne as follows:
22 4. Capital costs incurred up to $5.68 billion will be 23 presumed to be reasonable and prudent. The burden of 24 proof shall be on the party challenging those costs. 25
31
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 5. The Company will have the burden to show that Capital 2 costs above the revised forecast of $5.68 billion are 3 reasonable and prudent. 4
5 Q DOES LINE ITEM 4 FROM THE STIPULATION ABOVE
6 FOREGO THE OPPORTUNITY OF A PARTY FROM
7 CHALLENGING CAPITAL COSTS UP TO $5.68 BILLION?
8 A. No. Item one of the Stipulation deemed capital costs incurred by the
9 Company through the end of the Fourteenth VCM prudent, with the
10 exception that if any system, structure, or component embedded in that
11 capital cost through the Fourteenth VCM does not perform per the design
12 “…The Commission expressly reserves its right to review and disallow
13 any cost and or schedule impacts of such deficiency.” Cost between
14 those incurred through the Fourteenth VCM of approximately $3.5 billion
15 were therefore deemed prudent. Costs incurred after the 14th VCM up to
16 the $5.68 billion are challengeable, with the burden of proof on the party
17 challenging the cost. For costs above $5.68, the burden to show prudence
18 is the Company’s responsibility.
19
20 Q WITH THE CURRENT COMPANY CAPITAL COST FORECAST
21 TO COMPLETE BOTH UNITS AT $7.3 BILLION, WHAT
22 AMOUNT MUST THE COMPANY SHOW TO BE PRUDENTLY
23 INCURRED?
32
PUBLIC DISC. Direct Testimony of Steven D. Roetger, William R. Jacobs, Jr., Ph.D. Docket No. 29849, 20th-21st Semi-Annual Vogtle Construction Monitoring Period
1 A. It is the difference between the $7.3 billion current capital forecast and
2 the $5.68 billion which is $1.62 billion. If costs exceed $7.3 billion, the
3 Company would also have the burden of proof on those additional costs.
4
5 VIII. RECOMMENDATIONS
6
7 Q. WHAT IS STAFF’S RECOMMENDATION WITH REGARD TO THE
8 AMOUNT REQUESTED BY THE COMPANY TO BE VERIFIED AND
9 APPROVED?
10 A. We recommend that the expenditures of $1.248 billion incurred during the
11 Twentieth and Twenty-First VCM periods be verified and approved. As Staff has
12 previously explained, “verification and approval” of costs means a determination
13 that such costs have actually been spent on the Project and does not preclude a
14 subsequent disallowance by the Commission.
15
16 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
17 A. Yes, it does.
33
EXHIBIT STF-SDR-1
Resume Of
Steven D. Roetger
- 1 -
Resume of Steven D. Roetger
Steven D. Roetger 244 Washington Street, S.W. Atlanta, GA 30334
Professional Experience Georgia Public Service Commission Atlanta, Georgia 2008-Present Analyst Primary responsibilities include monitoring the Vogtle expansion of Units 3 and 4, attending site visits on a regular basis, participate with the Commission and Company interface, and assist in the preparation of testimony. Key achievements Manage the Vogtle Construction monitoring process including engineering, procurement, and construction; economic analysis of the value of the Project; and financial accounting review for the Project’s costs. Write and review direct pre-filed testimony of the status of the Project for a semi-annual hearings.
BCD Travel Atlanta, Georgia 2007-2008 Finance Manager Primary responsibilities were to manage financial analysts, generate and review variance analyses, analyze departmental financials, and facilitate the coordination between our group and various internal departments. Key achievements Elevated team's performance to improve consistency, accuracy, and timeliness of service Identified client missed revenue opportunities and communicated to Operations for recapture and/or inclusion with future invoicing Key Requirements Train, motivate, and develop 3 financial analysts to achieve an outstanding level of service and performance Direct work flow to maintain efficiency and productivity without compromising standards Analyze departmental financials to maximize profitability by reviewing contracts, perform variance analyzes, and ensure complete transaction billing Review complex contracts and interpret for finance reconciliation and billing procedures Prepare client budgets and forecasts
Marine Bank of Florida Marathon, Florida2003-2005 Accounting Operations Manager/Bank Officer Primary responsibilities were to manage the Bank's Accounting Department and, as directed by the COO, Deposit Operations' functions. Key achievements Identified high-risk, time sensitive accounts for dedicated review to significantly reduce financial risk to the Bank In partnership with the CFO reduced audit management exceptions from 13 to zero year over year Launched new wire department procedures to decrease response time, increase capacity, and improve customer service without increasing staff
Resume of Steven D. Roetger
In partnership with the COO implemented the Bank's new ACH operations to enhance existing customer relations, attract new business, and respond in a timely manner to ACH adjustments/returns Key Requirements Comprehensive G/L management including reconciliations, adjusting entries, and monthly/annual close Manage and review the activities of 3 accounting and 2 deposit operations personnel responsible for accounts payable, wires, ACH operations, VISA check card operations, branch settlements, electronic funds transfers, and check clearing. Establish and refine departmental policies and procedures to improve accuracy and timeliness of reporting, facilitate employee transition, and meet audit requirements Oversaw Federal Reserve, FHLB, and IBB correspondent accounts Supported the CFO to meet external audit requirements Oversaw the Bank's daily cash position to minimize overnight net interest expense Support branch operations by assisting branch managers maintain acceptable internal controls, provide training on Bank reporting procedures, and process exceptions
B. Terfloth &Co. USA) Inc. Atlanta, Georgia 1998-2000 Accounting Manager Primary responsibilities were to manage the Branch's Accounting Department with an emphasis on controlling expenses and manage the yearly audit process. Key achievements Re-established accurate and timely monthly reporting to the Corporate Office Developed a cash flow forecasting model to assess the Branch's financing needs and negotiated under the President's supervision a working capital credit line to meet those needs Key requirements Comprehensive G/L management including reconciliations, adjusting entries, and monthly/annual close Manage the annual audit process Accounts payable and accounts receivable Payroll and annual bonus calculations
Bridgetown Grill Restaurants Inc. Atlanta, Georgia1996-1997 Interim Controller Primary responsibilities were to re-establish a reliable Accounting process and once established facilitate the transition to a new Controller. Key achievements Established internal controls to better manage purchases, inventories, and reduce cash variances Developed Accounting procedures for Unit Managers and trained the management staff on those procedures Assisted the Owner in evaluating an outside purchase offer Key requirements Comprehensive G/L management including reconciliations, adjusting entries, and monthly close procedures Coordinate the annual audit process Manage accounts payable and payroll processing Manage credit card transaction procedures to reduce charge backs
Resume of Steven D. Roetger
Turner Broadcasting System Inc. Atlanta, Georgia 1991-1996 Staff Accountant Primary responsibility was to support the Managers with accurate and timely completion of assigned tasks. Key achievements Partnered with Management to streamline the procedure for The Statement of Cash Flows Corrected the EPS calculation Streamlined governmental reporting and incorporated detailed procedures for each report Provided a Companywide vacation and sick time accrual analysis Key requirements Worked, as part of a team, on the Consolidated Financial Statements of TBS, Inc. Develop various footnotes to the Financial Statements Provide analysis of accounts for actual to budget and actual to rolling12 month forecast variances Provide analysis of, and recommendations for, lease capitalizations Coordinate with 72 Operating Unit Controllers for the content and timely receipt of Unit financial data Prepare debt covenant calculations for 4 issues and provide forecasts with sensitivity analysis Prepare all U.S. Department of Commerce and U.S. Treasury Department statistical reports
Software PeopleSoft/nVision reporting, Kirchman/Bankway and IPS Sendero banking software, MSA accounting software, Excel, Outtask, and Word
Education
BBA Georgia State University in Finance with an equivalent in Accounting Completed 70 percent of course work toward an MBA in Finance from Georgia State University
Resume of William R. Jacobs, Ph.D.
EXHIBIT STF- WRJ-1
Resume Of
William R. Jacobs, Ph.D.
EDUCATION: Ph.D., Nuclear Engineering, Georgia Tech 1971 MS, Nuclear Engineering, Georgia Tech 1969 BS, Mechanical Engineering, Georgia Tech 1968
ENGINEERING REGISTRATION: Registered Professional Engineer
PROFESSIONAL MEMBERSHIP: American Nuclear Society
EXPERIENCE:
Dr. Jacobs has over thirty-five years of experience in a wide range of activities in the electric power generation industry. He has extensive experience in the construction, startup and operation of nuclear power plants. While at the Institute of Nuclear Power Operation (INPO), Dr. Jacobs assisted in development of INPO’s outage management evaluation group. He has provided expert testimony related to nuclear plant operation and outages in Texas, Louisiana, South Carolina, Florida, Wisconsin, Indiana, Georgia and Arizona. He currently provides nuclear plant operational monitoring services for GDS clients. Dr. Jacobs was a witness in nuclear plant certification hearings in Georgia for the Plant Vogtle 3 and 4 project on behalf of the Georgia Public Service Commission and in South Carolina for the V.C. Summer 2 and 3 projects on behalf of the South Carolina Office of Regulatory Staff. His areas of expertise include evaluation of reactor technology, EPC contracting, risk management and mitigation, project cost and schedule. He is assisting the Florida Office of Public Counsel in monitoring the development of four new nuclear units in the State of Florida, Levy County Units 1 and 2 and Turkey Point Units 6 and 7. He also evaluated extended power uprates on five nuclear units for the Florida Office of Public Counsel. He has been selected by the Georgia Public Service Commission as the Independent Construction Monitor for Georgia Power Company’s new AP1000 nuclear power plants, Plant Vogtle Units 3 and 4. He has assisted the Georgia Public Service Commission staff in development of energy policy issues related to supply-side resources and in evaluation of applications for certification of power generation projects and assists the staff in monitoring the construction of these projects. He has also assisted in providing regulatory oversight related to an electric utility’s evaluation of responses to an RFP for a supply-side resource and subsequent negotiations with short-listed bidders. He has provided technical litigation support and expert testimony support in several complex law suits involving power generation facilities. He monitors power plant operations for GDS clients and has provided testimony on power plant operations and decommissioning in several jurisdictions. Dr. Jacobs represents a GDS client on the management committee of a large coal-fired power plant currently under construction. Dr. Jacobs has provided testimony before the Georgia Public Service Commission, the Public Utility Commission of Texas, the North Carolina Utilities Commission, the South Carolina Public Service Commission, the Iowa State Utilities Board, the Louisiana Public Service Commission, the Florida Public Service Commission, the Indiana Regulatory Commission, the Wisconsin Public Service Commission, the Arizona Corporation Commission and the FERC.
A list of Dr. Jacobs’ testimony is available upon request.
1986-Present GDS Associates, Inc.
As Executive Consultant, Dr. Jacobs assists clients in evaluation of management and technical issues related to power plant construction, operation and design. He has evaluated and testified on combustion turbine projects in certification hearings and has assisted the Georgia PSC in monitoring the construction of the combustion turbine projects. Dr. Jacobs has evaluated nuclear plant operations and provided testimony in the areas of nuclear plant operation, construction prudence and decommissioning in nine states. He has provided litigation support in complex law suits concerning the construction of nuclear power facilities. Dr. Jacobs is the Georgia PSC’s Independent Construction Monitor for the Plant Vogtle 3 and 4 nuclear project.
1985-1986 Institute of Nuclear Power Operations (INPO)
Dr. Jacobs performed evaluations of operating nuclear power plants and nuclear power plant construction projects. He developed INPO Performance Objectives and Criteria for the INPO Outage Management Department. Dr. Jacobs performed Outage Management Evaluations at the following nuclear power plants:
Connecticut Yankee - Connecticut Yankee Atomic Power Co. Callaway Unit I - Union Electric Co. Surry Unit I - Virginia Power Co. Ft. Calhoun - Omaha Public Power District Beaver Valley Unit 1 - Duquesne Light Co.
During these outage evaluations, he provided recommendations to senior utility management on techniques to improve outage performance and outage management effectiveness.
1979-1985 Westinghouse Electric Corporation
As site manager at Philippine Nuclear Power Plant Unit No. 1, a 655 MWe PWR located in Bataan, Philippines, Dr. Jacobs was responsible for all site activities during completion phase of the project. He had overall management responsibility for startup, site engineering, and plant completion departments. He managed workforce of approximately 50 expatriates and 1700 subcontractor personnel. Dr. Jacobs provided day-to-day direction of all site activities to ensure establishment of correct work priorities, prompt resolution of technical problems and on schedule plant completion.
Prior to being site manager, Dr. Jacobs was startup manager responsible for all startup activities including test procedure preparation, test performance and review and acceptance of test results. He established the system turnover program, resulting in a timely turnover of systems for startup testing.
As startup manager at the KRSKO Nuclear Power Plant, a 632 MWE PWR near Krsko, Yugoslavia, Dr. Jacobs' duties included development and review of startup test procedures, planning and coordination of all startup test activities, evaluation of test results and customer assistance with regulatory questions. He had overall responsibility for all startup testing from Hot Functional Testing through full power operation. 1973 - 1979 NUS Corporation
As Startup and Operations and Maintenance Advisor to Korea Electric Company during startup and commercial operation of Ko-Ri Unit 1, a 595 MWE PWR near Pusan, South Korea, Dr. Jacobs advised KECO on all phases of startup testing and plant operations and maintenance through the first year of commercial operation. He assisted in establishment of administrative procedures for plant operation. As Shift Test Director at Crystal River Unit 3, an 825 MWE PWR, Dr. Jacobs directed and performed many systems and integrated plant tests during startup of Crystal River Unit 3. He acted as data analysis engineer and shift test director during core loading, low power physics testing and power escalation program.
As Startup engineer at Kewaunee Nuclear Power Plant and Beaver Valley, Unit 1, Dr. Jacobs developed and performed preoperational tests and surveillance test procedures.
1971 - 1973 Southern Nuclear Engineering, Inc.
Dr. Jacobs performed engineering studies including analysis of the emergency core cooling system for an early PWR, analysis of pressure drop through a redesigned reactor core support structure and developed a computer model to determine tritium build up throughout the operating life of a large PWR.
SIGNIFICANT CONSULTING ASSIGNMENTS:
Georgia Public Service Commission – Selected as the Independent Construction Monitor to assist the GPSC staff in monitoring all aspects of the design, licensing and construction of Plant Vogtle Units 3 and 4, two AP1000 nuclear power plants.
Georgia Public Service Commission – Assisted the Georgia Public Service Commission Staff and provided testimony related to the evaluation of Georgia Power Company’s request for certification to construct two AP1000 nuclear power plants at the Plant Vogtle site.
South Carolina Office of Regulatory Staff – Assisted the South Carolina Office of Regulatory Staff in evaluation of South Carolina Electric and Gas’ request for certification of two AP1000 nuclear power plants at the V.C. Summer site.
Florida Office of Public Counsel – Assists the Florida Office of Public Counsel in monitoring the development of four new nuclear power plants and extended power uprates on five nuclear units in Florida including providing testimony on the prudence of expenditures.
East Texas Electric Cooperative – Represented ETEC on the management committee of the Plum Point Unit 1 a 650 Mw coal-fired plant under construction in Osceola, Arkansas and represents ETEC on the management committee of the Harrison County Power Project, a 525 Mw combined cycle power plant located near Marshall, Texas.
Arizona Corporation Commission – Evaluated operation of the Palo Verde Nuclear Generating Station during the year 2005. Included evaluation of 11 outages and providing written and oral testimony before the Arizona Corporation Commission.
Citizens Utility Board of Wisconsin – Evaluated Spring 2005 outage at the Kewaunee Nuclear Power Plant and provided direct and surrebuttal testimony before the Wisconsin Public Service Commission.
Georgia Public Service Commission - Assisted the Georgia PSC staff in evaluation of Integrated Resource Plans presented by two investor owned utilities. Review included analysis of purchase power agreements, analysis of supply-side resource mix and review of a proposed green power program.
State of Hawaii, Department of Business, Economic Development and Tourism – Assisted the State of Hawaii in development and analysis of a Renewable Portfolio Standard to increase the amount of renewable energy resources developed to meet growing electricity demand. Presented the results of this work in testimony before the State of Hawaii, House of Representatives.
Georgia Public Service Commission - Assisted the Georgia PSC staff in providing oversight to the bid evaluation process concerning an electric utility’s evaluation of responses to a Request for Proposals for supply-side resources. Projects evaluated include simple cycle combustion turbine projects, combined cycle combustion turbine projects and co-generation projects.
Millstone 3 Nuclear Plant Non-operating Owners – Evaluated the lengthy outage at Millstone 3 and provided analysis of outage schedule and cost on behalf of the non- operating owners of Millstone 3. Direct testimony provided an analysis of additional post-outage O&M costs that would result due to the outage. Rebuttal testimony dealt with analysis of the outage schedule.
H.C. Price Company – Evaluated project management of the Healy Clean Coal Project on behalf of the General Contractor, H.C. Price Company. The Healy Clean Coal Project is a 50 megawatt coal burning power plant funded in part by the DOE to demonstrate advanced clean coal technologies. This project involved analysis of the project schedule and evaluation of the impact of the owner’s project management performance on costs incurred by our client.
Steel Dynamics, Inc. – Evaluated a lengthy outage at the D.C. Cook nuclear plant and presented testimony to the Indiana Utility Regulatory Commission in a fuel factor adjustment case Docket No. 38702-FAC40-S1.
Florida Office of Public Counsel - Evaluated lengthy outage at Crystal River Unit 3 Nuclear Plant. Submitted expert testimony to the Florida Public Service Commission in Docket No. 970261-EI.
United States Trade and Development Agency - Assisted the government of the Republic of Mauritius in development of a Request for Proposal for a 30 MW power plant to be built on a Build, Own, Operate (BOO) basis and assisted in evaluation of Bids.
Louisiana Public Service Commission Staff - Evaluated management and operation of the River Bend Nuclear Plant. Submitted expert testimony before the LPSC in Docket No. U- 19904.
U.S. Department of Justice - Provided expert testimony concerning the in-service date of the Harris Nuclear Plant on behalf of the Department of Justice U.S. District Court.
City of Houston - Conducted evaluation of a lengthy NRC required shutdown of the South Texas Project Nuclear Generating Station.
Georgia Public Service Commission Staff - Evaluated and provided testimony on Georgia Power Company's application for certification of the Intercession City Combustion Turbine Project - Docket No. 4895-U.
Seminole Electric Cooperative, Inc. - Evaluated and provided testimony on nuclear decommissioning and fossil plant dismantlement costs - FERC Docket Nos. ER93-465- 000, et al.
Georgia Public Service Commission Staff - Evaluated and prepared testimony on application for certification of the Robins Combustion Turbine Project by Georgia Power Company - Docket No. 4311-U.
North Carolina Electric Membership Corporation - Conducted a detailed evaluation of Duke Power Company's plans and cost estimate for replacement of the Catawba Unit 1 Steam Generators.
Georgia Public Service Commission Staff - Evaluated and prepared testimony on application for certification of the McIntosh Combustion Turbine Project by Georgia Power Company and Savannah Electric Power Company - Docket No. 4133-U and 4136- U.
New Jersey Rate Counsel - Review of Public Service Electric & Gas Company nuclear and fossil capital additions in PSE&G general rate case.
Corn Belt Electric Cooperative/Central Iowa Power Electric Cooperative - Directs an operational monitoring program of the Duane Arnold Energy Center (565 Mwe BWR) on behalf of the non-operating owners.
Cities of Calvert and Kosse - Evaluated and submitted testimony of outages of the River Bend Nuclear Station - PUCT Docket No. 10894.
Iowa Office of Consumer Advocate - Evaluated and submitted testimony on the estimated decommissioning costs for the Cooper Nuclear Station - IUB Docket No. RPU- 92-2.
Georgia Public Service Commission/Hicks, Maloof & Campbell - Prepared testimony related to Vogtle and Hatch plant decommissioning costs in 1991 Georgia Power rate case - Docket No. 4007-U.
City of El Paso - Testified before the Public Utility Commission of Texas regarding Palo Verde Unit 3 construction prudence - Docket No. 9945.
City of Houston - Testified before Texas Public Utility Commission regarding South Texas Project nuclear plant outages - Docket No. 9850.
NUCOR Steel Company - Evaluated and submitted testimony on outages of Carolina Power and Light nuclear power facilities - SCPSC Docket No. 90-4-E.
Georgia Public Service Commission/Hicks, Maloof & Campbell - Assisted Georgia Public Service Commission staff and attorneys in many aspects of Georgia Power Company's 1989 rate case including nuclear operation and maintenance costs, nuclear performance incentive plan for Georgia and provided expert testimony on construction prudence of Vogtle Unit 2 and decommissioning costs of Vogtle and Hatch nuclear units - Docket No. 3840-U.
Swidler & Berlin/Niagara Mohawk - Provided technical litigation support to Swidler & Berlin in law suit concerning construction mismanagement of the Nine Mile 2 Nuclear Plant.
Long Island Lighting Company/Shea & Gould - Assisted in preparation of expert testimony on nuclear plant construction.
North Carolina Electric Membership Corporation - Prepared testimony concerning prudence of construction of Carolina Power & Light Company's Shearon Harris Station - NCUC Docket No. E-2, Sub537.
City of Austin, Texas - Prepared estimates of the final cost and schedule of the South Texas Project in support of litigation.
Tex-La Electric Cooperative/Brazos Electric Cooperative - Participated in performance of a construction and operational monitoring program for minority owners of Comanche Peak Nuclear Station.
Tex-La Electric Cooperative/Brazos Electric Cooperative/Texas Municipal Power Authority (Attorneys - Burchette & Associates, Spiegel & McDiarmid, and Fulbright & Jaworski) - Assisted GDS personnel as consulting experts and litigation managers in all aspects of the lawsuit brought by Texas Utilities against the minority owners of Comanche Peak Nuclear Station.
BEFORE THE GEORGIA PUBLIC SERVICE COMMISSION
IN THE MATTER OF: GEORGIA POWER COMPANY’S TWENTIETH/TWENTY- DOCKET NO. 29849 FIRST SEMI-ANNUAL VOGTLE CONSTRUCTION MONITORING REPORT
DIRECT TESTIMONY
AND EXHIBITS
OF
TOM NEWSOME, PE, CFA
PHILIP HAYET
ON BEHALF OF THE
GEORGIA PUBLIC SERVICE COMMISSION PUBLIC INTEREST ADVOCACY STAFF
NOVEMBER 22, 2019
TABLE OF CONTENTS
I. INTRODUCTION ...... 2
II. COMPANY’S VCM 20/21 FILING ...... 5
III. STAFF’S ECONOMIC EVALUATION ...... 9
Staff’s Assumptions ...... 9 Staff’s Economic Evaluation Results ...... 18
1
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 I. INTRODUCTION
2 Q. PLEASE STATE YOUR NAMES, TITLES, AND BUSINESS ADDRESSES.
3 A. My name is Tom J. Newsome. I am the Director of Utility Finance with the Georgia Public 4 Service Commission (“Commission”). My business address is 244 Washington St., 5 Atlanta, Georgia, 30334.
6 My name is Philip Hayet. I am a Vice President and Principal of J. Kennedy and Associates, 7 Inc. (“Kennedy and Associates”). My business address is 570 Colonial Park Drive, Suite 305, 8 Roswell, Georgia, 30075.
9 Q. MR. NEWSOME, WHAT ARE YOUR PRIMARY RESPONSIBILITIES WITH THE 10 COMMISSION STAFF?
11 A. I am responsible for economic, financial, and cost of equity analysis and evaluations at the 12 Commission.
13 Q. WHAT CONSULTING SERVICES DOES KENNEDY AND ASSOCIATES 14 PROVIDE?
15 A. Kennedy and Associates provides consulting services related to electric utility system 16 planning, resource analysis, production cost modeling, ratemaking, finance, accounting, 17 and industry policy issues.
18 Q. PLEASE PROVIDE SUMMARIES OF YOUR EDUCATIONAL BACKGROUND 19 AND EXPERIENCE.
20 A. Summaries of our education, experience, professional certifications, and testimony 21 appearances are provided in Exhibits STF-NH-1 and STF-NH-2, for Mr. Newsome and 22 Mr. Hayet, respectively.
2
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 Q. PLEASE PROVIDE AN OVERVIEW OF THE PROJECT.
2 A. Georgia Power Company’s (“the Company” or “Georgia Power”) Twentieth/Twenty-First 3 Vogtle Construction Monitoring (“VCM 20/21”) Report covers the twelve-month period 4 of July 1, 2018 through June 30, 2019. Consistent with its 17th through 19th VCM filings, 5 the Company continues to forecast a schedule delay of 68 months, with commercial 6 operation dates (“CODs”) for Units 3 and 4 planned for November 2021 and 2022, 7 respectively. The VCM 20/21 filing states that the Company and Southern Nuclear 8 Operating Company (“SNC”) continue to project that Georgia Power’s share of Vogtle 9 Units 3 and 4 (“Project” or “Units”) construction and capital cost will be $8.4 billion. 10 However, at this time, the Company has only stated that it intends to seek approval of $7.3 11 billion in capital costs. Of the approximate $1.1 billion difference, the Company has stated 12 it will absorb $694 million and has not decided whether it will seek recovery of the 13 remaining $366 million contingency from the Commission.1
14 Staff included the $366 million contingency in its cost to complete economic analysis since 15 the Company expects to incur the cost and may seek recovery of the costs from ratepayers.2 16 Therefore, Staff’s revised capital cost estimate is $7.7 billion ($7.3 billion + $366 million) 17 with a financing cost of $3.1 billion, for a Total Project Cost of $10.8 billion.3
18 Staff reviewed the Company’s economic analysis and presents its own independent
1 At Georgia Power’s November 12, 2019 Direct Testimony hearing, Company witness Kuczynski discussed that a portion of the $366 million contingency amount has now been allocated (about $30 million), and he stated, “…we still expect that the remaining balance of contingency will be allocated by the completion of the project…” The Company also stated in its VCM 20/21 Report at pg. 4, “The Company is not requesting Commission approval of these costs in this filing but may request the Commission to evaluate expenditures allocated to contingency for rate recovery as and when appropriate.” The Company also recognized it would incur the $366 million of contingency in its SEC filings. 2 Staff’s inclusion of the $366 million for economic modeling does not constitute an agreement by Staff that these costs should be recovered from ratepayers. 3 The $10.8 billion Total Project Cost is the net of the Toshiba Parental Guarantee ($1.492 billion) that was applied as an offset to the construction balance and includes the return on equity (“ROE”) reductions provided in the Supplemental Information Review (“SIR”) stipulation and the 17th VCM Order. The $10.8 billion Total Project Cost represents about an 80 percent increase from the Company’s projection of $6.1 billion at Certification. 3
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 economic evaluation of the Project in this testimony. Similar to Staff’s analyses in prior 2 VCM proceedings, Staff performed independent economic studies over a range of 3 assumptions that in some cases differ from the Company’s assumptions and 4 methodologies.
5 Staff’s cost to complete economic analysis indicates it is economic to continue the Project 6 if the Company meets its current cost and COD forecasts. However, Staff determined that 7 a delay beyond 18 months from the current regulatory CODs of November 2021/2022 8 could result in the Project becoming uneconomic to continue. This is the result of the high 9 cost being incurred by the Company each month during construction.4 This cost to 10 complete economic analysis ignores the over $5 billion in capital costs already spent on 11 the Project as well as the $2 billion in financing costs already recovered from ratepayers 12 through the Nuclear Construction Cost Recovery (“NCCR”) tariff.
13 Q. WHY DO YOU EXCLUDE THE $7 BILLION THE COMPANY HAS ALREADY 14 INCURRED IN YOUR COST TO COMPLETE ANALYSIS?
15 A. The purpose of a cost to complete analysis is to examine whether it is economic to finish 16 the Project, not to evaluate whether the Project is economic for ratepayers over the entire 17 lifecycle (construction and operating periods). Therefore, only prospective costs should be 18 included in the cost to complete economic analysis. However, Staff also performed a 19 lifecycle economic analysis which included all costs that were excluded from the cost to 20 complete analysis. The results from lifecycle economic analysis are presented later in this 21 testimony.
22
4 For example, the Company incurred approximately $137 million per month of capital and financing cost during the first nine months of 2019. 4
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 II. COMPANY’S VCM 20/21 FILING
2 Q. WHAT CONVENTION DO YOU USE TO REFER TO THE DIFFERENT CASES 3 EVALUATED IN THIS PROCEEDING?
4 A. Our practice has been to identify the delay cases based on the number of months of delay 5 from the original certified in-service dates for the Units, which were April 2016/2017. 6 Since the Company’s latest in-service date estimate is November 2021/2022, Staff refers 7 to this as the 68-month delay case. The Company refers to the same case as its +29-month 8 case in reference to its prior CODs of June 2019/2020, as was reflected in the Company’s 9 15th and 16th VCM filings.
10 Q. PLEASE EXPLAIN HOW THE FINANCING COST INCURRED BY THE 11 COMPANY DURING THE CONSTRUCTION OF THE UNITS IS RECOVERED 12 FROM RATEPAYERS.
13 A. Of the Company’s $3.1 billion financing cost, $2.8 billion is being recovered during 14 construction through the Nuclear Construction Cost Recovery (“NCCR”) tariff. The $2.8 15 billion amount consists of $0.1 billion in financing cost that occurred prior to 2011 when 16 the NCCR tariff began,5 and an additional $2.7 billion of financing cost that will be 17 incurred from 2011 through the current CODs. The $2.7 billion amount consists of $0.76 18 billion of interest on debt and $1.96 billion of return on equity (“ROE” or “profit”). An 19 additional financing cost of $0.3 billion will be deferred and recovered over the operating 20 life of the Units through Allowance for Funds Used During Construction (“AFUDC”) 21 accounting.
22 Q. HOW MUCH OF THE NCCR TARIFF REVENUE REQUIREMENT WILL BE
5 The $0.1 billion financing cost amount that was incurred prior to 2011 was recovered over the period of 2011 to 2015. 5
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 COLLECTED FROM RATEPAYERS DURING THE CONSTRUCTION PERIOD?
2 A. Staff estimates the Company will collect approximately $3.9 billion from ratepayers 3 through the NCCR tariff. The $3.9 billion is composed of $2.8 billion in financing cost and 4 $1.1 billion in income tax expense.6
5 Q. HOW MUCH HAS ALREADY BEEN SPENT ON THE PROJECT THROUGH 6 THE END OF THE VCM 20/21 PERIOD?
7 A. As of June 30, 2019, the Company has incurred $5.19 billion of capital and construction 8 cost and $2.03 billion of financing cost for a total cost of $7.22 billion.7
9 Q. HOW MUCH REMAINS TO BE SPENT BY THE COMPANY ON THE PROJECT 10 THROUGH THE END OF CONSTRUCTION?
11 A. Over the remainder of the construction period, the Company estimates it will incur an 12 additional $2.11 billion of construction and capital costs and an additional $1.10 billion of 13 financing cost for total cost of $3.21 billion.8
14 Q. DID THE COMPANY CHANGE ANY MODELING ASSUMPTIONS FROM ITS 15 VCM 19 FILING?
16 A. Yes, and the changes are discussed on page 40 of the VCM 20/21 Report. The Company 17 notes that it updated all of its major underlying planning assumptions, including fuel 18 forecasts, load forecasts, and new generation technology costs. The changes the Company 19 made are the same as what was included in the recent 2019 Integrated Resource Plan 20 (“IRP”) (Docket No. 42310). However, one difference compared to the IRP is that the
6 Refer to Staff data requests 170-25 and 170-27. 7 The $5.19 billion capital cost value is net of the $1.49 billion Toshiba Parental Guarantee applied as an offset to the construction balance that otherwise would have been $6.68 billion. 8 As previously discussed, Staff is including the $366 million in its capital cost estimate, so based on that the estimate of the remaining capital cost to be incurred is $2.48 billion rather than the $2.11 billion value the Company reported. 6
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 Company included Gulf Power loads and resources in its IRP databases, but it removed the 2 Gulf Power loads and resources from its VCM 20/21 databases. In addition, the Company 3 made changes to Pre-in-service O&M, post-in-service O&M, post-in-service ongoing 4 capital, Ad Valorem taxes, its marginal cost of capital, nuclear fuel costs, and it ignored 5 cancellation costs in its analysis. Overall, the changes had a small impact on the cost-to- 6 complete economic analysis results.
7 In addition, with regard to the new Vogtle Units, the Company noted at page 40 of its VCM 8 20/21 Report that “The average summer net output has been updated based on the results 9 of the Vogtle 3 & 4 Power Output Assessment, which was filed as an update to STF-132- 10 19 in the Company’s May 2019 Monthly Status Report.” This amounts to about an 11 MW 11 increase in Georgia Power’s share of the capacity of the two new Vogtle Units.
12 Q. WHAT ECONOMIC EVALUATION DID THE COMPANY PERFORM IN THIS 13 PROCEEDING?
14 A. The Company performed a single cost-to-complete economic analysis study, which it 15 presented in Table 4.1 of its VCM 20/21 report. The Company’s analysis compared the 16 remaining cost to complete the Vogtle Project, referred to as the “Completion Case”, to the 17 cost to cancel Vogtle and construct an equivalent amount of combined cycle capacity, 18 referred to as the “Cancellation Case”. The Company’s analysis forecasts that there will 19 be a $2.8 billion benefit on an expected value basis to continue construction (2021 NPV 20 dollars).9
21 Q. DOES STAFF HAVE ANY CONCERNS WITH THE COMPANY’S ECONOMIC 22 EVALUATION?
23 A. Yes. Staff continues to have concerns with the Company’s analysis. First, as Staff
9 This amounts to $2.2 billion on a 2018 NPV basis. 7
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 discussed in prior proceedings, a correct and accurate economic analysis should include all 2 differences between cancelling and continuing the Project, including, among others, 3 accounting for prospective incremental income tax impacts.
4 Second, the Company omitted the $366 million contingency in its analysis without 5 agreeing to absorb the cost. The following table summarizes the capital costs included in 6 the Company’s Table 1.1 and its economic analysis and compares this to Staff’s capital 7 cost assumption.
8 Table 1 9 Comparison of the Company’s and Staff’s 10 Capital Cost Assumption in VCM 20/21($ Millions) 11 Capital Cost Capital Cost 9,486 Toshiba Parental Guarantee (1,492) Georgia Power to Absorb (694) Company’s Capital Cost 7,300 Contingency 366 Staff’s Capital Cost 7,667 12
13 Third, Staff disagrees with the Company’s interpretation of the VCM 17 Order, and some 14 of the modeling assumptions that the Company incorporated in its VCM 20/21 analysis. 15 Specifically, Staff disagrees with the Company’s interpretation of the amount of capital 16 investment to be placed into the rate base when Unit 3 goes into service, and the recovery 17 of the remaining investment and operations costs until Unit 4 is complete.
18 Fourth, although Staff determined that the Company lowered its natural gas price forecasts 19 considerably in this VCM proceeding compared to VCM 19, Staff continues to disagree 20 with the Company’s approach of deriving its forecasts using only a single source rather 21 than multiple sources of information.
8
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 Finally, Staff has concerns with the Company’s carbon modeling assumptions. One 2 concern is that the Company has not updated its carbon dioxide emission price forecast 3 even though the Clean Power Plan has been repealed. The second concern, as discussed in 4 Staff’s IRP testimony, is that in some scenarios the only type of combined cycle unit the 5 Company allows to be added as new resource additions are combined cycle units with 6 carbon sequestration capability. These units are extremely expensive, not commercially 7 available, and unlikely to ever be added as the Company has modeled them.
8 Q. WHAT SCENARIO DID THE COMPANY EVALUATE THAT LED TO THE 9 RESULTS IT PRESENTED IN TABLE 4.1?
10 A. The Company evaluated its current base case in-service date assumptions based on the 68- 11 month delay case. The Company performed its usual set of nine analyses evaluating all 12 combinations of three fuel price cases (Low, Mod, High) and three carbon dioxide emission 13 price cases ($0/Ton, $10/Ton, $20/Ton).
14
15 III. STAFF’S ECONOMIC EVALUATION
16 Staff’s Assumptions
17 Q. WHAT ANALYSES DID STAFF PERFORM IN ITS VCM 20/21 EVALUATION?
18 A. Staff conducted cost-to-complete analyses to evaluate the reasonableness of the 19 Company’s results using alternative modeling assumptions. Staff performed an evaluation 20 of the Company’s 68-month delay scenario with alternative assumptions and conducted a 21 sensitivity case assuming a 24-month delay beyond the Company’s current November 22 2021/2022 CODs (for a total delay of 92 months).
23 Q. WHAT CHANGES TO ASSUMPTIONS DID STAFF MAKE TO CREATE
9
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 STAFF’S CASES?
2 A. Staff made the following adjustments in its cases: 3 Set the net present value date to 2018, 4 Included the $366 million contingency cost, 5 Accounted for certain prospective incremental impacts of sunk costs, primarily 6 the income tax benefit of approximately $1.2 billion if Vogtle 3 & 4 were 7 cancelled,10 8 Relied on a different interpretation of VCM Order 17 and the Supplemental 9 Information Report (“SIR”) Stipulation that does not force ratepayers to pay 10 costs that have not been determined to be prudent, 11 Used a revised set of natural gas price forecasts,
12 Used a revised set of Carbon Dioxide (“CO2”) emission price forecasts, and; 13 Staff allowed Strategist the option of choosing the most economic combined 14 cycle resource with or without carbon dioxide sequestration. Under certain 15 circumstances, the Company required that any combined cycle resource added 16 after a certain date would need to include carbon sequestration capability. 17 18 Q. DISCUSS THE CHANGE STAFF MADE TO THE COMPANY’S PRESENT 19 VALUE DATE.
20 A. Staff used 2018 as the measurement date for present value calculations, rather than 2021. 21 As mentioned earlier, using a common present value year allows for consistency in 22 evaluating past, current, and future economic evaluations.
23 Q. PLEASE EXPLAIN STAFF’S CONSIDERATION OF THE $366 MILLION IN
10 $1.2 billion = $5.9 billion write-off x 21% tax rate 10
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 CONTINGENCY AND HOW IT IS MODELED.
2 A. As discussed above, Staff believes the $366 million contingency amount should be 3 included in the economic evaluation. While Staff includes the contingency cost in its 4 economic analysis, this should not be interpreted to mean that Staff believes customers 5 should be responsible for these costs.
6 Q. EXPLAIN THE CHANGES STAFF MADE TO ACCOUNT FOR THE 7 PROSPECTIVE INCREMENTAL INCOME TAX IMPACTS OF SUNK COSTS.
8 A. Staff accounted for two important incremental impacts of sunk costs in its cost to complete 9 analysis. Staff properly captured the impact of prospective income taxes stemming from 10 sunk costs and modeled the income tax write-off (savings) that Georgia Power would be 11 entitled to if the Project were cancelled. Georgia Power on the other hand incorrectly 12 assumes that this tax benefit can be ignored.11
13 Q. DOES STAFF AND THE COMPANY DIFFER ON THE INITIAL RATEMAKING 14 TREATMENT FOR UNIT 3 ONCE UNIT 3 IS PLACED INTO COMMERCIAL 15 OPERATION?
16 A. Yes. Staff and the Company have different interpretations of the 17th VCM Order and 17 Supplemental Information Report (“SIR”) Stipulation.
18 Q. PLEASE EXPLAIN STAFF’S INTERPRETATION OF THE 17th VCM ORDER.
19 A. Both Staff’s and the Company’s economic analyses assume a portion of Unit 3 and 20 common capital costs should be placed in rate base and reflected in rates in the first month
11 The $1.2 billion income tax benefit from canceling Vogtle would impact the cost to complete analysis by $255 million on a 2018 net present value (NPV) basis. The underlying assumptions include a sunk cost of $5.9 billion as of January 2020, a 15-year modified accelerated cost recovery system (“MACRS”) tax depreciation schedule for the $5.9 billion in the Continuation Case, and a 3-year straight-line tax depreciation schedule (abandonment loss) for the $5.9 billion in the Cancelation Case. 11
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 after the Unit 3 COD. But, they differ on the exact amounts. As Staff described in its 2 VCM 18 and 19 testimonies, the SIR Stipulation provided that capital costs verified and 3 approved through December 2015 would be deemed prudent except under special 4 circumstances. The SIR Stipulation also provided that the Vogtle Units 3 and 4 costs would 5 be placed in retail rate base on the latter of either December 31, 2020, or Unit 4 reaching 6 commercial operation.
7 The Commission’s 17th VCM Order modified the treatment of a portion of the Unit 3 and 8 common costs. Unit 3 and common costs that had been verified and approved through 9 December 2015 could now go into base rates after Unit 3 goes into commercial operation. 10 On page 18, the 17th VCM Order states:
11 ORDERED FURTHER, that effective the first month after Unit 3 is in 12 Commercial Operation, which is expected to be in November 2021, retail base rates 13 shall be adjusted to include the costs related to Unit 3 and common facilities 14 deemed prudent in the January 3, 2017 Stipulation. This rate adjustment will be 15 effective the first month after Unit 3 is in commercial operation.
16 All the remaining Unit 3 costs (as well as all the Unit 4 costs) would continue to stay out 17 of base rates until after Unit 4 is in commercial operation. Again, from page 18 of the 17th 18 VCM Order:
19 ORDERED FURTHER, that once the fuel load of Unit 4 is reached, the Company 20 may make a filing with the Commission to determine the adjustment to retail base 21 rates necessary to include the remaining amounts of Units 3 and 4 into retail base 22 rates. During this review, the Commission will determine the remaining issues 23 pertaining to prudence of Unit 3 and 4 costs. Such rate adjustment will be effective 24 the first month after Unit 4 is Commercially Operational. 25 (Emphasis added).
26 The 17th VCM Order further states that “[t]he balance of the proceeds received from 27 Toshiba, net of the Company’s costs to obtain that payment and net of the costs of 28 providing … customer credits, will be applied to the CWIP balance.” The CWIP balance
12
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 contains only costs already incurred by the Company. It does not contain any future costs. 2 And only some of the costs in CWIP have been deemed prudent.12 It is Staff’s position 3 that the Toshiba Parental Guarantee (“TPG”) funds can only be applied to offset costs that 4 have been deemed prudent by the Commission. 13 Otherwise, ratepayers may be paying 5 costs which the Commission has not yet, and may never, find to be prudent. Therefore, the 6 TPG funds can only be applied to the $3.5 billion deemed prudent in the SIR stipulation.
7 Q. HOW DOES THIS DIFFERENCE IN INTERPRETATION IMPACT THE 8 AMOUNT OF UNIT 3 AND COMMON COSTS THAT GO INTO BASE RATES 9 WHEN UNIT 3 IS COMPLETED?
10 A. Based on this interpretation of the SIR stipulation and the VCM 17 Order Staff determined 11 that the Company should be allowed to place $1.13 billion of Unit 3 Capital and Common 12 capital cost into rate base the month following commercial operation, whereas the 13 Company determined that it should be allowed to place $2.34 billion into rate base at that 14 time.14 Additionally, Staff assumed that capital costs placed into rate base the month after 15 Unit 3 is completed should be taken entirely from the capital costs underlying the NCCR 16 tariff to match how these capital costs are financed. This contrasts to the Company’s 17 interpretation that assumes Unit 3 costs put into rate base would be partly taken from
12 When the VCM 17 Order was issued, the CWIP balance was $3.902 billion, of that $3.509 billion had been deemed prudent by the SIR Stipulation. The VCM 17 Order also verified another $542 million, which has not yet been deemed prudent. Reducing the CWIP balance by the $1.493 net Toshiba payment, resulted in a new CWIP balance of $2.951 billion ($3.902 + .542 – 1.493). Despite this, the Company apparently contends that ratepayers still owed the Company the entire $3.509 billion, which was more than the entire CWIP balance. 13 As Commissioner Echols explained at the December 21, 2017 Special Administrative Session, “The owners … achieved payment in full for that parent guarantee but they achieved it for the customers' benefit and that's who should benefit.” Trans., pg. 7-8 (Emphasis added). Customers don’t benefit from the Toshiba payment unless it is applied to a cost that would otherwise be recoverable from customers. 14 The TPG proceeds of $1.493 billion were allocated in full against the $3.509 billion capital costs incurred through December 31, 2015, netting to $2.016 billion. Staff assumed 56% of this amount, or $1.129 billion would be placed in-service the month after Unit 3 is completed. The Company assumed no TPG offset and assumed 66.6% of the amount, or $2.34 billion, would be placed in service the month after Unit 3 is completed. See STF 137-9 part d.
13
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 AFUDC instead of exclusively from NCCR, which results in more costs remaining to be 2 recovered through the NCCR Tariff at the same time that base rates are adjusted.
3 Q. ARE THERE ANY OTHER DIFFERENCES IN HOW STAFF AND THE 4 COMPANY TREAT COSTS RELATING TO UNIT 3?
5 A. Staff has also determined that depreciation on the Unit 3 and Common amounts not placed 6 into rate base upon Unit 3 completion should be assigned to the Company. Likewise, O&M 7 and decommissioning expenses should not be charged to customers until Unit 4 is complete 8 and the Project has been reviewed.15 Financing costs on the Unit 3 capital balance not put 9 into rate base would continue to be recovered, through either the NCCR tariff or capitalized 10 through AFUDC accounting, at the reduced ROE rates consistent with the SIR stipulation 11 and the 17th VCM Order.
12 It is important to note that Staff’s interpretation reduces the Project’s revenue requirements 13 and therefore, increases the economic value of the Project to customers.
14 Q. WHAT IS THE FINANCIAL IMPACT ON RATEPAYERS OF STAFF’S AND THE 15 COMPANY’S DIFFERENT INTERPRETATIONS OF THE 17th VCM AND SIR 16 STIPULATION?
17 A. The revenue requirement collected from ratepayers under base rates during the first year
15 The VCM 17 Order provides that when Unit 3 goes into commercial operation, rates are only adjusted to include the portion of the costs deemed prudent in the January 3, 2017 Stipulation that are allocable to Unit 3 and common facilities. VCM 17 Order, p. 14, para. 8. None of these additional costs meet that criteria. Instead, these costs cannot go into rates until Unit 4 goes into commercial operation, VCM 17 Order, p. 14, para. 10 (“upon reaching fuel load of Unit 4, the Company may make a filing with the Commission to determine the adjustment to retail base rates necessary to include the remaining amounts of Units 3 and 4 into retail base rates. During this review, the Commission will determine the remaining issues pertaining to prudence of Unit 3 and 4 costs. Such rate adjustment will be effective the first month after Unit 4 is Commercially Operational.”); p. 16, para. 14 (“All Commission decisions regarding cost recovery will be made after a prudence review at the end of construction of Units 3 and 4.”).
14
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 of Unit 3 commercial operation would be materially different. Under Staff’s interpretation 2 the base rate revenue requirement would be approximately $450 million. Under the 3 Company’s interpretation the base rate revenue requirement would be approximately $700 4 million.16 Ratepayer bills would be lower by approximately $250 million under Staff’s 5 interpretation during the year between the Unit 3 and Unit 4 COD dates. This reduction of 6 ratepayer bills would increase if Unit 4 COD was extended beyond the planned one year 7 from Unit 3 COD.
8 Q. PLEASE DISCUSS YOUR REVIEW OF THE COMPANY’S NATURAL GAS 9 PRICE FORECASTS.
10 A. As Staff noted in prior VCM proceedings and the recent 2019 IRP proceeding, Staff has 11 been and continues to be concerned about the Company’s reliance on a single source, 12 Charles River Associates (“CRA”), for developing its natural gas price forecasts. The 13 Company continued this practice in VCM 20/21. Staff’s concern has been that without 14 adjusting its forecasts based on other information that is available, the Company could end 15 up with forecasts that are out of line with other industry trends. In fact, Staff has noted on 16 several occasions that the Company’s forecasts have appeared to be too high.
17 Q. DID STAFF COMPARE THE COMPANY’S NATURAL GAS PRICE FORECAST 18 TO OTHER RECENT PUBLICLY AVAILABLE FORECASTS IN THIS VCM?
19 A. Yes. The Company’s natural gas price forecast in this VCM is essentially the same as what 20 it used in its 2019 IRP. In this VCM, Staff compared Georgia Power’s underlying Henry 21 Hub natural gas price forecast to projections that are publicly available from other utility
16 The Company assumes a deferral of the Unit 3 depreciation cost not placed in rate base upon Unit 3’s completion date. The Company also assumes that after the Unit 4 COD date, it would get to recover the deferred Unit 3 depreciation costs over a five-year period.
15
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 companies including the Tennessee Valley Authority (“TVA”)17, Southwestern Electric 2 Power Company (“SWEPCO”)18, Entergy Louisiana, LLC (“ELL”)19, Xcel Minnesota20, 3 as well as the United States Energy Information Administration (“EIA”).21 As in the IRP, 4 Staff found that the Company’s High Gas Price forecast appears to be the highest of the 5 High Gas Price Forecasts reviewed, the Company’s moderate gas price forecast appears to 6 be slightly above the average consensus forecast that Staff developed, and the Company’s 7 low gas price forecast appears to be below the average consensus forecast. Staff developed 8 consensus average Low, Mod, and High gas price forecasts for its analyses using the 9 publicly available data it collected as it had done in prior VCMs.
10 Q. PLEASE EXPLAIN STAFF’S CONCERN REGARDING THE COMPANY’S CO2 11 EMISSION PRICE FORECAST.
12 A. Staff noted in its VCM 19 and 2019 IRP testimonies that it no longer seems reasonable for
13 the Company to use a CO2 emission price forecast that was originally based on the 14 Environmental Protection Agency’s (“EPA”) Clean Power Plan rule, given that rule has 15 been repealed and replaced by the Affordable Clean Energy (“ACE”) rule. Staff believes
16 that the Company’s CO2 emission price forecast is overstated based on the high annual
17 CO2 emission price escalation rate that the Company relies on for every year of the study 18 period covering the 60-year life of the new Vogtle Units. Though Staff acknowledges there
19 is tremendous uncertainty about what CO2 emission prices may be imposed in the future,
17 “2019 Integrated Resource Plan, Volume I – Draft Resource Plan,” https://www.tva.gov/file_source/TVA/Site%20Content/Environment/Environmental%20Stewardship/IRP/2019 %20Documents/TVA%20Draft%20IRP%20Vol%20I-reduced.pdf, pgs. E-7 and E-8. 18 “2019 Draft Integrated Resource Plan,” http://lpscstar.louisiana.gov/star/ViewFile.aspx?Id=c33b4da2-6ac0-459c- ae6d-a0620eed2809, pg. 152. 19 “Data Assumptions and Study Description,” https://www.entergy- louisiana.com/userfiles/content/irp/2019/ELL_2019_IRP_Assumptions.pdf, pg. 22. 20 2019 IRP data request, https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId=%7b F012F96C-0000-C414-9F8B-072BBCC2B2C9%7d&documentTitle=20199-155648-01 21 All projections gathered from utilities companies were from these companies most recent IRPs, in which the data was extracted from the graphs and tables that those companies presented in their public filings. 16
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 Staff believes it is appropriate to lower the Company’s CO2 emission price forecast. Staff 2 reduced the Company’s significant nominal escalation rate to about 4.5 percent per year.
3 The following graph provides a comparison of the Company’s and Staff’s CO2 price 4 forecasts for the $10/Ton and the $20/Ton cases. The graph demonstrates how
5 dramatically the Company’s CO2 prices increase under its Clean Power Plan modeling 6 approach.
7 Figure 1 8 Nominal CO2 price per Short Ton 9
GPC $10 GPC $20 Staff $10 Staff $20 10 11
12 Q. PLEASE EXPLAIN STAFF’S CONCERN REGARDING THE COMPANY’S 13 REQUIREMENT THAT UNDER CERTAIN CIRCUMSTANCES ANY ADDED 14 COMBINED CYCLE RESOURCE HAD TO HAVE CARBON SEQUESTRATION 15 CAPABILITY.
16 A. Staff disagrees with this assumption. It has been the Company’s practice under certain 17 circumstances to only permit combined cycle resources with carbon sequestration 18 capability to be added in resource planning analyses when combined cycle resources are 19 selected as resource additions. This combined cycle selection requirement is only modeled 17
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 in cases with $10/Ton and $20/Ton CO2 costs, and is only required after a certain date,
2 which is different in the two CO2 cases. Before those dates, the Company permits Strategist 3 to add combined cycle resources without carbon sequestration technology. Similarly, in 4 $0/Ton CO2 cases, combined cycle resource options are not required to include carbon 5 sequestration technology either. Combined cycle units modeled with carbon sequestration 6 technology are substantially more expensive than combined cycle units without that 7 technology.
8 Q. WHY DOES STAFF DISAGREE WITH THIS PRACTICE?
9 A. As Staff mentioned in its 2019 IRP testimony, this technology is extremely expensive and 10 not yet commercially available, and Staff is not aware of when it could even become 11 commercially available for use in Georgia. Given that the Company has modeled this 12 technology for many years, and it still appears no closer to being commercially available, 13 Staff decided to remove this constraint. Staff still left combined cycle options with 14 sequestration in the model, however, Staff allowed the model to determine based on 15 economics whether combined cycle resources with or without this technology should be 16 added.
17
18 Staff’s Economic Evaluation Results
19 20 Q. PLEASE PROVIDE A TABLE SIMILAR TO TABLE 4.1 IN THE COMPANY’S 21 VCM 20/21 REPORT, BASED ON STAFF’S PREFERRED ASSUMPTIONS.
22 A. The following table contains the results based on Staff’s assumptions.
23
18
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
Table 3 Staff’s VCM 20/21 Cost To Complete Economic Evaluation 68-Month Delay Case Economic Benefit of the Project Versus CC 2018 Net Present Value Date (Billions of dollars, Negative Means Uneconomic)
$0/Ton $10/Ton $20/Ton Fuel CO2 CO2 CO2 Expected High 1.5 2.0 2.6 Value Moderate 0.4 0.9 1.5 1.0 Low (0.4) 0.1 0.7 1 2 This compares to the Company’s expected value result of $2.2 billion (computed as a 2018 3 NPV amount) from Table 4.1 of its VCM 20/21 Report.22 Under current market conditions
4 of low natural gas prices and no CO2 emissions costs, the analysis indicates it would be 5 economic to cancel Vogtle Units 3 and 4 and build combined cycle units. The Vogtle Units 6 are only marginally economic under moderate gas price and no CO2 emissions costs; and
7 low gas price and low CO2 emissions costs. These results are primarily driven by the 8 relatively large amount of remaining capital expenditures and associated financing cost 9 necessary to complete the Vogtle units.
10 Q. STAFF’S RESULTS INDICATE IT WOULD BE ECONOMIC TO CONTINUE 11 THE PROJECT. WHY WOULD ONE EXPECT THIS RESULT AT THIS STAGE 12 OF THE PROJECT?
13 A. Normally, the closer a project is to completion, the more economic it is on a cost-to- 14 complete basis because more and more of the total project costs are ignored in the analysis 15 and presumably there is less remaining cost to be incurred. In this case, where we are ten
22 Note that Table 4.1 reports the Vogtle weighted average expected benefit as $2.8 billion on a 2021 NPV basis. Staff converted it to a 2018 NPV result for purposes of comparison. 19
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 years into the Project, it should not be surprising that it appears to be more economic on a 2 cost to complete basis to finish the Project than it would be to abandon the Project and 3 construct a combined cycle unit. What should be noted is how small the benefit of 4 completing the Project is compared to the large amount of sunk costs that are being ignored.
5 Q. WHAT ARE THE RESULTS OF STAFF’S DELAY SENSITIVITY ANALYSIS?
6 A. If the Project is delayed by 24 months beyond the current forecasted in-service dates, the 7 Project would be uneconomic by about $0.3 billion. The following table contains the 8 matrix of results for all nine combinations of fuel and carbon dioxide cases.
Table 4 Staff Cost To Complete Economic Evaluation 92-Month Delay Case Economic Benefit of the Project Versus CC August 2018 Net Present Value Date (Billions of dollars, Negative Means Uneconomic)
$0/Ton $10/Ton $20/Ton Fuel CO2 CO2 CO2 Expected High 0.1 0.6 1.2 Value Moderate (1.0) (0.4) 0.1 (0.3) Low (1.7) (1.2) (0.6) 9 10 Q. DID STAFF DETERMINE HOW LONG OF A DELAY IT WOULD TAKE FOR 11 THE PROJECT TO BE UNECONOMIC ON AN EXPECTED VALUE BASIS?
12 A. Yes, Staff determined that if the Project were delayed by approximately 18 months beyond 13 the current forecasted in-service dates, it would no longer be economic.
14 Q. WHAT WOULD BE THE IMPACT ON STAFF’S COST TO COMPLETE
20
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 ECONOMIC ANALYSIS IF THE COMPANY’S RATHER THAN STAFF’S 2 INTERPRETATION OF THE 17th VCM ORDER AND SIR STIPULATION WAS 3 ASSUMED?
4 A. The economic benefit to complete the Project would increase from $1.0 billion to $1.1 5 billion, a change of approximately $100 million.
6
7 Other Issues
8 Q. DOES STAFF HAVE ANY COMMENTS REGARDING THE COMPANY’S 9 REPLACEMENT ENERGY COST AND DEFERRED OPERATING COST 10 RESULTS IN TABLE 1.2 OF THE COMPANY’S VCM 20/21 REPORT?
11 A. Yes. It appears the Company’s Table 1.2 indicates that over the delay period through June 12 30, 2019, customers have been harmed by $103 million based on this calculation.
13 Q. DOES STAFF AGREE WITH THE COMPANY’S RESULTS IN TABLE 1.2?
14 A. No. The premise behind the table is fundamentally flawed as it ignores the significant 15 additional financing revenue requirements being recovered from ratepayers during the 68- 16 month construction delay period that otherwise would not have been incurred had the 17 Project been completed on-time and on-budget. For the entire delay period through 18 November 2022 ratepayers will pay an additional $1.8 billion in NCCR revenue 19 requirement during the construction period due to the delays and cost overruns.23 For a 20 typical residential customer the additional amount collected through the NCCR tariff is
23 The $1.8 billion value reflects the difference in the current estimate of the NCCR revenue requirement that customers will have to pay, which is $3.9 billion, and the estimate of $2.1 billion that would have been paid had the Project been completed in 2016/2017 from the original Certification.
21
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 approximately $385 during the construction period.24 The Company will also recover an 2 additional $309 million of financing cost that will be deferred and collected from customers 3 over the operating life of the Units due to the delays and cost overruns. Finally, Staff 4 estimates that after the Units go into service, the peak base rate impact for a typical 5 residential customer will be more than double what the Company told the Commission at 6 certification. Clearly the delays and cost overruns add additional costs to ratepayers that 7 are much greater than just the $103 million shown in Table 1.2
8 Q. YOU MENTIONED ABOVE THAT THE PURPOSE OF A COST TO COMPLETE 9 ANALYSIS IS TO EXAMINE WHETHER IT WOULD BE ECONOMIC TO 10 FINISH A PROJECT, BUT DOES IT PROVIDE AN INDICATION OF THE 11 TOTAL AMOUNT OF REVENUE REQUIREMENTS CUSTOMERS WILL HAVE 12 TO PAY FOR A PROJECT?
13 A. No, it does not. As Mr. Hayet has testified in prior VCMs,25 a life-cycle analysis would 14 provide additional useful information, including an indication of the total amount of 15 revenue requirements customers would have to pay for the Vogtle Project. Essentially, the 16 life-cycle analysis would show what ratepayers would have to pay for Vogtle Units 3 and 17 4 over the life of the Units versus what ratepayers would have to pay for a combined cycle 18 unit under various scenarios.
19 Q. HOW DO THE LIFE CYCLE NOMINAL REVENUE REQUIREMENTS 20 COLLECTED FROM RATEPAYERS COMPARE BETWEEN THE CASE WITH 21 VOGTLE UNITS 3 AND 4 AND THE CASE WITH THE COMBINED CYCLE 22 UNIT?
24 Staff also estimates that the total amount collected from a typical residential customer during the construction period will be approximately $833 over the life of the NCCR tariff. 25 Docket 29849, Philip Hayet Direct Testimony, Eighth VCM Proceeding, pages 19 – 22, and Twelfth VCM Proceeding, pages 29-30. 22
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
1 A. Staff has created a comparison of the projected cumulative nominal revenue requirements 2 (fuel, O&M, and capital costs) of Vogtle Units 3 and 4 that will be collected from 3 ratepayers to the replacement combined cycle unit for each of the three natural gas price 4 forecast scenarios. In the case of the combined cycle unit, Staff added all of the System 5 replacement fuel and O&M costs to the capital revenue requirements of the replacement 6 combined cycle unit. Nominal revenue requirements are used in this analysis to indicate 7 the impact on ratepayer bills.
8 Q. HOW DOES THE CUMULATIVE NOMINAL REVENUE REQUIREMENT OF 9 VOGTLE 3 & 4 COMPARE TO THE COMBINED CYCLE UNIT ASSUMING A
10 LOW NATURAL GAS PRICE FORECAST UNDER THE THREE CO2 EMISSION 11 PRICE FORECAST CASES?
12 A. As indicated in the graph below for the Low Natural Gas price forecast, the Vogtle Units 13 3 & 4 cumulative nominal revenue requirement exceeds the combined cycle nominal
14 revenue requirement under all three CO2 emission price forecasts.
23
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
Vogtle 3&4 Versus Combined Cycle Low Gas Price Forecast Cumulative Nominal Revenue Requirements (Millions of Dollars) $80,000 Vogtle 3&4 $70,000 CCGT $0 CO2 CCGT $10 CO2 $60,000 CCGT $20 CO2
$50,000
$40,000
$30,000
$20,000
$10,000
$0
1 2
3 Q. HOW DOES THE CUMULATIVE NOMINAL REVENUE REQUIREMENT OF 4 VOGTLE 3&4 COMPARE TO THE COMBINED CYCLE UNIT ASSUMING A
5 MODERATE NATURAL GAS PRICE FORECAST UNDER THE THREE CO2 6 EMISSION PRICE FORECAST CASES?
7 A. The Vogtle 3&4 cumulative nominal revenue requirement exceeds the combined cycle 8 nominal revenue requirement under all three CO2 emission price forecasts.
24
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
Vogtle 3&4 Versus Combined Cycle Mod Gas Price Forecast Cumulative Nominal Revenue Requirements (Millions of Dollars) $80,000 Vogtle 3&4 $70,000 CCGT $0 CO2 $60,000 CCGT $10 CO2 CCGT $20 CO2 $50,000
$40,000
$30,000
$20,000
$10,000
$0
1 2 3 Q. HOW DOES THE CUMULATIVE NOMINAL REVENUE REQUIREMENT OF 4 VOGTLE 3&4 COMPARE TO THE COMBINED CYCLE UNIT ASSUMING A
5 HIGH NATURAL GAS PRICE FORECAST UNDER THE THREE CO2 EMISSION 6 PRICE FORECAST CASES?
7 A. The Vogtle 3&4 cumulative nominal revenue requirement exceeds the combined cycle 8 nominal revenue requirement under the $0/Ton case for the entire period, and it exceeds
9 the $10/Ton CO2 emission price forecast case almost until the end of the period. Under the
10 $20/Ton CO2 emission price forecast, the Vogtle 3&4 cumulative nominal revenue 11 requirement exceeds the combined cycle nominal revenue requirement until 2072.
25
Docket No. 29849 Testimony of Tom Newsome and Twentieth/Twenty-First Semi-Annual Vogtle Construction Philip Hayet Monitoring Filing
Vogtle 3&4 Versus Combined Cycle High Gas Price Forecast Cumulative Nominal Revenue Requirements (Millions of Dollars) $90,000
$80,000 Vogtle 3&4 CCGT $0 CO2 $70,000 CCGT $10 CO2 $60,000 CCGT $20 CO2
$50,000
$40,000
$30,000
$20,000
$10,000
$0
1 2 3 Q. WHAT WOULD THE RESULTS OF A TRADITIONAL ECONOMIC ANALYSIS 4 USING PRESENT VALUE DOLLAR RESULTS INDICATE?
5 A. When the life-cycle revenue requirement results are compared on a cumulative present 6 value basis, the Vogtle Units revenue requirements are greater than the combined cycle
7 revenue requirements every year in all nine of the natural gas price and CO2 emission price 8 cases.
9 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
10 A. Yes, it does.
26
BEFORE THE GEORGIA PUBLIC SERVICE COMMISSION
IN THE MATTER OF: GEORGIA POWER COMPANY’S TWENTIETH/TWENTY- DOCKET NO. 29849 FIRST SEMI-ANNUAL VOGTLE CONSTRUCTION MONITORING REPORT
EXHIBIT
STF-NH-1
Exhibit___(STF-NH-1) Page 1
Summary of Educational and Professional Experience of Tom J. Newsome
Mr. Newsome received a Bachelor of Chemical Engineering with certificates in Pulp & Paper and Polymers from the Georgia Institute of Technology in June 1986. In 1994, Mr. Newsome passed both required examinations and received a professional engineering license (PE) from the State of North Carolina. Mr. Newsome received a Master of Science in Business Economics and a Master of Science in Finance from Georgia State University in August 1996 and June 1997, respectively. Mr. Newsome is the recipient of the George J. Malanos Graduate Award for Academic Excellence for completing the finance program with a 4.0 grade-point average. In 2003, Mr. Newsome received Chartered Financial Analyst (CFA) designation from the CFA Institute after successfully completing three six-hour examinations on security analysis and portfolio management.
After graduation from Georgia Tech, Mr. Newsome worked as plant/process engineer for Shaw Industries, a carpet manufacturer. In April 1988, Mr. Newsome joined Weatherly, Inc., engineering and construction firm specializing in fertilizer plants, as a process engineer. Mr. Newsome’s primary responsibilities were process design and plant start-ups, including start-ups in Korea and India. Mr. Newsome joined Midrex Direction Reduction Corp., an applied research, engineering and construction firm with proprietary iron ore processing plant technology in March 1993 as a process engineer. Mr. Newsome duties were similar to those at Weatherly, including assisting in the start-up of the world’s largest Direct Reduction Iron plant in India.
Following graduation from graduate school at Georgia State, Mr. Newsome joined Georgia Gulf Corporation in 1997 as a corporate development analyst. While at Georgia Gulf, Mr. Newsome performed financial analysis and modeling for natural gas purchasing/hedging program, developed a “make-or-buy” model for methanol business, performed financial modeling for an acquisition, and calculated and summarized the financial performance of prior capital investments. In 1999, Mr. Newsome joined FMV Opinions, Inc. as a business valuation analyst and valued private companies for gift and estate tax, transactional and management planning purposes.
Mr. Newsome joined the Georgia Public Service Commission (“Commission”) in January 2005 as a Financial Analyst/Economist. Mr. Newsome was promoted to Director of Utility Finance in 2008.
Mr. Newsome has testified in thirteen Georgia Power Company (“Company” or “Georgia Power”) proceedings before the Commission. Mr. Newsome’s most recent testimony was in Docket 42310 Georgia Power Company’s 2019 Integrated Resource Plan on supply side and certain other issues. Prior to that testimony Mr. Newsome testified in Docket 29849 19th Vogtle Construction Monitoring (“VCM”), 18th VCM and 17th VCM on the economics of continuing Vogtle 3 and 4 construction and provided the Commission policy recommendations to protect ratepayers. Prior to testifying in the 17th VCM Mr. Newsome testified in the 2016 Integrated Resource Plan on the Company’s requested to capitalize cost for investigation of new nuclear units. Mr. Newsome’s testified in Docket No. 39638 Fuel Cost Recovery (FCR-24) on the Company’s natural gas hedging program. In Docket No. 22403, Mr. Newsome addressed Georgia Power Company’s natural gas
1
Exhibit___(STF-NH-1) Page 2 hedging program and in Docket No. 24506 Mr. Newsome testified on the application of AFUDC accounting for calculating financing cost of capital projects. In Docket No. 27800, Certification of Plant Vogtle Expansion, Mr. Newsome addressed the sources, impact and mitigation of financial risk from the construction and operation of new nuclear units at Plant Vogtle. Mr. Newsome testified in Docket No. 29849 concerning Georgia Power’s First Semi-annual Construction Monitoring Report on Plant Vogtle expansion. Mr. Newsome evaluated the economic analysis performed by Georgia Power and developed Staff’s own independent economic and risk analysis of the Project. In the Second Vogtle Semi-annual hearing, Mr. Newsome testified on the Company’s proposal to change how escalation on certain project cost was calculated (Amendment 3). In the Third Vogtle Semiannual hearing and in separate proceeding, Adoption of a Risk Sharing Mechanism, Mr. Newsome testified on Staff’s revised risk sharing mechanism for Vogtle 3 & 4. In Docket No. 28945 Fuel Cost Recovery FCR–21, Mr. Newsome testified on seasonal rates. Mr. Newsome also presented cost of equity testimony in Atmos Energy Corporation’s Rate Case in Docket No. 30442 and Generic Proceeding to Implement House Bill 168 (small telephone companies) in Docket No. 32235 in 2011 and 2018. Mr. Newsome provided testimony before the Commission in Georgia Power’s 2013 Base Rate Case in Docket No. 36989 on the Company’s projected cost of debt for 2014 – 2016. Mr. Newsome’s primarily responsibility, prior to presenting testimony in these dockets, has been performing analyses of the parties’ cost of equity capital positions in Docket Nos. 18638 (Atlanta Gas Light Company 2004/2005 Rate Case), 19758 (Savannah Electric and Power Company 2004 Rate Case), 20298 (Atmos Energy Corporation - Georgia Division 2005 Rate Case), 25060 (Georgia Power Co. 2007 Rate Case) and 27163 (Atmos Energy Corporation - Georgia Division 2008 Rate Case) and developing the Advisory PIA Staff’s cost of equity recommendation to the Commission.
2
BEFORE THE GEORGIA PUBLIC SERVICE COMMISSION
IN THE MATTER OF: GEORGIA POWER COMPANY’S TWENTIETH/TWENTY- DOCKET NO. 29849 FIRST SEMI-ANNUAL VOGTLE CONSTRUCTION MONITORING REPORT
EXHIBIT
STF-NH-2
Exhibit___(STF-NH-2) Page 1
QUALIFICATIONS OF PHILIP HAYET
EDUCATION/CERTIFICATION
M.S., Electrical Engineering, Georgia Institute of Technology, 1980 B.S., Electrical Engineering, Purdue University, 1979 Cooperative Education Certificate, Purdue University, 1979
PROFESSIONAL AFFILIATIONS
National Society of Professional Engineers Georgia Society of Professional Engineers Institute of Electrical and Electronic Engineers
EXPERIENCE
Since completing his Master’s program, Mr. Hayet worked for fifteen years at Energy Management Associates, now Ventyx, providing consulting services and client service support to electric utility companies for the widely used planning models, PROMOD IV and STRATEGIST. Mr. Hayet had an instrumental role in designing some of the modeling features of those tools including the competitive market modeling logic in STRATEGIST.
In 1995, Mr. Hayet began his own utility consulting firm, Hayet Power Systems Consulting (“HPSC”), and has worked for customers in the United States, and internationally in Australia, Japan, Singapore, Malaysia, the United Kingdom, and Vietnam. Over his more than 30-year career, Mr. Hayet has provided consulting services to Public Utility Commissions, Regional Power Pools, State Energy Offices, Consumer Advocate Offices, Electric Utilities, Global Power Developers, and Industrial Companies. Mr. Hayet’s expertise covers a number of areas including utility system planning and operations, RTO analysis, market price forecasting, Integrated Resource Planning, renewable resource evaluation, transmission planning, demand-side analysis, and economic analysis.
In 2000 Mr. Hayet also joined the consulting firm of J. Kennedy & Associates, Inc. (“Kennedy and Associates”). Since joining, Mr. Hayet worked on Kennedy and Associates’ projects that required utility resource planning, analysis, and software modeling expertise. Mr. Hayet became a Vice- President and Principal of Kennedy and Associates in 2015.
Mr. Hayet has conducted numerous consulting studies in the areas of RTO Cost/Benefit Analysis, Renewable Resource Evaluation, Renewable Portfolio Standards Evaluation, Electric Market Price Forecasting, Generating Unit Cost/Benefit Analysis, Integrated Resource Planning, Demand-Side Management, Load Forecasting, Rate Case Analysis and Regulatory Support.
2000 to J. Kennedy and Associates, Inc.
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 2
QUALIFICATIONS OF PHILIP HAYET
Present: Vice President and Principal
• Initially began as Director of Consulting, became Vice President and Principal in 2015 • Managed electric related consulting projects. • Responsible for business development. • Clients include Staffs of Public Utility Commissions and other State Agencies, State Energy Offices, Global Power Developers, and Industrial Groups, and large energy users.
1996 to Hayet Power Systems Consulting Present: President and Principal
• Managed electric utility related consulting projects • Clients include Staffs of Public Utility Commissions and other State Agencies, State Energy Offices, Global Power Developers, and Industrial Groups, and large energy users.
1991 to EDS Utilities Division, Atlanta, GA (Now Ventyx) 1996: Lead Consultant, PROSCREEN (Now STRATEGIST) Department
• Managed a client services software team that supported approximately 75 users of the STRATEGIST electric utility strategic planning software. • Participated in the development of STRATEGIST’s competitive market modeling features and the Network Economy Interchange Module • Provided client management direction and support, and developed new consulting business opportunities. • Performed system planning consulting studies including integrated resource planning, DSM analysis, marketing profitability studies, optimal reserve margin analyses, etc. • Based on experience with PROMOD IV, converted numerous PROMOD IV databases to STRATEGIST, and performed benchmark analyses of the two models.
1988 to Energy Management Associates (EMA), Atlanta, GA 1991: Manager, Production Analysis Department
• Served as Project Manager of a database modeling effort to create an integrated utility operations and generation planning database. Database items were automatically fed into PROMOD IV. • Supervised and directed a staff of five software developers working with a 4GL database programming language.
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 3
QUALIFICATIONS OF PHILIP HAYET
• Interfaced with clients to determine system software specifications, and provide ongoing client training and support
1980 to Energy Management Associates (EMA), Atlanta, GA 1988: Senior Consultant, PROMOD IV Department
• Provided client service support to EMA’s base of over 70 electric utility customers using the PROMOD IV probabilistic production cost simulation software. • Provided consulting services in a number of areas including generation resource planning, regulatory support, and benchmarking.
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 4
QUALIFICATIONS OF PHILIP HAYET
TESTIMONY AND EXPERT WITNESS APPEARANCES
Date Case Jurisdict Party Utility Subject 09/98 97-035-01 UT Utah Committee PacifiCorp Utah jurisdictional Net Power Costs, for Consumer PacifiCorp Rate Case Proceeding Services 07/01 01-035-01 UT Utah Committee PacifiCorp Utah Jurisdictional Net Power costs in for Consumer General Rate Case Services 2001 ER00-2854- FERC Louisiana Public Entergy Proposed System Agreement 000 Service Modifications Commission 07/02 02-035-002 UT Utah Committee PacifiCorp Special contract for industrial consumer for Consumer Services 2002/ U-25888 LA Louisiana Public Entergy Investigation of retail issues related to 2003 Service the System Agreement Commission 2003 U-27136 LA Louisiana Public Entergy Aging gas steam-fired retirement study Subdocket A Service Commission Staff 07/03 EL01-88- FERC Louisiana Public Entergy Rough production cost equalization 000 Service proceeding Commission 05/04 03-035-14 UT Utah Committee PacifiCorp Development of a large QF avoided for Consumer cost methodology Services 06/04 18687-U GA Georgia Public Georgia Power 2004 Integrated Resource Planning Service and Savannah Studies 18688-U Commission Staff Electric 08/04 ER03-583- FERC Louisiana Public Entergy Affiliate power purchase agreements 000 Service Commission 11/04 03-035-19 UT Utah Committee PacifiCorp Industrial customer’s request for a for Consumer special economic development tariff Services 11/04 03-035-38 UT Utah Committee PacifiCorp Large QF proceeding. for Consumer Services 03/05 03-035-14 UT Utah Committee PacifiCorp Concerning PacifiCorp’s Schedule 38
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 5
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject for Consumer avoided cost tariff and remaining Services unsubscribed capacity 07/05 03-035-14 UT Utah Committee PacifiCorp Concerning PacifiCorp’s Schedule 38 for Consumer avoided cost proceeding Services 12/05 04-035-42 UT Utah Committee PacifiCorp Net power costs in General Rate Case for Consumer Services 04/06 05-035-54 UT Utah Committee PacifiCorp Certification request to expand Blundell for Consumer Geothermal Power Station. Related to Services Mid-American Energy Holding’s Acquisition of PacifiCorp 05/06 22403-U GA Georgia Public Georgia Power March 2006 fuel cost recovery filing Service and Savannah Commission Staff Electric 2006 06-35-01 UT Utah Committee PacifiCorp 2006 rate case, net power costs for Consumer Services 08/06 U-21453 LA Louisiana Public Entergy Gulf Jurisdictional separation. Service States Commission Staff 11/06 U-25116 LA Louisiana Public Entergy Fuel adjustment clause filings Service Louisiana Commission Staff 01/07 23540-U GA Georgia Public Georgia Power November 2005 fuel cost recovery Service filing Commission Staff 04/07 07-035-93 UT Utah Committee PacifiCorp General Rate Case for Consumer Services 06/07 24505-U GA Georgia Public Georgia Power 2007 Integrated Resource Planning Service Commission Staff 10/07 U-30334 LA Louisiana Public Cleco Power 2008 Short-Term RFP Service Commission Staff 04/08 26794-U GA Georgia Public Georgia Power Fuel cost recovery filing (FCR-20) Service Commission Staff
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 6
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject 2008 6630-CE- WI Wisconsin WEPCO Certification Proceeding for 299 Industrial Energy environmental upgrades at Oak Creek Group, Inc. power plant 07/08 ER07-956 FERC Louisiana Public Entergy 2006 rough production cost equalization Service compliance filing in the System Commission Agreement case 09/08 6680-CE- WI Wisconsin Wisconsin Certification proceeding concerning 180 Industrial Energy Power and Light Nelson-Dewey coal-fired generating unit Group, Inc. 11/08 08-1511-E- WV West Virginia Allegheny Fuel cost recovery filing GI Energy Users Power Group 12/08 27800-U GA Georgia Public Georgia Power Vogtle 3 and 4 nuclear unit certification Service proceeding Commission Staff 2008 08-035-35 UT Utah Committee PacifiCorp Chehalis Combine Cycle Power Plant for Consumer based on a waiver of the RFP solicitation Services process certification proceeding 07/09 ER08-1056 FERC Louisiana Public Entergy 2007 rough production cost equalization Service compliance filing in the System Commission Agreement case 07/09 U-30975 LA Louisiana Public SWEPCO and Application to acquire the Oxbow Mine Service Cleco to supply Dolet Hills Power Station Commission Staff certification proceeding 09/09 E015/PA- MN Large Power Minnesota Request for approval to purchase Square 09-526 Intervenors Power Butte’s 500 kV DC transmission line, restructure a coal based power purchase agreement 09/09 09-035-23 UT Utah Office of PacifiCorp 2009 rate case, net power costs Consumer Services Direct 10/09 09A-415E CO Public Utilities Black CPCN application to construct two LMS Commission of Hills/Colorado 100 natural gas combustion turbine units Colorado 10/09 09-035-23 UT Utah Office of PacifiCorp 2009 rate case, net power costs Consumer Services Surrebuttal 12/09 29849-U GA Georgia Public Georgia Power First Semi-Annual Vogtle Construction Service Monitoring Report Commission Staff
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 7
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject 12/09 ER08-1224 FERC Louisiana Public Entergy 2008 production costs used to develop Service bandwidth payments Commission 2009 09-2035-01 UT Utah Office of PacifiCorp 2008 IRP Consumer Services 01/10 28945-U GA Georgia Public Georgia Power Fuel cost recovery filing Service Commission Staff 2010 EL09-61 FERC Louisiana Public Entergy System Agreement, individual operating Service company sales Commission 06/10 29849-U GA Georgia Public Georgia Power Second Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 12/10 29849-U GA Georgia Public Georgia Power Third Semi-Annual Vogtle Construction Service Monitoring Report Commission Staff 01/11 ER09-1350 FERC Louisiana Public Entergy 2008 production costs used to develop Service bandwidth payments Direct Commission 02/11 ER09-1350 FERC Louisiana Public Entergy 2008 production costs used to develop Service bandwidth payments Cross- Commission Answering 04/11 33302-U GA Georgia Public Georgia Power Fuel cost recovery filing (FCR-22) Service Commission Staff 06/11 29849-U GA Georgia Public Georgia Power Fourth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 09/11 U-31892 LA Louisiana Public Cleco Power Settlement agreement, CPCN to upgrade Service Madison 3 coal unit to accommodate Commission Staff biomass fuel 11/11 26550-U GA Georgia Public Georgia Power Reacquisition of wholesale block Service capacity Commission Staff 11/11 34218-U GA Georgia Public Georgia Power Decertification of two aging coal units, Service acquire PPA resources, approve IRP Commission Staff update
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 8
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject 12/11 29849-U GA Georgia Public Georgia Power Fifth Semi-Annual Vogtle Construction Service Monitoring Report Commission Staff 03/12 U-32148 LA Louisiana Public Entergy Change of Control Proceeding to move Service to Midwest ISO Commission Staff 2012 20000-EA- WY Wyoming Rocky Certification of environmental upgrades 400-11 Industrial Energy Mountain at Naughton 3 Consumers Power 05/12 35277-U GA Georgia Public Georgia Power Fuel cost recovery filing (FCR-23) Service Commission Staff 05/12 29849-U GA Georgia Public Georgia Power Sixth Semi-Annual Vogtle Construction Service Monitoring Report Commission Staff 07/12 2012-00063 KY Kentucky Big Rivers Environmental upgrades in compliance Industrial Utility with MATS and CSAPR Customers, Inc. 09/12 U-32275 LA Louisiana Public Dixie Electric Ten year power supply acquisition Service Member certification proceeding Commission Staff Cooperative 12/12 EL09-61- FERC Louisiana Public Entergy Harm calculation, violation of System 002 Direct Service Agreement Commission 12/12 U-32557 LA Louisiana Public Entergy Certification of 28 MW PPA for Service renewable energy capacity (RAIN waste Commission Staff heat) in accordance with LPSC’s Renewable Energy Pilot 12/12 U-29764 LA Louisiana Public Entergy Retail proceeding regarding termination Service of cross-PPAs Commission Staff 12/12 29849-U GA Georgia Public Georgia Power Seventh Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 03/13 EL09-61- FERC Louisiana Public Entergy Harm calculation, violation of System 002 Cross- Service Agreement Answering Commission
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 9
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject 04/13 2012-00578 KY Kentucky Industrial Kentucky Mitchell Certificate of Public Utility Customers, Power Convenience and Necessity Inc. Company 05/13 36498-U GA Georgia Public Georgia Power 2013 IRP and request to decertify over Service 2,000 MW of coal-fired capacity Commission Staff 07/13 U-32785 LA Louisiana Public Entergy 8.5 MW PPA for renewable energy Service capacity (Agrilectric rice hull) in Commission Staff accordance with LPSC’s Renewable Energy Pilot 08/13 29849-U GA Georgia Public Georgia Power Eighth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 10/13 2013-00199 KY Kentucky Industrial Big Rivers Base rate case Utility Customers, Inc. 05/14 13-035-184 UT Utah Office of PacifiCorp 2014 General Rate Case, net power cost Consumer Services 06/14 29849-U GA Georgia Public Georgia Power Ninth/Tenth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 07/14 20000-446- WY Wyoming PacifiCorp 2014 General Rate Case, net power cost EA-14 Industrial Energy Consumers 08/14 2000-447- WY Wyoming PacifiCorp 2014 Energy Cost Adjustment EA-14 Industrial Energy Mechanism application Consumers 08/14 14-035-31 UT Utah Office of PacifiCorp 2014 Energy Balancing Adjustment Consumer Services application 09/14 ER13-432 FERC Louisiana Public Entergy Allocation of Union Pacific Settlement Service Agreement benefits Commission 10/14 2014-00225 KY Kentucky Industrial Kentucky Kentucky Power Company’s Fuel Utility Customers, Power Adjustment Clause Inc. 12/14 29849-U GA Georgia Public Georgia Power Eleventh Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 10
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject 05/15 14-035-140 UT Utah Office of PacifiCorp Solar and wind capacity contribution Consumer Services avoided cost proceeding. 06/15 29849-U GA Georgia Public Georgia Power Twelfth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 08/15 15-035-03 UT Utah Office of PacifiCorp 2015 Energy Balancing Adjustment Consumer Services application 09/15 14-035-114 UT Utah Office of PacifiCorp Cost and Benefits of PacifiCorp’s Net Consumer Services Metering Program 11/15 39638-U GA Georgia Public Georgia Power FCR-24 Fuel Cost Recovery Proceeding Service Commission Staff 11/15 29849-U GA Georgia Public Georgia Power Thirteenth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 5/16 40161 GA Georgia Public Georgia Power Georgia Power Company’s 2016 IRP Service and Application for Decertification of Commission Staff Plant Mitchell Units 3, 4A, and 4B, Kraft Unit 1 CT, and Intercession City CT 6/16 29849 GA Georgia Public Georgia Power Fourteenth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 8/16 16-035-27 UT Utah Office of PacifiCorp Renewable Energy Services Contract Consumer Services between Rocky Mountain Power and Facebook, Inc 8/16 16-035-01 UT Utah Office of PacifiCorp 2016 Energy Balancing Adjustment Consumer Services application 9/16 09-035-15 UT Utah Office of PacifiCorp EBA Pilot Evaluation Direct Testimony Consumer Services 11/16 29849-U GA Georgia Public Georgia Power Fifteenth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 11/16 09-035-15 UT Utah Office of PacifiCorp EBA Pilot Evaluation Rebuttal Consumer Services Testimony 11/16 EL09-61-04 FERC Louisiana Public Entergy Violation of System Agreement, Phase Service III, Harm Calculation, Direct Commission
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 11
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject 3/17 EL09-61-04 FERC Louisiana Public Entergy Violation of System Agreement, Phase Service III, Harm Calculation, Rebuttal Commission 6/17 29849-U GA Georgia Public Georgia Power Sixteenth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 9/17 17-035-39 UT Utah Office of PacifiCorp Approval of Resource Decision to Consumer Services Repower Wind Facilities, Direct 11/17 17-035-39 UT Utah Office of PacifiCorp Approval of Resource Decision to Consumer Services Repower Wind Facilities, Surrebuttal 4/18 17-035-39 UT Utah Office of PacifiCorp Approval of Resource Decision to Consumer Services Repower Wind Facilities, Response 4/18 17-035-39 UT Utah Office of PacifiCorp Approval of Resource Decision to Consumer Services Repower Wind Facilities, Rebuttal to Response 12/17 17-035-40 UT Utah Office of PacifiCorp Approval of Resource Decision for New Consumer Services Wind and New Transmission, Direct 1/18 17-035-40 UT Utah Office of PacifiCorp Approval of Resource Decision for New Consumer Services Wind and New Transmission, Rebuttal 4/18 17-035-40 UT Utah Office of PacifiCorp Approval of Resource Decision for New Consumer Services Wind and New Transmission, Second Rebuttal 6/18 29849-U GA Georgia Public Georgia Power Eighteenth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 8/18 Cause 45052 IN Indiana Coal Vectren Energy Request for Approval of an 850 MW Council Delivery of CCGT Plant Indiana 9/18 U-34836 LA Louisiana Public Entergy Authorization to Participate in a 50 MW Service Louisiana, LLC Solar PPA Commission Staff 11/18 29849-U GA Georgia Public Georgia Power Nineteenth Semi-Annual Vogtle Service Construction Monitoring Report Commission Staff 1/19 U-35019 LA Louisiana Public Entergy Authorization to Make Available Service Louisiana Experimental Renewable Option and Commission Staff Rate Schedule RTO
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 12
QUALIFICATIONS OF PHILIP HAYET
Date Case Jurisdict Party Utility Subject 4/19 42310-U GA Georgia Public Georgia Power Georgia Power’s 2019 IRP Proceeding Service Commission Staff
ADDITIONAL JUDICIAL PROCEEDINGS AND OTHER PROJECT INFORMATION
1995 – 2000 - Modeled the Singapore Power Electricity System and analyzed the benefits of dispatching a new oil-fired unit within the system, BHP Power
1995 – 2000 - Modeled the Australian National Energy Market to develop market based energy price forecasts on behalf of an Independent Power Producer in Australia, BHP Power
1995 – 2000 - Analyzed the benefit of purchasing existing gas-fired steam turbine units within the Australian market, BHP Power
1995 – 2000 Developed market price forecasts for South Australia as part of the evaluation of a new gas fired combined cycle unit, BHP Power
1995 – 2000 - Modeled the Vietnam Electricity System as part of a project to develop Least Cost Expansion plans for Vietnam, EVN State Utility
1995 – 2000 - Assisted in the evaluation of Phu My CCGT power plant in Vietnam, BHP Power
1995 – 2000 - Assisted in the development of Market Price Forecasts in several regions of the US. These forecasts were used as the basis for stranded cost estimates, which were filed in testimony in a number of jurisdictions across the country.
1995 – 2000 - Conducted research regarding ISO Tariffs and Operations for the PJM Power Pool, the California ISO, and the Midwest ISO on behalf of a Japanese Research.
1995 – 2000 - Performed research on numerous electric utility issues for 3 Japanese research organizations. This was primarily related to deregulation issues in the US in anticipation of deregulation being introduced in Japan.
1995 – 2000 - Critiqued the IRP filings of 5 utilities in South Carolina on behalf of the South Carolina State Energy Office
1999 - Helped to analyze the rate structure and develop an electricity price forecast for the Metropolitan Atlanta Rapid Transit Authority (MARTA) in Atlanta, Georgia
August 2002 – Expert Report, Civil Action No. 1:00-cv-1262 in the United Stated District Court for the Middle District of North Carolina, United States v. Duke Energy Corporation, Department of Justice
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 13
QUALIFICATIONS OF PHILIP HAYET
2002 - Worked on behalf of the Utah Committee of Consumer Services to provide guidance and assist in the analysis of PacifiCorp’s 2002 Integrated Resource Plan.
July 2003 - Worked on behalf of the Oregon Public Utility Commission to Audit PacifiCorp’s Net Power Costs per a Settlement Agreement accepted by the Public Utility Commission of Oregon in its Order No. 01-787. Audit report in Docket No. UE-116 filed July 2003.
2003 - Regulatory support to the Utah Committee of Consumer Services regarding PacifiCorp’s 2003 Utah General Rate Case Docket # 03-2035-02.
2004 – Assistance to the Utah Committee of Consumer Services to analyze a series of power purchase agreements and special contracts between PacifiCorp and several of its industrial customers.
2005 - Worked on behalf of the Utah Committee of Consumer Services to help analyze PacifiCorp’s restructuring proposals.
2005 - Assisted the Utah Committee of Consumer Services by evaluating PacifiCorp’s 2005 IRP and assisted in writing comments that were filed with the Commission.
2007 - Assisted the Utah Committee of Consumer Services to evaluate PacifiCorp’s 2007 IRP.
2007 - Conducted an investigation of the Southern Company interchange accounting and fuel accounting practices on behalf of the Georgia Public Service Commission Staff (Docket 21162-U).
2008 - Assisted the Louisiana Public Service Commission Staff with the review and evaluation of Cleco Power’s 2008 Short Term RFP and its 2010 Long-Term RFP.
2008 - Assisted the Utah Committee of Consumer Services by participating in a collaborative process to develop an avoided cost tariff for large QFs.
2008 - Assisted the Louisiana Public Service Commission Staff with a rulemaking for the opportunity to implement a Renewable Portfolio Standard in Louisiana. (Docket No. R-28271 Sub-Docket B)
April 2011 – Initial Expert Report, Civil Action No. 2:10-cv-13101-BAF-RSW, on behalf of the Department of Justice in US District Court, United States v.Detroit Edison
June 2011 – Rebuttal Expert Report, Civil Action No. 2:10-cv-13101-BAF-RSW, on behalf of the Department of Justice in US District Court, United States Detroit Edison • 2011 - Assisted the Georgia Public Service Commission Staff to investigate the acquisition of additional coal and combustion turbine capacity currently wholesale capacity (Docket 26550).
______J. Kennedy and Associates, Inc.
Exhibit___(STF-NH-2) Page 14
QUALIFICATIONS OF PHILIP HAYET
• 2012 - Assisted the Louisiana Public Service Commission Staff with a rulemaking to design Integrated Resource Planning (“IRP”) rules. (Docket No. R-30021) • December 2013 – Expert Report, Civil action no. 4:11-cv-00077-RWS, on behalf of the Department of Justice in US District Court, United States v. Ameren Missouri.
PUBLICATIONS AND PRESENTATIONS
Co-authored “Review of EPA’s Section 111(d) CO2 Emission Rate Goals for the State of Montana, on behalf of the Montana Large Customer Group, October 2014. Authored “Singapore’s Developing Power Market”, which appeared in the July/August 1999 edition of Power Value Magazine Co-authored “The New Energy Services Industry – Part 1”, which appeared in the January/February 1999 edition of Power Value Magazine. Co-authored and Presented “Evaluation of a Large Number of Demand-Side Measures in the IRP Process: Florida Power Corporation’s Experience”, Presented at the 3rd International Energy and DSM Conference, Vancouver British Columbia, November 1994 Co-authored “Impact of DSM Program on Delmarva’s Integrated Resource Plan”, Published in the 4th International Energy and DSM Conference Proceedings, held in Berlin, Germany, 1995 Presentation – Law Seminars International, Electric Utility Rate Cases, Case Study of the Louisiana Public Service Commission’s Quick Start Energy Efficiency Program, March 2015.
______J. Kennedy and Associates, Inc.
BEFORE THE GEORGIA PUBLIC SERVICE COMMISSION
IN THE MATTER OF GEORGIA POWER COMPANY’S TWENTIETH AND TWENTY-FIRST SEMI-ANNUAL VOGTLE CONSTRUCTION MONITORING REPORT
PUBLIC DISCLOSURE
DOCKET NO. 29849
DIRECT TESTIMONY
OF
DON GRACE
ON BEHALF OF THE
GEORGIA PUBLIC SERVICE COMMISSION
PUBLIC INTEREST ADVOCACY STAFF
NOVEMBER 22, 2019
TABLE OF CONTENTS
Introduction…………………………………………………...... 1
Purpose of Testimony………………………………………...... 3
Schedule Analysis and Conclusions……..……………………………………………….5
Bulk Commodity Unit Rates……….………………………...... 7
Unit 3, Project Performance Measures……………………....11
Planned & Actual Production Rates…………………………13
Unit 3, Construction Turnovers to ITP..………………….....20
Complexity of Planning & Executing Future Work………..24
Summary Schedule Analysis ………………………….….…30
Cost Analysis and Conclusions..………………….………….33
Exhibits:
1. Exhibit A: Don Grace Resume
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 1
1 INTRODUCTION 2 3 Q. PLEASE STATE YOUR NAME, POSITION, AND BUSINESS ADDRESS.
4
5 A. My name is Don Grace, and I am the Vice President of Engineering for the Vogtle
6 Monitoring Group (“VMG”). I am one of the key personnel engaged by the Georgia
7 Public Service Commission (“GPSC”) Public Interest Advocacy (“PIA”) Staff since April
8 2018 to independently evaluate Southern Nuclear Company’s (“SNC”) ability to
9 successfully manage completion of the Vogtle 3 & 4 Nuclear Project (“Project”). I have
10 over 50 years of hands on experience in all phases of the electrical generating plant life
11 cycle (i.e., Licensing/Permitting, Engineering, Construction, Start-up Testing and
12 Commissioning, Operations & Maintenance, and Decommissioning) for nuclear and fossil
13 fuel plants. I have a B.S in Marine Engineering from the U.S. Naval Academy (having
14 graduated with distinction), an MBA from Harvard Graduate School of Business (having
15 been awarded a fellowship) and have been a registered Professional Engineer in the field
16 of Power Generation for over 45 years. A copy of my curriculum vitae is attached as
17 Exhibit A.
18
19 Q. PLEASE PROVIDE ADDITIONAL INFORMATION REGARDING THE OTHER
20 KEY VMG TEAM MEMBERS, AND THE ROLES THEY PLAY IN
21 SUPPORTING YOUR TESTIMONY.
22
1
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 2
1 A. There are two additional key members of VMG that support my testimony. Mr. Dinos
2 Nicolaou has an MBA degree and is a highly experienced Project Controls professional
3 with over 45 years in developing and maintaining Earned Value Management System
4 (“EVMS”) based Integrated Project Schedules (“IPS”). He has performed dozens of
5 independent cost and schedule reviews of other major projects. Mr. Ray Bryant is a
6 highly experienced construction management professional with over 40 years in
7 construction management with a focus on nuclear electrical and security oversight. Mr.
8 Bryant functions as a full-time on-site construction monitor at the Project site. Other
9 subject matter experts are engaged on an as needed basis.
10
11 Q. WHAT ARE YOUR CRITERIA FOR SUCCESSFUL MANAGEMENT OF A
12 PROJECT LIKE VOGTLE 3 AND 4?
13
14 A. It includes SNC’s ability to safely complete the Project in a quality manner while meeting
15 SNC’s forecast Commercial Operations Dates (“CODs”) of November 2021 for Unit 3
16 and November 2022 for Unit 4, while also staying within or below SNC’s Total Project
17 Cost (“TPC”) forecast of $ 17.1 B.1
18
19 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE OTHER REGULATORY
20 AGENCIES, AND SPECIFICALLY BEFORE THE GPSC?
21
1 This TPC of $ 17.1 B represents all of the equity owners’ cost (i.e., represents 100% equity ownership, and not just Georgia Power Company’s 45.7% ownership, and excludes all financing related costs). 2
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 3
1 A. I have previously provided written testimony to the GPSC regarding the Project in
2 November 2018, and oral testimony in December 2018. Also, I have testified before the
3 Mississippi Public Service Commission, the Arizona Corporate Commission, and the
4 Arkansas Attorney General’s Office. I have also testified before the Nuclear Regulatory
5 Commission, in my capacity as the Chairman of the Boiling Water Reactor Owners’
6 Group.
7
8 PURPOSE OF TESTIMONY
9
10 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
11
12 A. The purpose of my testimony is to first describe how VMG utilized data provided by either
13 SNC /or Georgia Power Company (“GPC”) to perform independent analyses of the
14 Project Schedule and Cost. Based on these analyses, I will then provide VMG’s
15 conclusions regarding the Project Schedule and Cost.
16
17 Q. PLEASE PROVIDE YOUR SUMMARY CONCLUSIONS.
18
19 A. With respect to the aggressive target CODs of May 23, 2021 and May 23, 2022, it is
20 VMG’s opinion that these dates cannot be achieved. With respect to the Commission
21 Approved CODs of November 2021 and November 2022, unless performance improves
22 significantly, those dates are significantly challenged.
3
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 4
1 With respect to the TPC, assuming the current performance trends continue the $17.1B
2 may be exceeded. The degree to which it will be exceeded relies on two primary factors;
3 i.e., (a) schedule delay costs, which the Georgia Power Nuclear Development Group has
4 advised us are estimated to be $100M per month, and are related primarily to the ability to
5 complete construction work at the planned rate, and (b) poor Project productivity related
6 costs, which are dependent on the degree to which SNC’s Project performance does or
7 does not improve.
8
9 Q. PRIOR TO EXPLAINING THE SCHEDULE AND COST ANALYSES THAT
10 VMG HAS PERFORMED, ARE THERE ANY OTHER ISSUES THAT YOU
11 WANT TO FIRST ADDRESS?
12
13 A. Yes. I would like to note that in addition to our summary conclusions regarding the Project
14 Schedule and Cost, we find that the April 2019 Baseline does not represent a reasonable
15 plan for implementing and executing Project activities and reporting on the progress of the
16 Project. The primary reason for our determination that the April 2019 Baseline is
17 unreasonable, among others, is that the Integrated Project Schedule (“IPS”) is too
18 aggressive and the assumed commodity installation unit rates (electrical, piping, supports,
19 etc.) are not based on what craft labor (“Craft”) has been able to achieve to date.
20 Furthermore, we see no indication that SNC will be able to sufficiently improve
21 performance of craft labor to achieve the unit rates assumed in the April 2019 Baseline.
22
4
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 5
1 SNC’s strategic approach is in essence focused on completing the Project as soon as
2 possible because of an assumption that schedule delay costs outweigh consideration of
3 other cost increases (e.g., losses in productivity). To this end, SNC is focusing on systems
4 and systems testing prior to completing construction commodities that would (if first
5 completed) provide for a smoother transition to system testing. The risk in implementing
6 this approach is reduced efficiency (i.e., productivity) of the Construction effort, and this
7 risk has indeed been realized as we will show in our detailed analyses of both the
8 Schedule and Costs. Included in these detailed analyses will be the many “schedule risk
9 mitigation measures” being taken by SNC (which are not included in the April 2019
10 Schedule Baseline, and has further complicated the planning, execution, and reporting of
11 Project progress).
12
13 SCHEDULE ANALYSES
14
15 Q. PLEASE PRESENT YOUR SCHEDULE ANALYSES.
16
17 A. In order to provide context for the portions of the Schedule that we analyzed, I will first
18 provide an overview of the over-all Schedule. I will then address the “to date” Unit 3
19 actual schedule performance vs the planned construction performance for the period
20 encompassing the point in time when Bechtel, the Construction Contractor, started
21 reporting progress (i.e., October 2017) to the present. During this period of time, the June
22 2018 Baseline was established and subsequently SNC issued the April 2019 Baseline.
5
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 6
1
2 In analyzing the “to date” actual IPS performance, we focused primarily on the Unit 3
3 Construction and Initial Test Program Phases and then address the over-all Project
4 Schedule (to include Unit 4 and Balance of Plant (“BOP”)). The totality of these analyses
5 is then used to reach our final conclusion that the current Commission Approved
6 November COD’s will not, if the current schedule performance continues, be achieved.
7
8 Turning now to an overview perspective of the total remaining schedule:
9
10 a) The initial engineering and design efforts are for the most part complete, and
11 through August 2019 the over-all Project is reported by SNC to be 80.5 %
12 complete.
13
14 b) After construction completion of systems and ITP testing of each system, the
15 Project will be approaching the last 11 to 12 months of the Schedule at which point
16 integrated system tests are performed (e.g., Integrated Leak Rate Test of the
17 Containment, and Hot Functional Testing).
18
19 c) With successful completion of the above tests, including completion of the design-
20 specific pre-operational tests and a Nuclear Regulatory Commission finding in
21 accordance with 10 CFR 52.103(g) that all the acceptance criteria in the
22 “Inspections, Test, Analysis and Acceptance Criteria” (“ITAAC”) in Appendix C
6
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 7
1 to the Unit 3 Combined License (COL) are met, the final 5 to 6 months of the
2 Schedule consists of Fuel Loading plus Startup Testing and Commissioning
3 activities leading to Commercial Operations.
4
5 d) The above schedule activities apply separately to Unit 3 and to Unit 4, and the
6 currently planned schedule lag between the Unit 3 & 4 plant COD’s is 12 months.
7
8 Bulk Commodity Unit Rates
9
10 In October 2017, Bechtel estimated the amounts of construction bulk commodities
11 remaining and started reporting progress in completing construction of these commodities.
12 In June 2018, a schedule baseline was established, referred to hereafter as the June 2018
13 Baseline, and in April 2019, a revised schedule baseline was established, referred to
14 hereafter as the April 2019 Baseline. One of the primary focuses of these baselines was
15 Direct Craft labor construction efforts and the utilization of “planned bulk commodity unit
16 rates” and crew sizes to determine the schedule durations required to complete the various
17 construction activities. The construction activities are then logically linked to the ITP
18 system testing activities, which are then logically linked to the final 11 to 12 months of
19 integrated system test activities leading to fuel load, Startup Testing and Commissioning,
20 and ending with Commercial Operations. The final product of this scheduling effort is the
21 Integrated Project Schedule (“IPS”). Further, the planned Direct Craft construction effort
7
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 8
1 that is integral to the IPS is the basis against which the Direct Craft Construction effort is
2 measured.
3
4 With respect to quantities, there were no significant changes. With respect to the Unit
5 Rates, however, the data presented in Table 1 below raises concerns regarding the decision
6 to use installation rates significantly lower than the experienced rates, and the
7 reasonableness of the resultant durations used and the impacts that this has on
8 Performance Monitoring and Reporting.
9
10 In analyzing the data of Table 1, the installation unit rates experienced (from October
11 2017 through March 2019 and October 2017 through September 2019) are in most cases
12 significantly greater than the Planned Rates assumed in the April 2019 Baseline. The
13 Table below compares the experienced rates prior to the April 2019 Baseline (column 3)
14 to those planned in the April 2019 Baseline (column 4) and then compared to the current
15 actual rates (column 5).
16
8
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 9
1
2 Table 1 Vogtle Unit 3; Planned and Actual Bulk Commodity Installation Rates Actual Rates Planned Rates in Actual Rates Bulk Commodity Unit of Measure October April 2019 October 2017 – Sept 2017 – Schedule 2019 March 2019 Baseline Column 3 Column 4 Column 5 Piping Large Bore Pipe Hours / LF Large Bore Pipe Hours / each Supports Small Bore Pipe Hours /LF Electrical Conduit Hours / LF Cable Trays Hours / LF Cable Tray Hours / each Supports Cable Hours / LF Terminations Hours / each Bases of Above Rates 1. Actual Rates, October 2017 – March 2019: Equals hours spent divided by quantities earned and was derived from numbers in the Bechtel March 2019 Updated Monthly Status Report page 142. 2. Rates Used in April 2019 Schedule Baseline: Planned Hours divided by new baseline quantities and was derived from the Bechtel April 2019 updated monthly status report, page 145. 3. Actual Rates, October 2017 – Sept 2019: Again, equals hours spent divided by quantities earned, and was derived from the Bechtel September 2019 Updated Monthly Status Report pages 200. 4. “LF” denotes “Linear Foot” 3 4 5 Q. BASED ON THIS ANALYSIS, WHAT ARE YOUR CONCLUSIONS?
6
9
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 10
1 A. Since the planned unit rates directly impact planned schedule durations, VMG concludes
2 the following:
3
4 1. The IPS schedule durations to complete the work are not achievable (i.e., durations
5 are much shorter than required).
6
7 2. Since the Cost and Schedule Performance Indices are directly related to the
8 planned, unreasonable unit rates in the IPS, the benchmark performance metrics
9 used in reporting the performance of the critical construction Direct Craft labor
10 efforts are less meaningful.
11
12 3. The recently established April 2019 Baseline does not represent an achievable
13 plan, nor does it provide a meaningful basis for performance monitoring and
14 thereby it does not represent an effective tool for updating forecasts of the Project
15 COD’s and TPC. The Company itself refers to the 2019 Baseline as a strategy and
16 admits that they continue to use it as such even when it may look unachievable or
17 aggressive. (Transcript, Abramovitz, p. 60).
18
19 4. When developing the new April 2019 Baseline in early 2019 SNC should have
20 assumed more realistic unit rates that were better aligned with actual craft
21 production when establishing unit rates for the April 2019 Schedule Baseline.
22
10
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 11
1 Unit 3 Over-all Project Performance Measures
2
3 Q. PLEASE PROVIDE VMG’S ANALYSIS OF UNIT 3 OVER-ALL PROJECT
4 PERFORMANCE MEASURES.
5
6 A. I will provide an explanation of the two major performance measures at this point of the
7 Project. These measures are as follows:
8
9 1) Schedule Performance Index (SPI): For a pre-defined period of time, and at Vogtle,
10 this is expressed as the Planned Hours to be Earned divided by the Earned Hours. The
11 SPI is a measure of schedule adherence and can be used in a variety of ways; e.g., by
12 Unit, by Bulk Commodity, by geographic area of a Unit, etc. From this definition, an
13 SPI greater than 1.0 is unfavorable, and an SPI of less than 1.0 is favorable.
14
15 2) Cost Performance Index (CPI): For a pre-defined period, this is expressed as the
16 Actual Hours Spent divided by the Hours Earned; and, similar to the SPI, a CPI of
17 greater than 1.0 is unfavorable, and a CPI of less than 1.0 is favorable. The CPI is a
18 measure of efficiency of work performed.
19
20 Table 2 provides these performance measures, for Unit 3 as a whole (i.e., includes all
21 construction bulk commodities) vis-a-vis the recently established April 2019 Baseline.
22
11
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 12
1 2 Table 2 Unit 3 Over-all Cost and Schedule Performance vs April 2019 Schedule Baseline Cum to Date Monthly Data Starting with Man- (Since Establishing the April 2019 Schedule Baseline) April 2019 Hours Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Baseline Planned 162,579 292,699 398,494 352,982 368,663 464,276 2,039,693 Earned 179,575 248,165 284,137 220,507 285,959 288,109 1,506,452 Actual 2,299,247 Spent 307,326 308,049 440,636 351,863 421,062 470,311
SPI 0.91 1.18 1.40 1.60 1.29 1.61 1.35 CPI 1.71 1.24 1.55 1.60 1.47 1.63 1.53 1. Except for the April 2019 Planned value, all other data is derived from project reporting (ref: Updated Bechtel Monthly Status Score Card Reports). 2. Since an April Planned Value was not reported, VMG simply derived what it would have to be to reconcile to the above planned numbers. The SPI for April was also not reported, and was then calculated by VMG from the April Planned Hours divided by the April Earned Hours to be 0.91. 3 4 5 Q. WHAT CONCLUSIONS DO YOU DRAW IN ANALYZING THE DATA OF
6 TABLE 2?
7
8 A. VMG concludes actual performance versus the April 2019 Baseline is unfavorable to the
9 point that one could conclude that the April 2019 Baseline itself is not an achievable plan.
10 The cumulative SPI of 1.35 suggests that it takes 1.35 months to earn progress that was
11 planned for one month. Also, the cumulative CPI of 1.53 suggests that it is taking one and
12 a half hours to complete one hour of planned earned work. The Company has stated that
13 they expect another re-baseline in the near future. (Transcript, Haswell, p. 58).
12
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 13
1 Planned and Actual Production Rates for
2 Critical Piping and Electrical Bulk Commodities
3
4 Q. ARE THERE SPECIFIC BULK COMMODITIES THAT ARE MOST CRITICAL
5 TO FINISHING THE PROJECT AS SOON AS POSSIBLE, AND HAVE YOU
6 ANALYZED PRODUCTION RATES FOR THOSE COMMODITIES?
7
8 A. Yes. Electrical bulk commodities are lagging the most and are well behind planned April
9 2019 Baseline production goals. In terms of the Unit 3’s planned hours and actual earned
10 hours, through October 2019, these electrical efforts are 397,633 hours behind plan and on
11 average these same efforts are continuing to fall behind at a rate of 25,000 hours per week.
12 At these rates we conclude that SNC is already 16 weeks (i.e., over 3.5 months) behind
13 schedule. This back-log, when added to already planned future work, is then contributing
14 to what is addressed later as a “future bow wave” of work.
15
16 Q. IN ADDITION TO THE ABOVE ELECTRICAL COMMODITY INSTALLATION
17 DATA, PLEASE PRESENT YOUR ANALYSIS AS IT RELATES TO AN IMPACT
18 ON THE FORECAST OF UNIT 3’S COD?
19
20 A. VMG first looked at what schedule durations would be using the historical production
21 rates (bulk construction work performed since October 2017 through March 2019) and
22 compared them to schedule durations resulting from the productivity rates established in 13
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 14
1 the April 2019 Baseline. From this we derive the ratio of these durations for the
2 commodities analyzed and we call this the “Schedule Duration Factor”. These results are
3 provided in Table 3.1.
4
5 Each schedule duration factor indicates that for every hour of planned activity identified in
6 the April 2019 Baseline for the selected commodity, the actual time to perform that
7 activity (based on experience to date) can be found by taking the planned time and
8 multiplying it by the Schedule Duration Factor.
9 10 Table 3-1 Schedule Duration Factors If Experienced Unit Rates Were Used vs April 2019 Baseline Unit Rates Planned Unit Actual Schedule Rates (per April Historical Duration Factors Selected Unit of 2019 Schedule Unit Rates; i.e., Actual Remarks Commodity Measure Baseline Oct 2017- Historical Rates Mar 2019 Baseline Rates Piping For all the selected Large Bore Pipe Hours/LF commodities (less Large Bore Pipe Large Bore Pipe Hours/each Supports & Supports Conduit), use of Small Bore Pipe Hours /LF experienced based Electrical unit rates would Conduit Hours/LF have required more Cable Trays Hours/LF effort (and increased schedule Cable Tray Hours/each durations) from Supports what was provided Cable Hours/LF in the April 2019 Terminations Hours/each Baseline; see Note below. Note: Using Large Bore Pipe as an example, if an activity in the April 2019 Baseline was planned to require 100 hours to complete, use of the experienced based productivity unit rate would indicate that the activity should have been planned for (vs 100 hours). This explains why the Schedule Performance Indices for Piping and Electrical commodities are so high, and why work in these areas is significantly “lagging the plan”. 11 12 14
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 15
1 The data in the table clearly shows that it is taking SNC considerably more time to install
2 most commodities than SNC has assumed in its April 2019 Baseline.
3
4 From the start of our Independent Monitoring role, we believed the strategic approach
5 used by SNC to expedite the start of testing activities prior to completing civil and more
6 bulk commodity construction would lead to increased craft congestion and schedule
7 conflicts in the field. As such, performance metrics would then become even more
8 unfavorable. For this reason, we took a snapshot of what these same statistics would show
9 for the one week ending September 29, 2019. That data is presented in Table 3.2 below.
10
15
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 16
1
2 Table 3.2 Schedule Durations Impact/ Factor (a) Unit Rate (b) Actual (c) Oct 2017-Mar Recent Week Selected Unit of (per April Rates for 2019; Schedule Ending 9/29 Critical Measure 2019 Week Ending Duration Factor Schedule Commodity Schedule Sept 29, 2019 (ref: Table 3.1) Duration Factor; Baseline i.e., (b) (a) Piping Large Bore Pipe Hours / LF Large Bore Pipe Hours / Supports each Small Bore Pipe Hours / LF Electrical Conduit Hours / LF Cable Trays Hours / LF Cable Tray Hours / Supports each Cable Hours / LF Terminations Hours / each NOTE: 1. Blue color coding indicates that the schedule durations (based on actual experienced unit rates), for each of the two indicated time periods are exceeding those schedule durations assumed within the April Schedule Baseline. For large bore pipe, as an example, if 100 hours were planned for a crew to complete an activity, given the average time to install large bore piping (over the time period Oct 2017 – March 2019) it would have taken the crew to perform the work. Fast forward to the one week ending Sept 29th, the trend worsened (i.e., would have taken , and therefore a proportionately longer period of time to complete). 2. Green color coding represents the areas where performance was in line with respect to the unit rates planned within the April 2019 Baseline. 3 4 5 Q. WHAT DO YOU CONCLUDE FROM THIS ANALYSIS OF THE CRITICAL
6 BULK CONSTRUCTION COMMODITIES?
7
16
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 17
1 A. We conclude that since the establishment of the April 2019 Baseline, the man-hours that it
2 is taking to complete construction of the more critical bulk commodities is much greater
3 than what was planned. From this same data in Table 3.2, a majority of the items show a
4 continued negative trend which we believe will result in significant delays of the Units 3
5 and 4 COD’s beyond the aggressive May 23, 2021/2022 COD’s, and potential delays
6 beyond the November 2021/2022 COD’s.
7
8 Q. BASED ON YOUR SCHEDULE ANALYSIS SO FAR, IS IT NOT TRUE THAT
9 SIMPLY ADDING MORE CRAFT LABOR COULD HELP TO SHORTEN THE
10 SCHEDULE DURATION?
11
12 A. Yes, but only to a point. To illustrate, if adding more craft labor alone would shorten the
13 schedule duration, the Project would do so (Project is presently attempting this approach)
14 and it would not have had to slip the target COD’s for the April 2019 Baseline from what
15 they were in the prior June 2018 Baseline. However, when continuing to simply add labor
16 you get to a point where more craft is unproductive and not conducive to completing work
17 in an efficient and timely manner.
18
19 Q. DO YOU THINK THE NEGATIVE PERFORMANCE TRENDS CAN BE
20 SIGNIFICANTLY IMPROVED?
21
17
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 18
1 A. VMG believes that significant improvements cannot be achieved in the near term to either
2 recover lost schedule, or to even achieve the planned rate of construction work. Reasons
3 supporting this belief are as follows:
4
5 1. It is noted that there is a recent (dated October 5, 2019) “Vogtle Unit 3 and 4 Near
6 Term Electrical Production and Productivity Improvement Plan.” However, this is just
7 one of several plans that have been developed and implemented since VMG has been
8 monitoring the Project, with none to date having achieved significant improvements.
9
10 2. With a near term increase in concurrent construction of bulk commodities and ITP
11 testing activities (ref: next section regarding Construction Turnovers to ITP), there will
12 be more situations where construction cannot proceed due to limited personal access,
13 if for example, a hydro test is being performed. Even without this added complexity,
14 as construction work continues work areas will become more congested. This
15 congestion is a typical occurring trend as construction progresses, it is termed
16 “stacking of trades”. In addition to Bechtel and ITP attempting to plan and execute
17 their work, multiple subcontractors will also be doing the same.
18 3. As is explained in the next section regarding turnovers from Construction to ITP, the
19 turnover dates keep getting slipped into the future. This, with no significant change in
20 the planned aggressive April/ May COD for Unit 3, results in further compressing the
21 over-all schedule. The highly compressed schedule, together with an April 2019
18
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 19
1 Baseline plan that is not considered achievable, then complicates planning and
2 execution of the work which then results in less than optimal planning of the work.
3
4 Further evidence of VMG’s conclusions regarding the increased complexities of work
5 planning and execution is apparent in the following report and example:
6
7 Comments made in the July 22 – August 17, 2019 study of work conducted by
8 Vitale, Inc wherein they note:
9 10 “ 11 12 13 14 ” 15 16 In the “Engineering Deep Dive” presentation on September 27, 2019, a situation
17 was highlighted wherein field routing of conduit supports, conduit, cable, and
18 cable terminations were all completed, and equipment was powered.
19 Subsequently, piping was to go through the area but could no longer be routed as
20 planned, and re-engineering of re-routed piping of supports and piping were
21 required to provide for alternate construction, all of which “impacted Condensate
22 System, Circulating Water System and Potable Water System Scope for near term
23 turn-over.” In VMG’s opinion, proper planning of the field routed electrical work
24 would have included a constructability review and check of the 3-D plant model, 19
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 20
1 in which case the routing of the piping should have been observed and this
2 situation should have been avoidable.
3
4 Unit 3 Construction Turnovers to ITP
5
6 Q. PLEASE DESCRIBE THE CONSTRUCTION TURNOVERS TO ITP AND THE
7 RELEVANCE TO THE COD.
8
9 A. Toward the end of physical construction there are construction tests which must take
10 place. After construction’s performance of certain tests, and after completion of the
11 required engineering and construction documentation, a System or Partial System, is then
12 turned over to ITP. ITP then performs what are in essence “component” and “System
13 Tests”.
14
15 The ability to turnover systems to construction was addressed as an issue in my prior
16 November 2018 testimony. With an inability to achieve these turnovers as planned during
17 the prior June 2018 Baseline, and not wanting to delay the Unit 3 COD, most of these
18 turnovers are now planned to occur over a compressed time period thus making the
19 previously identified problem even more serious. Quantification of the delays, and the
20 continued inability to perform as planned, are provided in Table 4 which follows.
21
20
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 21
1 Q. DESCRIBE THE TURNOVER DATA PROVIDED IN TABLE 4, AND VMG’S
2 ANALYSIS OF THAT DATA.
3
4 A. In Table 4 VMG has identified the partial systems that had been scheduled for turnover in
5 support of the major schedule milestone identified as Integrated Flush, and for each has
6 listed the planned turnover dates per the June 2018 Baseline and per the April 2019
7 Baseline. VMG has also indicated if, and if so when, the actual turnover has occurred.
8 Finally, the data end date for identifying actual turnovers is October 19, 2019.
9
10 As can be seen from the table, planned turnover dates for these nearer term turnovers
11 slipped an average of 153 days from the June 2018 Baseline to the April 2019 Baseline,
12 and the performance to date in meeting the April 2019 Baseline dates has slipped by 47
13 days and continues trending negatively.
14
15 Table 4
Planned T/O Date Per Days Slip Partial System Turnovers In Support June 2018 April 2019 from Days Slip of Integrated Flush Schedule Schedule Prior Actual from April (Data Date Oct 19, 2019) Baseline Baseline Baseline T/O Date 2019 Baseline U3 – PLS-3 System Partial Turnover 1 to Testing 16-Dec-18 27-Jun-19 193 27-Aug-19 61 U3 – PLS-2 System Partial Turnover 2 23-Oct-18 2-Jul-19 to Testing (IF) 252 28-Jun-19 -4 U3 – SFS-1 System Turnover to 3 26-May-19 28-Jul-19 Testing (IF) 63 14-Aug-19 17 4- U3 – RCS-1 System Partial Turnover 7/29/2019; to Testing (IF); plus RCS-1-E (Below) 19-Jun-19 161 Missed A 11/27’19 72 U3 – RNS-1 System Turnover to 5 21-May-19 4-Aug-19 Testing (IF) 75 Missed 76 6- U3 – PXS-1 System Partial Turnover 8/5/2019; 30-May-19 A to Testing (IF) 10/31/19 154 Missed 75 U3 – WLS-1 System Partial Turnover 7 21-Apr-19 20-Aug-19 to Testing (IF) 121 Missed 60 21
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 22
U3 – CVS-1 System Turnover to 8- 8/27/2019; Testing (IF); plus CVS-1 E 30-Jun-19 A 10/28/’19 Containment (below) 120 Missed 53 U3 – SWS-1 System Turnover to 9 7-Jun-19 7-Oct-19 Testing (IF) 122 Missed 12 U3 – IDS-1 System Turnover to 10 18-Jun-19 24-Oct-19 Testing (IF) 129 11; 8- U3 – CVS-1 System Turnover to A later sub-div 28-Oct-19 NA B Testing (IF) Containment Electrical of CVS-1 12; U3 – PXS-1 System Partial Turnover A later sub-div 6- to Testing (IF) Containment Electrical 31-Oct-19 NA of PXS-1 B U3 – CCS-1 System Partial Turnover 13 to Testing (to support SFS, RNS, & 23-May-19 6-Nov-19 167 CVS Testing, (IF) 14- U3 – WRS-1 System Turnover to 11/8/2019; 17-Jun-19 141 A Testing (IF); plus WRS-1-X1 (below) 11/15/19 15; U3 – CAS-1 (SA) System Partial A later sub-div 20- Turnover to Testing (IF) South Aux 13-Nov-19 NA of CAS-1 B 16; U3-WRS-1-X1 (1A) System Turnover Deferred 14- to Testing (Exceptions) Exceptions 15-Nov-19 NA B from WRS-1 U3 – PLS-4 System Partial Turnover 17 16-Apr-19 16-Nov-19 214 to Testing (IF) U3 – ECS-2 System Partial Turnover 18- 11/23/2019; to Testing (IF); plus ECS-2-E (next 3-Jul-19 145 A 11/25/2019 item) 19; U3 – ECS-2 System Partial Turnover A later sub-div 18- to Testing (IF) Containment Electrical 25-Nov-19 NA of ECS-2 B U3 – CAS-1 System Partial Turnover 20- 11/27/2019; to Testing (IF); plus line item 15; 20-B 15-Jul-19 135 A 11/13/19 above 21; U3 – RCS-1-E System Partial 4- Turnover to Testing (IF) Containment A later sub-div 27-Nov-19 NA B Electrical of RCS-1 U3 – PLS-5 System Partial Turnover 22 20-Mar-19 4-Dec-19 to Testing (IF) 259 Average Day Shift of 153-day slip (from June 2018 Schedule Baseline to April 2019 Schedule Baseline); as computed from original 16 Partial 153 Days Systems in June 2018 Schedule Baseline; i.e., planned date slips averaging over 5 months in a period of 10 months Average Days Slip from April 2019 Schedule Baseline to 47; and Actual T/O Date growing 1 2 3 Q. YOU HAVE SHOWN THAT WITH CONTINUAL SLIPS OF UNIT 3 ACTIVITIES
4 THE TIME TO COMPLETE REMAINING ACTIVITIES CONTINUES TO BE
5 COMPRESSED. FOR THIS SAME PHASE OF THE PROJECT WHERE MORE
22
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 23
1 PARTIAL SYSTEMS ARE TO BE TURNED OVER FROM CONSTRUCTION TO
2 ITP, CAN THE SITUATION BE IMPROVED?
3
4 A. VMG does not believe the situation can be improved. As stated previously, the ability to
5 turnover systems from construction to ITP was highlighted as a problem in our prior
6 November 2018 testimony, and as has just been explained the situation has become more
7 serious. Of particular note in this latter regard is that in the very near term the sheer
8 number of turnovers is planned to increase dramatically. In addition, and as is explained
9 later in the section titled “Complexity of Planning & Executing Future Work”, additional
10 work is continually being repackaged and delayed into the future, which then adds to the
11 required number of turnovers. In spite of these added complexities it is also important to
12 highlight what was stated in my previous November 2018 testimony regarding SNC’s
13 strong operating record. As such, SNC is working to assure that proper technical controls
14 are put in place so that in spite of the everchanging methods to plan the work, the finished
15 plants are constructed in a manner which documentation shows is consistent with the
16 design. They should therefore function within the bounds of operations as required by the
17 NRC licensing basis document titled “Final Design Safety Analysis Report”. However,
18 and as is explained later in our schedule analyses, these processes have become very
19 complicated, and we question – from a planning/ project controls perspective -- the ability
20 of SNC to effectively keep up with all the changes that are continuing to be made to the
21 planned work.
22
23
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 24
1 Q. BASED ON WHAT VMG HAS ANALYZED REGARDING THE TURNOVER OF
2 PARTIAL SYSTEMS FROM CONSTRUCTION TO ITP, WHAT IS YOUR
3 SUMMARY CONCLUSION?
4
5 A. VMG concludes that the over-aggressiveness of the April 2019 Baseline is not achievable
6 and there will be continued further slips in the turnover dates from the baseline planned
7 dates.
8
9 Complexity of Planning & Executing Future Bow Wave of Increasing Work
10
11 Q. PLEASE COMMENT ON THE COMPLEXITIES OF PLANNING AND
12 EXECUTING A FUTURE BOW WAVE OF INCREASED WORK.
13
14 A. First, and as has been already briefly mentioned, by “bow wave” of increased work we
15 mean taking work planned for completion at an earlier date and then re-planning/ adding it
16 to already planned future work. The means by which SNC is deferring work and how
17 these procedures further complicates the over-all planning and execution of that work are
18 detailed as follows:
19
20 1. As noted previously, the contractor is not turning over complete systems to ITP, but
21 “Partial Systems” wherein multiple “Partial Systems” then comprise each total system.
24
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 25
1 Within the partial systems there are then multiple work packages that comprise the
2 partial system.
3
4 2. As work for completing partial systems has continued to lag the plan, and as a near
5 term major schedule milestones approach, the Project has employed various means to
6 still meet the nearer term milestone (e.g., “Start of Integrated Flush”). The various
7 means are as follows:
8
9 a) Identify work package “exceptions”2 and defer that work for later completion.
10 Depending on the number and magnitude of the associated work scopes being
11 deferred, these deferred work packages may be planned as single future scopes of
12 work, or several of the deferred work packages may be bundled into an additional
13 partial system (as was done for line item “16; 14-b” identified in the prior Table 4
14 for the Unit 3 WRS (Radioactive Waste System), Partial System (designated as
15 WRS-1). To further illustrate, often times permanent power is not yet available
16 (due to lagging electrical work) to perform an activity such as stroking a valve or
17 starting a motor, so the “exception process” then defers the permanent power and
18 adds “temporary power” to allow testing of the component. These deferred work
19 packages are bundled into a newly created further sub-division of the original
20 Partial System, and the newly created partial system carries an “E” designator
2 An “exception” represents a Construction Work Package (or a collection of Construction Work Packages) that was originally planned for completion by a specified date in the current (now April 2019) baseline, but a decision was subsequently made to not complete that work by the specified date (but by a later date). 25
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 26
1 (where “E” denotes electrical). As can be seen by this example, this complicates
2 both current planning and execution of work, and also does the same for the work
3 that is being deferred. As a further example of how it complicates the work, with
4 permanent power to a motor, protection of that motor and associated power is
5 provided through a Motor Control Center (“MCC”), so engineering approval of the
6 means of providing the temporary power is required, plus this all creates additional
7 work that had not been originally planned.
8 b) Use of the Partial Release for Test (“PRT”) procedure, wherein the following
9 actions take place:
10 Jurisdictional Control of a portion of the Partial System is temporarily turned
11 over to ITP; this means that control of this portion of the system (e.g., in terms
12 of equipment “lock outs and tag outs”)3 is turned over to ITP and they can then
13 perform a limited test. Again, this process complicates the planning and
14 execution not only of current work, but also future work.
15 This process also results in two additional “hand-offs” of Jurisdictional Control
16 (i.e., with a PRT there is a hand-off to ITP, and then back again to
17 Construction) thus adding to the complexity of properly controlling work
18 package management.
19
3 This process is absolutely necessary and must be properly controlled in order to protect both personnel and equipment. 26
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 27
1 Q. REGARDING THE EXCEPTION PROCESS, HAVE YOU ATTEMPTED TO
2 CAPTURE THE EXTENT TO WHICH ORIGINALLY PLANNED WORK IS
3 BEING DEFERRED?
4
5 A. Yes, and this is shown in Table 5 which illustrates the above points for only a portion of
6 those systems that the April 2019 Baseline had planned for turnover through October
7 2019.
8 Table 5 Table 5: Unit 3 “Creation of Bow Wave” of Work Deferred into the Future (Data as of Oct 2019) Example: Partial Systems which (per the Apr 2019 Baseline) Already Were, or Are, Planned for Turnover to ITP Prior to October 31, 2019 Partial System & Associated Number of Original Work Major Schedule Milestone Packages (WP’s) Number of WP Exceptions Integrated Flush RCS-1 PXS-1 WLS-1 CVS-1 SWS-1 IDS-1 CVS-1E PXS-1E 1 For the Last two items (shown in italics), each was included in their associated original Partial System within the June 2018 2 Schedule Baseline, but were subsequently further sub-divided out as separate Partial Systems in the April 2019 Schedule Baseline. 3 Also, as the forecast T/O dates near, the exceptions most likely will increase. 9 10 As an example of what can be seen from the above table, Partial System PXS-1 originally 11 was comprised of Work Packages, subsequently a decision was made to package 12 of these Work Packages into a separate PXS-1E Partial System which was then given a 13 later planned date for completion, and of the remaining Work Packages (i.e., –
27
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 28
1 ) there are an additional that have been ‘Excepted’ and re-planned for a later 2 completion date. 3 4 Q. WHAT ARE VMG’S CONCLUSIONS REGARDING THIS PART OF YOUR
5 SCHEDULE ANALYSES?
6
7 A. Our conclusions are as follows:
8
9 1. In an attempt to meet a major milestone (such as the “Start of Integrated Flush”),
10 extreme efforts are being taken to both (a) defer originally planned work (through
11 “Exceptions”) and to (b) authorize limited testing (through the “Partial Release for
12 Test” process, which in some cases can serve to defer originally planned tests) – which
13 then results in a large degree of variance from the April 2019 Schedule Baseline.4
14
15 2. In light of the above practices, VMG concludes that it has become very difficult to
16 keep up with a timely and effective updating of the Schedule Baseline.
17
18 3. As such, it is virtually impossible to accurately analyze variances and it is therefore
19 difficult to predict what the actual COD’s will be.
20
4 There is nothing improper about deferring work that is not necessary to meet a major milestone. The point, however, is that the baseline plan is not being met, and more appropriate measures of progress going forward will be whether Integrated Flush is completed on time, and the extent to which the deferred work can be effectively integrated with the already planned future work. 28
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 29
1 Q. HAVE YOU ANALYZED THE SCHEDULE BEYOND THE UNIT 3 ITP TO AND
2 THE UNIT 4 SCHEDULE?
3
4 A. For the Unit 3 schedule, we have not done a detailed analysis beyond the Unit 3
5 Construction and Construction turnover to ITP (i.e., have not analyzed in detail the
6 subsequent activities leading to the Unit 3 Fuel Load and COD). We have, however, done
7 a limited review of both the Unit 3 Schedule beyond Construction turnover to ITP, and
8 also the Unit 4 Schedule, and for purposes of this analysis have accepted the durations
9 shown in those schedules. At this time, the general rationale for not delving into the
10 schedules in greater detail and for now accepting those schedule durations is as follows.
11
12 1. VMG finds the Unit 3 Schedule to be overly aggressive, and that the Unit 4 Schedule
13 (in terms of durations by phase) to be roughly equal to the Unit 3 Schedule. Further,
14 whatever improvements are possible for Unit 4 based on Unit 3 lessons learned are
15 assumed to be offset by the overly aggressive current schedule. In addition to the
16 over-aggressiveness of the Unit 3 Construction and ITP phases, the one-year duration
17 between Units (when compared to the roughly two-year average duration at the more
18 recent dual unit sites across the nation) is also believed to be aggressive (note: Units 1
19 and 2 at Vogtle were 2 years apart as well).
20
21 2. SNC decreased the duration from Hot Functional Test (“HFT”) to COD from what
22 was a 12-month duration to 11 months. The current Nuclear Regulatory Commission
29
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 30
1 licensing process (although not yet proven) is supposed to be improved over the past
2 process, and for this reason this may be achievable. In further support of this, we have
3 reviewed the status of NRC related activities which include inspections of on-going
4 activities, SNC submittal of License Amendment Requests, and of the NRC related
5 “Inspections, Analyses, and Acceptance Criteria (ITAAC)” notifications from SNC to
6 the NRC and their status and find no deficiencies of note.
7
8 3. In summary, and for purposes of this schedule analysis, we have assumed that the
9 overall Project Schedule will be impacted directly by whatever we conclude regarding
10 the Unit 3 Schedule; i.e., if the analysis shows the Unit 3 Scheduled COD to be
11 delayed by x months beyond the commission approved COD, then Unit 4 would be
12 delayed by that same amount.
13
14 SUMMARY SCHEDULE ANALYSIS
15
16 Q: PLEASE PROVIDE A SUMMARY INDICATOR THAT SUPPORTS VMG’s
17 CONCLUSION THAT ACHIEVING THE UNIT 3 NOVEMBER 2021 COD IS AT
18 SIGNIFICANT RISK.
19
20 A: VMG’s analysis thus far has focused primarily on describing how Unit 3 actual schedule
21 performance has significantly lagged both the June 2018 baseline and the April 2019
22 baseline. The analysis has also focused on the many near-term challenges that SNC will
30
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 31
1 continue to face which will limit significant improvements to performance. Our high-
2 level summary analysis starts by first assuming that nearly all of the Construction effort
3 must be completed by the “Mechanical Completion” date (which is the same date for the
4 Major Schedule Milestone “Start Hot Functional Testing” and is mid-June 2020). In
5 Table 6, we show the SPI during the period of the June 2018 Schedule Baseline (i.e., July
6 2018 through March 2019), the SPI during the period of the current April Schedule
7 Baseline (i.e., April 2019 through September 2019), and the combined SPI measuring
8 actual schedule performance vs the actual plans for each of these periods. This combined
9 SPI is roughly 1.4, which means that for every month (say 30 days) of planned work, the
10 amount of work not completed is equivalent to 12 days of work.
11 TABLE 6 12 Man-Hours Baseline Period Planned Earned Period SPI June 2018 July 2018 - March 2019 3,268,543 2,280,543 1.43 April 2019 April 2019 - Sept 2019 2,039,693 1,506,452 1.35 13 Combined July 2018 - Sept 2019 5,308,236 3,786,995 1.40 14
15 VMG then reviewed the time frame from the start of the July 2018 Schedule Baseline to
16 mid-June 2020 and computed that to be 23.5 months. If we then apply the SPI of 1.4 to
17 this 23.5-months duration of Construction work, this results in extending the date for the
18 start of Hot Functional Testing by nearly 10 months (i.e., 0.4 x 23.5). Finally, with no
19 changes in the subsequent schedule, the COD for Unit 3 would be delayed by roughly 9.5
20 months (from the nearly equal aggressive April/ May 2021 COD’s of the June 2018 and
21 April 2019 Baselines, to the February/ March timeframe of 2022). 31
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 32
1 2 Q: CAN YOU ADD TO YOUR ANALYSIS TO PROVIDE A BASIS FOR THE UNIT 4
3 NOVEMBER 2022 COD ALSO BEING AT SIGNIFICANT RISK?
4
5 A: That is difficult to assess at this point. VMG’s opinion, however, is that even with the
6 Lessons Learned in planning and executing the Unit 3 work it is questionable that the
7 assumed 1-year duration between the Unit COD’s can be maintained or decreased. For
8 example, the average duration between COD’s at US dual unit nuclear plant sites has been
9 roughly 2 years (as was the case for Vogtle 1 and 2). Further, one would think that in light
10 of the Unit 3 issues, the Unit 4 plan would not simply be a time slipped near replicate of
11 the unachievable Unit 3 plan but would attempt to first plan for completion of more of the
12 bulk construction effort prior to the start of testing.
13
14 Q: SO, TO BE CLEAR, VMG’S OPINION – IN LIGHT OF THE DETAILED UNIT 3
15 SCHEDULE ANALYSIS AND ABOVE COMMENTS REGARDING THE UNIT 4
16 SCHEDULE -- IS THAT BOTH THE NOVEMBER 2021 AND NOVEMBER 2022
17 COD’S ARE AT SIGNIFICANT RISK.
18
19 A: Yes, that is correct.
20
32
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 33
1
2 Cost Analysis and Conclusions
3
4 Q. VMG’S ANALYSIS OF THE PROJECT TOTAL PROJECT COST AND WHAT
5 VMG MIGHT ESTIMATE THE TPC TO BE AT PROJECT COMPLETION.
6
7 A. VMG sees the main challenges to meeting the TPC of $ 17.1 billion5 are both unfavorable
8 Production Efficiencies and the Schedule delay. With regard to unfavorable production
9 efficiencies, we have a measure of that with the craft labor CPI’s, and with respect to
10 Schedule VMG will include the cost impacts of schedule delays later within this
11 discussion.
12
13 Q. PLEASE DESCRIBE YOUR ANALYSES OF UNFAVORABLE PRODUCTION
14 EFFICIENCIES.
15
16 A. What we have done in the first part of our cost analysis is to focus on potential cost
17 impacts due to the currently unfavorable production efficiencies and at what cost – unless
18 significant improvements are made – the final TPC may be. This analysis uses the April
19 2019 Baseline as a benchmark, which forecasts COD’s of May 23, 2021/ 2022. This first
20 part of our analysis, therefore, excludes consideration of the Schedule Contingency for a
5 GPC share is $7.3 billion 33
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 34
1 delay of the COD’s beyond these dates, but schedule delay is then considered after this
2 first part of the analysis within VMG’s further analyses.
3 Table 7 identifies major Cost Categories which when summed total the TPC of $ 17.1
4 billion. Also, all of the “Project” identified cost numbers for the “to go” period starting in
5 July 2018 and ending with the Unit 4 COD of November 2022 were taken directly from
6 the SNC Project Management Board meeting slides dated October 30, 2019.
7 8 Table 7
9 10 11 Not visible from Table 7 is the major components of Construction Cost, which are
12 identified in The Bechtel August Monthly Report (Section 6) as “Craft” (which consists of
13 Direct Labor) and Field Non-Manuals (which consists of Craft Management and other
14 Bechtel support staff). Both of these components vary directly with the CPI. Further, the
15 Bechtel budgeted costs for these numbers reflect a CPI of 1.0. Our detailed analysis, 34
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 35
1 therefore, simply takes the “Project Current EAC” costs from Table 7 and adjusts them by
2 adding the adjustments that VMG calculated for the various CPI’s (reference Table 8 for
3 computation of adjustments as calculated from the Bechtel data). To illustrate, for a CPI
4 of 1.25, adding $ to the Project Current EAC of $ yields $
5 . In addition to analyzing at a CPI of 1.25, VMG also analyzed (and repeated this
6 same process) for CPI’s of 1.35 and 1.50.
7
8 Table 8 Cost Categories within Bechtel Adjustment to the Table 7 August Monthly Report & Base $ ($ millions) millions6 to Adjust “Project Current EAC’s” for CPI’s of ___
Cost Category Base5 $ M's 1.0 1.25 1.35 1.5 Craft 0 Field Non-Manuals 0 Total Amount of Adjustments 0 9
10 Q: IS THERE ANYTHING ELSE YOU WOULD LIKE TO ADDRESS PRIOR TO
11 MOVING ON TO VMG’S CONSIDERATION OF SCHEDULE DELAY
12 RELATED COSTS?
13 A. Yes, in our analysis thus far we have accounted for Construction Risks by considering
14 CPI’s based more on Project experience and how it would be difficult to achieve
15 significant improvements to that experience. Further, the costs of Table 7 assume the
16 aggressive May 23, 2021/ 2022 COD’s are met. Also, by considering CPI’s as we have,
17 we have accounted – to a large degree – for continuing construction risks. As noted in
6 Due to Bechtel’s “To Go” budget covering a longer period of time than the “Project To Go Budget”, this factor was necessary to align the Bechtel Cost Budget with the Project’s Cost Budget. 35
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 36
1 Table 7, however, we have not accounted for any changes to the other cost categories, and
2 for that reason have included an assumed additional 10% contingency for those cost
3 categories across all CPIs. That contingency value is an additional $ for all CPI’s.7
4 This then results in a VMG line item (corresponding to the Project “Total Site Working
5 Plan”; reference line 6 of Table 7) of $ (CPI of 1.25), $ (CPI of 1.35), and
6 $ (CPI of 1.5). As one final note, to arrive at a TPC, the prior costs (prior to July
7 2018) of $7,880M need to be included in all scenarios. To summarize, please refer to
8 Table 9. Also, note that no schedule contingency is included in the analysis thus far in
9 that this analysis assumes meeting the aggressive target May 23, 2021/ 2022 COD’s.
10 Table 9 VMG Cost Analysis; Summary Cost Table ($ M's) While Meeting May 23, 2021/ 2022 COD's To Go Costs; $ M's (July 1, 2018 - Completion) CPI Cost Category $ M's 1.25 1.35 1.5 Remarks "Project's" Current EAC (for Construction) VMG Construction Adjustments Equals "Project's Current EAC VMG Adjusted (for Construction) plus VMG Construction Cost Adjustments All Other To Go Costs VMG Contingency Equals sum of Italicized Text $ M's and corresponds to Project’s VMG Total "To Go" “Total Site Working Plan” line Costs item 6 of Table 7. + Prior Costs Add to obtain "TPC" ="s VMG TPC Range Equals sum of Bolded Text $ M's 11
7 For each of the CPI scenarios of Table 7, VMG Contingency was calculated at 10% of (Subcontractors + All Other Cost), and for each of the three CPI scenarios it equals $ . 36
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 37
1 2 Q. WITH RESPECT TO VMG’s ASSUMED COST CONTINGENCY OF 10% ON
3 ALL BUT THE CONSTRUCTION COSTS, ARE THERE SPECIFIC ITEMS
4 THAT YOU HAVE IDENTIFIED REGARDING WHAT THESE MAY BE, AND
5 WHY YOU HAVE THEN ASSUMED 10% OF THESE COSTS?
6
7 A. Yes, there are specific issues, with primary among them being Subcontracts, and the
8 Deferred “Bow Wave” of work.
9
10 With respect to Subcontracts, these include both Bechtel Managed and SNC Managed.
11 For Bechtel Managed, 10 of 27 already have CPI’s greater than 1.0 and Bechtel reporting
12 shows an additional $ for Subcontracts. For SNC Managed Subcontracts, SNC is
13 reporting a higher than budget EAC. Also, as the normally experienced “stacking of
14 craft” issue starts to manifest itself during the latter stages of construction, this, in
15 conjunction with the concurrent construction and testing efforts, will only exacerbate the
16 efficiency of the many subcontractors’ simultaneous efforts.
17
18 With respect to the Deferred “Bow Wave” of Work, the additional engineering and
19 administrative support efforts to break out systems into subsystems, identify and defer
20 “excepted work”, to package and control “partial releases for test”, and the efforts to re-
21 plan and then execute all of these activities, all have the potential to increase the EAC
22 above what has been budgeted.
37
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 38
1 Q. PLEASE PROVIDE AN INTEGRATED ANALYSIS OF THE COMBINED
2 IMPACTS OF BOTH PRODUCTION INEFFICIENCIES AND SCHEDULE
3 DELAYS?
4
5 A. First recall that our Cost Analysis thus far is based on looking at the baseline plan for
6 meeting the aggressive May 23, 2021/ 2022 COD’s and therefore includes no “Schedule
7 Contingency” (which is consistent with the IPS of the Project’s April 2019 Baseline).
8
9 Based on this approach, VMG then assumed the SNC provided schedule delay cost of
10 $100M/ month in developing an integrated analysis of the combined effects of production
11 inefficiencies and schedule delays. An integrated summary analysis of the potential
12 impact of both of these factors on the project TPC is provided in Table 10.
13 Table 10 14 Overall Project Cost Summary VMG Analysis of TPC’s ($ M’s) For Various CPI’s and COD’s CPI’s COD’s 1.25 1.35 1.50 Remarks May 23, Represents current April 2019 Schedule 2021/ 2022 $16,951 $17,222 $17,630 Baseline aggressive May 23, 2021/ 2022 COD’s Nov 2021/ $17,491 $17,762 $18,170 Represents Commission Approved 2022 COD’s and is derived by adding the “Project” estimated $540M Schedule Contingency into the above values. NOTE: If one were to assume that the “Project” estimated $100 M/ month schedule delay costs are accurate, to obtain costs beyond the November 2022/ 2023 dates one would simply add $100M per month to each of the three costs represented by each of the CPI’s. VMG believes, however, that this estimate of $100M per month warrants further review, especially as the project proceeds beyond Unit 3 Mechanical Completion. 38
Public Disclosure Direct Testimony of Don Grace Docket No. 29849, Twentieth and Twenty-First Semi-Annual Vogtle Construction Monitoring Period Page 39
1 2 Q. IS IT CORRECT TO ASSUME, THAT BASED ON YOUR ANALYSIS, EVEN IF
3 THE COMMISSION APPROVED NOV 2021/ 2022 COD’S WERE MET, IT IS
4 POSSIBLE THAT THE $17.1B TPC WILL BE EXCEEDED?
5
6 A. That is correct, primarily due to the challenge of achieving their overall CPI goals, which
7 VMG understands to be 1.25 for Unit 3, and 1.20 for Unit 4.
8
9 Q. IT IS ALSO CORRECT TO ASSUME THAT IF THE $17.1B IS NOT TO BE
10 EXCEEDED, AND IF THE OVERALL PROJECT CPI WERE 1.25, THE
11 PROJECT MAY NEED TO FINISH EARLIER THAN THE NOV 2021/ 2022
12 COD’S?
13
14 A. Yes; based on our current analysis as depicted in the above table, with the COD’s having
15 to occur roughly three months prior to the Nov 2021/ 2022 dates (i.e., to save roughly
16 $300M in schedule related costs, thus reducing the $17,491M figure to less than
17 $17,100M).
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19 Q. MR. GRACE, DOES THIS CONCLUDE YOUR TESTIMONY?
20 A. Yes, it does
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Exhibit A Resume of Don Grace Page 1
Education and Certifications
Master of Business Administration, Project Management Harvard Graduate School of Business (Awarded Fellowship to Attend)
Bachelor of Science in Marine Engineering and Mathematics United States Naval Academy (Graduated Cum Laude)
US Naval Polaris Missile Officer School, US Naval Submarine School, US Naval Nuclear Power School, and US Naval Scuba Diver School
Professional Engineer (Pennsylvania), Power Generation
Career Highlights
Fifty years of hands on technical, management and executive experience with all phases of the Plant Life Cycle (design, licensing, construction, start-up and testing, commissioning, operations and decommissioning). Also, highly experienced in performing economic analyses of projects, facilities, and processes.
Development of New Facilities – Seventeen years of experience with a major U.S. Architectural Engineering firm, Burns and Roe Enterprises (BREI), in the positions of Project Engineering Manager, Project Manager, Executive Consultant, and President of a company formed by BREI, AREVA and Duratek. Nearly all of these experiences entailed First of a Kind (FOAK) projects which involved new Nuclear Power Plant Projects and FOAK Chemical Process Projects.
• Directing Major Project, Independent Reviews - As an employee of BREI, contracted by the Department of Energy (DOE) to assemble project review teams which I then directed to provide independent project management reviews of multi-billion-dollar DOE projects. Nearly all of the projects were FOAK, and the reviews were total scope reviews (i.e., reviewed ability to achieve technical objectives, within the forecast costs and schedules). Subsequently, and as an independent consultant, was contracted by DOE to work as the technical lead working as part of DOE teams that reviewed and certified DOE contractors Earned Value Management Systems. Reviews per the 32 criteria of ANSI Standard 748.
Upgrades to Operational Facilities – Seventeen years of experience with General Public Utilities (GPU) in designing, constructing new or modified systems, testing, training plant 1
Exhibit A Resume of Don Grace Page 2
operators and turning systems over to plant operations. Also, worked with the Nuclear Regulatory Commission (NRC) and state environmental agencies in support of the nuclear and fossil plant licensing and permitting activities.
• Economic and Costing Studies: Performed many such studies, examples of which include developing a return of investment model for the DOE Waste Management Office, computing asset value for an existing operating power plant, computing component costs of power plants generating electricity, computing component costs of fabricating nuclear fuel (did this for Westinghouse).
• Skilled Communicator: Highly experienced in analyzing and presenting complex technical and economic issues to executive levels of various government agencies (e.g., US Nuclear Regulatory Commission, US Department of Energy, Thai Government, International Atomic Energy Agency, and Public Utility Commissions), and responding to questions in articulate and professional manner.
Prior and Current Project Experiences (A Partial Listing)
BREI, GPU, and Independent Executive Consultant project experiences have included:
• President of a company created from merging personnel from BREI, Duratek (a nuclear waste management company), and AREVA (a fabricator of nuclear fuel), and contracted to the DOE to design, construct, and operate facilities for disposing of depleted uranium hexafluoride (a by- product of the uranium enrichment process). Project entailed utilizing a patented, FOAK chemical process for taking uranium hexafluoride (UF6) gas, and converting it to Uranium Oxide (UOx) with usable Hydrofluoric Acid (HF) as a by-product. Two full scale facilities were designed, have been constructed, and are functioning at the Paducah, KY and Portsmouth, OH uranium enrichment facilities.
• Director of a Nuclear Power Feasibility Study conducted for the nationalized electric utility of Thailand (EGAT) and the Thai government. Study entailed evaluation of commercially available Nuclear Power Plant alternatives, estimates of their capital costs, operating costs, and forecasts of their bus bar costs (in terms of Levelized Cost of Electricity); plant licensing/construction/start-up schedules all leading to licensed
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Exhibit A Resume of Don Grace Page 3
plant operations; evaluation of nuclear safety issues and risks; and approach to educating and training of personnel. Study entailed evaluation of various commercially available nuclear plant types (i.e., a Boiling Water Reactor, as proposed by Japan/ Hitachi; and four separate types of Pressurized Water Reactors, as proposed by (1) Toshiba/ Westinghouse, (2) Japan/ Mitsubishi, (3) France/ AREVA, and (4) Korea/ KEPCO. Also involved economic studies of alternative electrical energy sources.
• Executive Consultant / Director of DOE Project Independent Reviews: The DOE, in pursuit of improved management practices, established an office independent of those managing major DOE projects (i.e., established the Office of Engineering and Construction Management). They then contracted with BREI and others to perform full scope (i.e., technical, cost and schedule) reviews of its projects. All major projects (i.e., larger dollar values) were assigned to BREI, and I assembled the required personnel expertise and directed all of these reviews. Example projects (most of which are FOAK) that were reviewed include the following:
Yucca Mountain Project: This is the highly political project of the first facility to permanently store High Level Wastes (from both DOE facilities, and mostly Spent Nuclear Fuel from operating nuclear plants). Included in this effort was the first project Life Cycle Cost Estimate.
The National Ignition Facility at Lawrence Livermore Laboratory: This project consists of 192 high energy pulse laser beams, all fired at the same time at a target the size of a bee- bee. Its purpose is to do research regarding fusion reactions in support of predicting the performance of fusion weapons as they age. The facility is now operational, but actual costs greatly exceeded the budget and schedule, and it is still not functioning at the desired level.
The Mixed Oxide Fuel Facility (MOX Facility) at the Savannah River Site. This project is based on a French technology and its purpose is to take plutonium from excess nuclear weapons and combine plutonium oxide with uranium oxide to make fuel for commercial nuclear reactors.
The Neutrino Project at Argonne National Laboratory: This project consists of an accelerator located at Argonne (in the Chicago area) shooting neutrinos through the earth’s
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Exhibit A Resume of Don Grace Page 4
crust to a target located in a mine shaft in Minnesota, to study the properties of neutrinos.
Numerous Site Cleanup Projects: During the cold war many of the materials for nuclear weapons were developed via reactors and other facilities, and with the primary criteria being schedule, environmental controls (although somewhat effective) were not nearly as strict as they are today. As a result, there are numerous “legacy wastes” in need of treatment and / or disposal. Cleanup projects reviewed include: (a) Fernald, (b) Rocky Flats, (c) Mound, (d) Oak Ridge, (e) Brookhaven National Laboratory, (f) the Nevada Test Site, (g) Pantex, (h) the Savannah River site, (i) the Hanford Site, and (j) Idaho National Laboratory.
• Director for the Oyster Creek Nuclear Power Plant Safety and Reliability Upgrade Program: Valued at over one billion dollars (in current year dollars). Work over a roughly 10-year period included nearly 100 separate projects which were largely the result of Three Mile Island Lessons Learned, NRC Appendix R (fire protection related requirements), required upgrades to the Torus (i.e., part of the containment), and plant reliability projects. Efforts resulted in keeping oldest publicly financed U.S. Nuclear Power Plant operational (had – until September 2018 -- been operating since December 1969).
• Project Engineering Manager for the Modular High Temperature Gas Cooled Reactor First-of-a-Kind Project. Contracted to the DOE, the objectives of this FOAK project were to produce tritium in support of U.S. Department of Defense missions, and to demonstrate a new commercial reactor technology.
• Project Operations Manager for the Accelerator Production of Tritium Project: This was another DOE contracted FOAK project whose mission was also to produce tritium in support of DOD missions. Project was valued at three billion dollars.
• Served as the first utility elected Chairman of the Boiling Water Reactor Owners’ Group (BWROG), and in working with GE, other nuclear industry groups, and the BWR owners developed generic design upgrades to address NRC identified safety issues.
• Served as on-site manager during completion of construction and demonstration testing of a FOAK proof of concept chemical process for disposing of chemical weapons.
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Exhibit A Resume of Don Grace Page 5
• Worked as a team with Cost Plus Consulting, a certified Appraiser, and legal-council, to develop Fitzpatrick Nuclear Station asset values. Working through legal-council, the ultimate client consisted of local municipality taxing authorities, with their objective being to receive favorable and fair taxing of the facilities within their jurisdiction.
• Early in my career, I worked in the GPU Plant Licensing Group, and worked with legal-council, state and federal environmental groups, the Nuclear Regulatory Commission and nuclear and fossil plant personnel to develop, implement and maintain acceptable liquid discharge permits (i.e., National Pollution Discharge Elimination System; NPDES permits) and air emissions permits.
• Also early in my career I worked within the Comptroller’s Office and performed economic analysis of the various elements of a power plants costs (i.e, Fixed, Variable, Fuel, and Recovery of Capital Costs). This was done for fossil and nuclear plants. Also, worked with coal fired plant personnel to develop and implement Corrective Maintenance and Preventative Maintenance Programs.
US Navy, Nuclear Plant Operations Experience: Five years as a submarine naval officer in the U.S. Nuclear Navy as a nuclear trained and qualified Engineering Officer of the Watch (equivalent to a commercially licensed Nuclear Plant Senior Reactor Operator). Also served as Weapons Officer responsible for operational readiness of Polaris-missile and torpedo weapons systems.
Positions Held
• US Navy: Served as a naval officer aboard submarines for 5 years following graduation from the US Naval Academy. Positions included engineering department head, weapons officer, and stood watches as Officer of Watch and Engineering Officer of the Watch. Retired from service as a Lieutenant, Sr. Grade (O-3).
• General Public Utilities: In 17 years held positions of increasing responsibility, several of which are summarized below (and for which the roles and responsibilities are also described):
• Lead Licensing Engineer: Responsible for licensing and permitting activities for a pressurized water reactor nuclear plant and several coal fired plants.
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Exhibit A Resume of Don Grace Page 6
• Senior Analyst, working for the Comptroller: Analyzed the component costs of the company’s generating plants. Also, did efficiency studies of how plant outages were conducted, and working with fossil plant personnel developed and implemented corrective maintenance and preventative maintenance program.
• Project Engineering Manager: Responsible primarily for Electrical and Instrumentation & Controls Upgrades to a Boiling Water Reactor (BWR) Nuclear Plant.
• Director, Engineering Projects: Responsible for all major projects (both capital, and O&M) for a BWR Nuclear Plant. Also, responsible for developing, prioritizing, and managing the over-all capital budget.
• Burns & Roe Enterprises, Inc (BREI): In 17 years with BREI positions of increasing responsibility, several of which are summarized below.
BREI Site Manager (working at Aberdeen Proving Grounds, for proof of concept testing of a new method of treating/ disposing of Chemical Weapons).
Project Engineering Manager (for the Modular High Temperature Gas Cooled Reactor (MHTGR) Project).
BREI Site Manager (working with Booz Allen Hamilton, in support of the DOE Office of Waste Management, in Germantown, Md.)
Project Operations Manager (for the Accelerator Production of Tritium Project).
Project Manager and Executive Consultant (for the Independent Project Management Reviews of Major DOE Projects)
Director, Thailand Nuclear Feasibility Study
President & Project Manager, Uranium Disposition Services, Inc.
• Management Consulting Services: For the past 14 years have had my own consulting company, and have served in various capacities either on my own (Grace Management Consulting Services, LLC) or as part of other consulting companies, on many assignments, some of which are summarized below:
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Exhibit A Resume of Don Grace Page 7
• Worked in support of a General Electric (GE) proposal to the DOE: The effort resulted in the award of a contract to the GE team to pursue fuel reprocessing studies in support of the Global Nuclear Energy Partnership initiative of the U.S. Government.
• Worked under contract to NuScale in support of their development of a “Small Modular Reactor” proposal to the DOE: The effort resulted in NuScale’s initial receipt of a contract award to further pursue the effort.
• Working under contract to the DOE, functioned as part of a team of personnel reviewing and certifying major DOE contractors Earned Value Management Systems against the criteria of ANSI Std 748
• Worked with Cost Plus Consulting (CPC, LLC) in support of providing a bottoms-up estimate of what it would cost today to build the Fitzpatrick Nuclear Plant. Also, developed a report of that same cost, based on the forecast cost and schedules of other US Nuclear Plants under construction. This was in support of local tax jurisdictions efforts to improve the asset valuation for purposes of securing increased tax revenues.
• More recently, as an independent consultant with Critical Technologies Consulting (CTC, LLC), have independently reviewed power plant projects and operations for clients as discussed below.
• Mississippi Public Utility Staff: In support of the CTC role as independent monitor for the Kemper Integrated Combined Cycle (IGCC) project, performed monthly reviews of the project, provided monthly updates of the project status, and provided written and oral expert witness testimony to the Mississippi Public Service Commission in support of rate proceedings.
• Arizona Corporate Commission: Working again with CTC, led and developed a review of the technical, cost and schedule performance of the Four Corners Selective Catalytic Reduction Project, and then provided written and oral testimony in support of rate proceedings to reflect the project being in-service.
• Georgia Public Service Commission (GPSC) Staff: Currently working as a member of a CTC team contracted by the GPSC Staff to serve as the Independent Monitor for the on-going Vogtle Units 3 & 4 Nuclear Project. In this role, perform periodic reviews of performance and both written and oral testimony as an expert witness during the semi-annual reviews of the project by the Georgia Public Service Commission.
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