PUBLIC DISCLOSUREmediad.publicbroadcasting.net/p/wabe/files/Jacobs_Testimony_9&10_VCM-PD.pdf10 STF-SR/WRJ-1 Resume of Steven D. Roetger 11 STF-SR/WRJ-2 Resume of William R. Jacobs,

BEFORE THE

GEORGIA PUBLIC SERVICE COMMISSION

IN THE MATTER OF GEORGIA POWER COMPANY’S

NINTH / TENTH SEMI-ANNUALVOGTLE

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

June 20, 2014

PUBLIC DISCLOSURE

Direct Testimony of Steven D. Roetger and William R. Jacobs, Jr., Ph.D.

Docket No. 29849, Ninth / Tenth Semi-Annual Vogtle Construction Monitoring Period

1

1

Table of Contents 2

I. INTRODUCTION ................................................................................................... 2 3

II. STATUS OF PROJECT .......................................................................................... 7 4

III. SCHEDULE ANALYSIS AND CHALLENGES ................................................. 12 5

IV. RECOMMENDATIONS ....................................................................................... 28 6

7

Exhibits: 8

9

STF-SR/WRJ-1 Resume of Steven D. Roetger 10

STF-SR/WRJ-2 Resume of William R. Jacobs, Jr., Ph.D. 11

12

PUBLIC DISCLOSURE



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I. INTRODUCTION 1

Q. PLEASE STATE YOUR NAMES, TITLES AND BUSINESS ADDRESSES. 2

A. My name is Steven D. Roetger. I am an analyst for the Georgia Public Service 3

Commission. My business address is 244 Washington Street, S.W., Atlanta, 4

Georgia, 30334. My name is William R. Jacobs, Jr., Ph.D. I am an 5

executive consultant with GDS Associates, Inc. My business address is 1850 6

Parkway Place, Suite 800, Marietta, Georgia, 30067. 7

8

Q. MR. ROETGER, PLEASE SUMMARIZE YOUR EDUCATIONAL 9

BACKGROUND AND EXPERIENCE. 10

A. I hold a Bachelor of Business Administration degree from Georgia State 11

University. I have been employed by the Georgia Public Service Commission 12

since September of 2008, primarily in the capacity as a team member for the 13

Vogtle Unit 3 and 4 Project under Docket No. 29849. Also, I was a Public 14

Interest Advocacy Staff team member for the Vogtle certification, Docket No. 15

27800, and an Advisory team member for various other proceedings. Prior to 16

joining the Georgia Public Service Commission I held various positions in either 17

an accounting or finance capacity for firms in different industries. My resume is 18

included in Exhibit SR/WRJ-1. 19

20

Q. DR. JACOBS, PLEASE SUMMARIZE YOUR EDUCATIONAL 21

BACKGROUND AND EXPERIENCE. 22

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A. I received a Bachelor of Mechanical Engineering in 1968, a Master of Science in 1

Nuclear Engineering in 1969 and a Ph.D. in Nuclear Engineering in 1971, all 2

from the Georgia Institute of Technology. I am a registered Professional 3

Engineer and a member of the American Nuclear Society. I have more than thirty 4

years of experience in the electric power industry including more than twelve 5

years of nuclear power plant construction and start-up experience. I have 6

participated in the construction and start-up of seven nuclear power plants in this 7

country and overseas in management positions including start-up manager and 8

site manager. As a loaned employee to the Institute of Nuclear Power Operations 9

(“INPO”), I participated in the Construction Project Evaluation Program, 10

performed operating plant evaluations and assisted in development of the Outage 11

Management Evaluation Program. Since joining GDS Associates, Inc. in 1986, I 12

have participated in rate case and litigation support activities related to power 13

plant construction, operation and decommissioning. I have evaluated nuclear 14

power plant outages at numerous nuclear plants throughout the United States. I 15

served on the management committee during construction of Plum Point Unit 1, a 16

650 Megawatts Electric (“MWe”) coal fired power plant. As a member of the 17

management committee, I assisted in providing oversight of the Engineering, 18

Procurement and Construction (“EPC”) contractor for this Project. I have assisted 19

the Georgia Public Service Commission as the Independent Construction Monitor 20

in providing oversight of the Vogtle 3 and 4 Project since August 2009. My 21

resume is included in Exhibit STF-SR/WRJ-2. 22

23

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4

Q. WHOM ARE YOU REPRESENTING IN THIS PROCEEDING? 1

A. We are representing the Georgia Public Service Commission (“Commission”) 2

Public Interest Advocacy Staff (“Staff”). 3

4

Q. MR. ROETGER, WHAT IS YOUR INVOLVEMENT WITH THE 5

VOGTLE 3 AND 4 PROJECT? 6

A. Since Docket No. 27800, I have been directly involved in the oversight of the 7

Vogtle Unit 3 and 4 Project (“Project”) as part of the Staff team. I have closely 8

monitored the Project with Dr. Jacobs since its inception. I also testified in the 9

Eighth Semi-Annual Vogtle Construction Monitoring (“VCM”) proceeding. 10

11

Q. DR. JACOBS, WHAT IS YOUR INVOLVEMENT WITH THE VOGTLE 3 12

AND 4 PROJECT? 13

A. I am the Commission’s Independent Construction Monitor (“CM”) for the 14

Project. As such, my duties are to assist the Staff in providing regulatory 15

oversight of all aspects of the Project and to keep the Commission informed of 16

significant Project issues or changes in the projected cost and schedule as they 17

occur. I have presented testimony in the First, Second, Third, Fourth, Fifth, Sixth, 18

Seventh, and Eighth Semi-Annual VCM proceedings describing the construction 19

monitoring activities, the status of the Project and any concerns or significant 20

issues that I identified. 21

22

Q. WHAT IS YOUR ASSIGNMENT IN THIS PROCEEDING? 23

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Our assignment is to present the results of the Staff’s and CM’s Project oversight 1

from certification of the Project to the present with emphasis on the time period 2

covered by the Ninth / Tenth Semi-Annual VCM Report, January 1, 2013 through 3

December 31, 2013. We will describe the current status of the Project and will 4

update the Commission on issues that have the potential to impact the schedule or 5

cost of the Project that have been discussed in prior testimony in this docket and 6

identify any new issues that have arisen since the Eighth Semi-Annual VCM 7

proceeding. Finally, we will make a recommendation regarding the $389 million 8

of costs submitted by Georgia Power Company (“Company”) for verification and 9

approval and will address other requests made by the Company in its filing. 10

11

Q. PLEASE DESCRIBE THE CONSTRUCTION MONITORING PROGRAM 12

THAT THE STAFF AND INDEPENDENT CONSTRUCTION MONITOR 13

HAVE IMPLEMENTED TO MONITOR THE CONSTRUCTION OF THE 14

VOGTLE 3 AND 4 PROJECT. 15

A. The Staff and the CM continue to be very active in monitoring the Project. These 16

activities include monthly meetings with Staff and Company personnel to discuss 17

Project status, regular trips to the Vogtle Project site to observe the monthly EPC 18

meeting and to witness firsthand construction activities and progress. The CM 19

has observed readiness review meetings in which Company and Consortium 20

personnel review the Consortium’s plan for key activities. In addition, the CM 21

team has continued its review of the Company’s process for handling Project 22

invoices from Westinghouse and Chicago Bridge & Iron (“CB&I”). This includes 23

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review of the Project cost control procedures and sampling of processed invoices. 1

Other activities conducted by the Vogtle Construction Monitoring team include: 2

Review of Weekly Metrics reports issued by the Company; 3

Review of Monthly Project status reports issued by the Company; 4

Review of Monthly EPC status reports; 5

Review of the Company’s Semi-Annual VCM Reports; 6

Preparation of discovery requests for additional information as needed 7

following review of the monthly status reports, semi-annual 8

construction monitoring reports or meetings with the Company; 9

Participation in Nuclear Regulatory Commission (“NRC”) public 10

meetings; 11

Review of public correspondence between the Company and the NRC 12

via the NRC website; 13

Review of correspondence between the Consortium and the Company; 14

Review of trade articles and journals related to new nuclear power 15

plant development. 16

Witnessing significant construction activities including: 17

o Units 3 and 4 First Nuclear Concrete; 18

o Units 3 and 4 Setting of Containment Vessel Bottom Heads; 19

o Unit 3 Setting of CA04 20

21

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II. STATUS OF PROJECT 1

2

Q. PLEASE DESCRIBE THE PROJECT SCHEDULE AND COST 3

PRESENTED BY THE COMPANY IN ITS NINTH / TENTH VOGTLE 4

CONSTRUCTION MONITORING REPORT. 5

A. In its 9th/10th

Vogtle Construction Monitoring Report, the Company states that 6

the forecasted Commercial Operation Dates (“COD”) for Unit 3 and Unit 4 of 7

December 2017 and December 2018 are unchanged from the 8th VCM report and 8

remain 21 months beyond the CODs at certification. The total construction and 9

capital cost forecast remains unchanged from the $4.799 billion reported in the 10

8th VCM report. Forecasted financing costs have declined by $91 million 11

resulting in a forecasted Total Project Cost of $6.759 billion, which is $650 12

million more than the certified cost. 13

14

Q. WHAT IS THE STATUS OF THE INTEGRATED PROJECT SCHEDULE 15

(“IPS”)? 16

A. Prior to May 2014, Staff and the CM had been concerned that the IPS used by the 17

Company and the Consortium to manage the Project lacked detail in several 18

critical areas such as the completion of engineering, fabrication and assembly of 19

the CA01 module and, fabrication and assembly of the Shield Building. In early 20

May 2014, the Consortium issued the April 2014 IPS that contained these missing 21

elements. This schedule was called a “locked down” schedule meaning that going 22

forward Project progress would be measured against this schedule. However, this 23

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IPS only presents detailed Project activities through December 2015. Beyond 1

2015, the Consortium has recognized that significant mitigation efforts potentially 2

including, but not limited to, opening up numerous work fronts and double 3

shifting of craft labor, will be required to maintain the current CODs. These 4

mitigation plans were not developed as of the issuance of the “locked down” 5

schedule and as a result many critical post 2015 activities were not updated in the 6

April 2014 IPS. The April 2014 IPS will be discussed in more detail in the 7

Schedule Analysis section of our testimony. 8

9

Q. WHAT IS THE CURRENT STATUS OF THE PROJECT BUDGET? 10

A. As reported in the Company’s 9th/10th

VCM report, as of December 31, 2013 the 11

Total Project Cost (the Company’s share) of $3,144 million was $57 million 12

under the February 2014 re-forecast1 budget-to-date amount of $3,201 million 13

with Total Construction and Capital Cost being $54 million under budget and 14

Total Construction Schedule Finance Cost being $3 million under budget. As 15

described in our testimony in the 8th

VCM period, these budget variances are 16

primarily due to timing differences between actual expenditures and the budget 17

and should not impact Total Project Cost. More plainly, the Project is under 18

budget because the Consortium has not completed the milestones necessary to 19

receive milestone payments as anticipated in the Company’s current budget. 20

Thus, the Consortium has been paid less at this time than projected by the 21

1 The Company re-forecasts its budget twice per year; once in February and again in August.

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Company’s current budget because they have not accomplished work according to 1

scheduled milestones. 2

3

Q. WHAT FUTURE RISKS COULD RESULT IN ADDITIONAL COST TO 4

THE PROJECT? 5

A. Among the future risks that could result in additional cost to the Project are: 6

additional schedule delay beyond the current forecasted delayed CODs; the 7

outcome of the current litigation between the Owners and the EPC Consortium; 8

the resolution of current change orders submitted by the Consortium; and, the 9

submittal of potential additional change orders by the Consortium. The costs 10

resulting from additional schedule delay include increased capital cost, financing 11

cost, and replacement fuel cost. The quantification of additional capital, 12

financing, and replacement fuel costs and their impact on ratepayers are addressed 13

in detail in Staff Witness Hayet’s testimony. 14

15

Q. HAS THE COMPANY ALSO IDENTIFIED THE ABOVE AS TANGIBLE 16

RISKS TO THE PROJECT? 17

A. Yes. In the Company’s 2013 Annual Report under footnote 3 Contingencies and 18

Regulatory Matters the Company states: 19

As construction continues, the risk remains that additional challenges in the 20

fabrication, assembly, delivery, and installation of structural modules, delays in 21

the receipt of the remaining permits necessary for the operation of Plant Vogtle 22

Units 3 and 4, or other issues could arise and may further impact project 23

schedule and cost. Additional claims by the Contractor or the Company (on 24

behalf of the Owners) are also likely to arise throughout construction. These 25

claims may be resolved through formal and informal dispute resolution 26

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procedures under the Vogtle 3 and 4 Agreement, but also may be resolved 1

through litigation. 2

3

The ultimate outcome of these matters cannot be determined at this time. 4

5

Q. PLEASE DESCRIBE THE CONSTRUCTION PROGRESS THAT HAS 6

BEEN MADE IN THE NUCLEAR ISLANDS DURING THE NINTH / 7

TENTH VCM PERIOD. 8

A. Significant construction progress has been accomplished in the Unit 3 and Unit 4 9

nuclear islands during 2013, the 9th/10th

VCM period. Accomplishments in the 10

nuclear islands include: 11

Placement of Unit 3 First Nuclear Concrete; 12

Setting the Unit 3 CR10 module (the cradle that holds the Containment 13

Vessel Bottom Head); 14

Setting the Unit 3 Containment Vessel Bottom Head (CVBH); 15

Setting the Unit 3 CA04 module; 16

Receipt of the first Unit 3 Shield Building panels; 17

Completion of the Unit 3 Containment Vessel second and third course 18

rings; 19

Completion of Unit 4 CVBH; 20

Placement of Unit 4 First Nuclear Concrete. 21

22

Q. PLEASE DESCRIBE CONSTRUCTION ACCOMPLISHMENTS IN THE 23

UNIT 3 AND UNIT 4 NUCLEAR ISLANDS IN 2014. 24

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11

Although not in the 9th/10th

VCM period, progress has continued in the Project 1

nuclear islands in 2014. This progress includes: 2

Setting Unit 3 CA20 module, the Auxiliary Building; 3

Setting the Unit 4 CR10 module; 4

Setting the Unit 4 CVBH. 5

Overall progress on Unit 4 has been generally on time relative to the IPS assumed 6

by the Company in the 8th

VCM and without NRC findings, which indicates the 7

Project is taking advantage of lessons learned from Unit 3 design and construction 8

activities. Staff believes the ability of the Project to internalize and adopt lessons 9

learned could be a key positive for the Project going forward. 10

11

Q. PLEASE DESCRIBE THE ACCOMPLISHMENTS IN THE BALANCE OF 12

PLANT (NON-NUCLEAR) AREA. 13

A. Significant accomplishments have been made in the Balance of Plant areas which 14

have generally been completed on schedule. During the 9th/10th

VCM period 15

these include erection of Unit 3 turbine building structural steel, setting of Unit 3 16

condensers A and C and continuing to make good progress on the construction of 17

Unit 3 cooling tower. Also, work is progressing well with the raw water intake 18

structure and ancillary office and warehouse buildings. 19

20

Q. WHAT MAJOR COMPONENTS HAVE BEEN RECEIVED AT THE 21

VOGTLE PROJECT SITE DURING THIS PERIOD? 22

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A. Several large components were received at the Vogtle site during the 9th/10th

1

VCM period. These include the Unit 3 A&B Accumulator Tanks, the Unit 3 2

A&B Core Makeup Tanks, the Unit 3 Reactor Vessel and the Unit 3 Turbine 3

Generator. In addition, in 2014 the Unit 4 Reactor Vessel and Unit 4 Turbine 4

Generator were received at the site. 5

6

III. SCHEDULE ANALYSIS AND CHALLENGES 7

8

1. EVOLUTION OF THE PROJECT SCHEDULE BEGINNING IN 9

JANUARY OF 2013 THROUGH J UNE 20, 2014 10

Q. WAS STAFF PROVIDED A FULL IPS THROUGH THE COD DATES OF 11

THE UNITS BY THE COMPANY AT THE BEGINNING OF 2013? 12

A. No. From December 2012 through April 2013 neither the Staff nor the CM 13

received an IPS from the Company. It was the Staff’s and CM’s understanding 14

that during this period the Consortium only provided six month look-ahead 15

schedules to the Company. The Consortium did, however, have a paper Level 1 16

IPS on site available for the Company to review. The Level 1 IPS is the most 17

detailed schedule available and it shows all of the thousands of individual 18

activities that are required to be complete for the Project. 19

20

Q. WHEN DID THE STAFF AND THE CM FIRST RECEIVE AN IPS IN 21

2013? 22

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A. Staff and the CM received a Level 2 IPS in June 2013 with a data date as of May 1

24, 2013. A Level 2 IPS takes the detailed Level 1 IPS and logically groups those 2

thousands of activities along, for example, structures, systems, processes, and 3

components. 4

5

Q. IS IT THE STAFF’S AND CM’S UNDERSTANDING THAT THE LEVEL 6

2 IPS RECEIVED IN JUNE 2013 WAS THE SAME IPS THAT THE 7

COMPANY USED TO DETERMINE THAT THE PROJECT WAS UP TO 8

21 MONTHS DELAYED AS IT REPORTED IN THE EIGHTH VCM? 9

A. Yes. 10

11

Q. IN EARLY 2014 DID THE CONSORTIUM BEGIN AN EFFORT TO ADD 12

THE REMAINING ENGINEERING ACTIVITIES TO THE IPS? 13

A. Yes. After the release of the IPS dated January 24, 2014 the Consortium began an 14

effort to incorporate more accurate data for critical activities of engineering 15

completion. Additional details in critical Project areas including CA01 sub-16

module fabrication, delivery, and assembly; remaining structural modules 17

fabrication, delivery, and assembly; shield building panel fabrication, delivery, 18

and assembly; and Annex Building early start to support initial energization were 19

incorporated in this schedule. 20

21

Q. PLEASE DESCRIBE THE ENGINEERING COMPLETION ACTIVITIES. 22

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A. In early 2014, the Project concluded that the IPS did not contain a sufficient level 1

of detail related to the completion of engineering activities. The Consortium 2

began a substantial effort to add the needed engineering detail to the IPS. The 3

Consortium committed to providing the complete Engineering Completion 4

Schedule to the Company by March 31, 2014. However, this effort is taking 5

longer than expected. 6

7

Q. WHEN DID THE CONSORTIUM COMPLETE THIS EFFORT AND 8

WHEN DID STAFF AND THE CM RECEIVE ITS FIRST REVISED 9

COPY IPS? 10

A. This effort is not complete. The Consortium did however present an April 2014 11

IPS that it termed ‘locked down’ through December 2015. Staff and the CM 12

received a copy of this Level 2 IPS in May 2014. 13

14

Q. WHAT INFORMATION MUST BE INCLUDED IN ORDER TO 15

COMPLETE THE APRIL 2014 IPS? 16

A. The mitigation of the balance of activities forecasted to begin in January of 2016 17

through the completion of the Project. 18

19

Q. DOES THE APRIL 2014 IPS SHOW ANY ACTIVITIES BEYOND 20

DECEMBER 31, 2015? 21

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A. With the exception of inter-connection transmission work, which is the 1

responsibility of the Company, the April 2014 IPS shows no activities beyond 2

December 31, 2015. 3

4

Q. DID THE COMPANY PROVIDE A REASON WHY THE CONSORTIUM 5

DID NOT PROVIDE A SCHEDULE THAT INCLUDED ACTIVITIES 6

THROUGH THE CODs? 7

A. Yes. The Company stated that when the activities described above were 8

incorporated into the IPS it was apparent that significant schedule mitigation2 was 9

necessary to hold the COD dates and that the Consortium was developing 10

mitigation plans prior to making a full schedule available. As of April 2014, the 11

Consortium stated the remaining work on the schedule should be complete within 12

3-5 months. 13

14

Q. WHY IS THE COMPLETION OF ENGINEERING IMPORTANT AND 15

WHAT ISSUES WERE IDENTIFIED FROM DEVELOPMENT OF THE 16

APRIL 2014 IPS? 17

A. The engineering completion schedule identified that hundreds of activities were 18

pushed out past the construction need date due to late engineering which delayed 19

necessary procurement. This in turn pushed out the start and end dates of some 20

construction activities. The Consortium worked to mitigate these schedule 21

impacts during the engineering and procurement phases. However, mitigation of 22

2 Mitigation refers to efforts deployed to compress activity durations.

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some activities will be required in the construction phase. Since not all of the 1

impacts of late engineering identified during development of the engineering 2

completion schedule have been mitigated, additional potential impacts to the 3

Project IPS exist at this time. 4

5

Q. YOU STATE ABOVE THAT THE COMPANY AND THE CONSORTIUM 6

CONSIDER THE APRIL 2014 IPS TO BE ‘LOCKED DOWN’. WHAT IS 7

STAFF’S UNDERSTANDING OF THIS TERM? 8

A. Staff’s understanding of the term ‘locked down’ is that this is the schedule to 9

which the Consortium agrees to be measured against. Variances between current 10

forecast completion dates and the dates in the April 2014 IPS will be provided and 11

used to measure schedule adherence. 12

13

Q. DOES THE EPC AGREEMENT CONTAIN ANY PROTECTIONS FOR 14

RATEPAYERS SHOULD THIS ‘LOCKED DOWN’ SCHEDULE NOT BE 15

MET? 16

A. It is our understanding that, other than the liquidated damages protections in the 17

EPC Agreement, there are no additional protections for ratepayers should the 18

CODs shown in this IPS not be met. 19

20

Q. DO THE COD DATES IN THE APRIL 2014 IPS COINCIDE WITH THE 21

GUARANTEED SUBSTANTIAL COMPLETION DATES (“GSCD”) THE 22

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CONSORTIUM BELIEVES IT IS ENTITLED TO UNDER THE EPC 1

AGREEMENT? 2

A. No. As of the April 2014 Consortium Monthly Project Report, the Consortium 3

continues to present two distinct Project Schedules. The Accelerated Schedule3 is 4

presented only for Unit 3 and shows a COD of January 6, 2018. This schedule is 5

based on the original certification schedule duration of 54 months from First 6

Nuclear Concrete (“FNC”) plus an additional three months. The Consortium’s 7

Fully Impacted Schedule for Unit 3 is shown with a COD of XXXXX and a 8

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX 9

XXXXXXXXXXXX 10

11

Q. WHAT ARE THE STAFF’S AND THE CM’S PRIMARY CONCERNS 12

WITH THE APRIL 2014 IPS? 13

A. First, it was not issued as complete. At this time Staff and the CM have no 14

indication as to the extent of mitigation needed after 2015 to maintain the CODs 15

of late 2017 and late 2018. Second, the schedule portion that was submitted 16

already contains mitigation of some of those activities up to December 2015. 17

With mitigation strategies unknown and untested it is difficult for the Staff and 18

the CM to assess the reasonableness of the CODs. The inclusion of mitigation for 19

near term critical path activities also increases the risk that should any of these 20

mitigations not be realized, the Consortium would be forced to further mitigate 21

3 Includes mitigation strategies for Shield Building design changes, COL delay, and FNC delay i.e. those

issues currently being litigated.

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longer term activities which appears to be already problematic given the IPS was 1

not released with post 2015 information. As will be discussed below, the current 2

forecast for Nuclear Island civil construction activities to reach elevation 3

100’/103’ has already slipped xxx days from the Company’s revised schedule in 4

the 8th

VCM that incorporated a 21 month delay. 5

6

2. ANALYSIS OF UNIT 3 NUCLEAR ISLAND ACTIVITIES FROM 7

JANUARY 2013 TO EARLY 2015 8

Q. YOU STATE ABOVE THAT SIGNIFICANT WORK HAS BEEN 9

ACHIEVED IN THE UNIT 3 NUCLEAR ISLAND, CORRECT? 10

A. Yes. However, for the most part that work has been delayed relative to the 11

forecasted dates shown in the IPS that the Company used to develop its forecasted 12

CODs in the 8th

VCM. 13

14

Q. HAVE THE ACTUAL ACTIVITY DELAYS AND FORECASTED 15

ACTIVITY DELAYS INCREASED OVER TIME? 16

A. Yes. Please refer to the table below. This table compares some of the activity 17

forecast dates from the first Level 2 schedule Staff received in 2013 with the latest 18

Weekly Metrics forecast dates for the same activities. The third column shows 19

the variance in days. A positive number indicates schedule delay. 20

21

22

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1

Q. PLEASE EXPLAIN THE PRIMARY REASONS FOR THESE 2

ACTIVITIES BEING DELAYED. 3

A. As the CM and Staff have reported in previous VCMs, the primary reasons for 4

these delays are as follows: 5

Late design changes to ensure that the design conforms to the licensing 6

basis and meets all technical and code requirements; 7

Late delivery and poor quality of sub-modules that required significant re-8

work at the 'Lake Charles Facility - Vogtle', or Level D storage; 9

Ineffective Quality Assurance Programs, with particular emphasis on the 10

Corrective Action Program, at the Consortium vendors. 11

12

Q. WHAT IS THE SIGNIFICANCE OF REACHING ELEVATION 13

100’/103’6” IN THE NUCLEAR ISLAND (“NI”)? 14

Unit 3 Nuclear Island Path to Elevation 100'/103'

Milestone Activity

Level 2 Schedule Dated 5/24/2013*

May 30, 2014 Weekly Metrics Days Delayed

A XXXXXXXXXXXXXXXXXXXXXX 8/6/2013 12/4/2013(A) 120

B XXXXXXXXXXXXXXXXXXXXXX 9/4/2013 3/8/2014(A) 185

C XXXXXXXXXXXXXXXXXXXXXX 12/3/2013 7/21/2014 230

D XXXXXXXXXXXXXXXXXXXXXX 2/24/2014 12/3/2014 282

E XXXXXXXXXXXXXXXXXXXXXX 2/25/2014 1/8/2015 317

**5/24/2013 IPS shows these activities combined with an end date @ elevations 100'/103'; (A) = Actual date set; *IPS in the 8th VCM.

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A. Construction of the Shield Building is on the Project critical path at this time. 1

Shield Building construction cannot begin until concrete placement in the nuclear 2

island reaches these elevations. 3

4

Q. WHAT IS THE KEY TAKE-AWAY FROM THIS TABLE? 5

A. The table demonstrates that not only have activity durations been expanded but 6

that the rate of expansion has increased over time. For example, the ‘XX 7

XXXXXXXXXXXXXXXXXXXXXXXXXX actually occurred 120 days later 8

than what was forecast in the IPS used by the Company in the 8th

VCM filing; the 9

XXXXXXXXXXXXXXXXXXXXXXXXXXX is forecast to set 317 days later 10

than what was forecast in the IPS used by the Company in its 8th

VCM filing. 11

12

Q. THE DATA DATES BETWEEN THE TWO IPS SCHEDULES SHOWN IN 13

THE TABLE ABOVE ARE APPROXIMATELY ONE YEAR APART. 14

WAS THE EXPANSION OF THE ACTIVITY DURATIONS SUDDEN OR 15

WAS IT A PATTERN OVER TIME? 16

A. It was a pattern over time. If one were to compare an activity duration completion 17

over a few months it would not have shown a significant change. It is the 18

cumulative effect of the minor delays in each of the 12 months represented in the 19

Table that causes, for example, the last line item to be forecast 317 days late. 20

21

Q. DOES THE FACT THAT THE CONSORTIUM MUST CONTINUALLY 22

RE-FORECAST NEAR TERM ACTIVITY DURATIONS REFLECT ON 23

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THE CONSORTIUM’S ABILITY TO FORECAST PROJECT 1

ACTIVITIES IN A TIMELY MANNER? 2

A. Absolutely. It shows Staff and the CM that the Consortium has difficulty 3

forecasting completion of activities in the short (1-6 months) term and also in the 4

intermediate and long term. 5

6

Q. FOR ANY OF THE ACTIVITIES SHOWN IN THE TABLE ABOVE, DID 7

THE CONSORTIUM, OR WILL THE CONSORTIUM, INITIATE 8

MITIGATION STRATEGIES? 9

A. For the first two activities the Consortium did deploy mitigation strategies. We 10

believe these strategies had some positive effect. However, the effect was 11

insufficient to recover the entirety of the delay to set each module. For the last 12

three activities, it is Staff’s and the CM’s understanding that the Consortium is 13

currently deploying mitigation strategies. However, as experience has shown, it is 14

far from certain that mitigation will be successful or even partially successful. 15

16

Q. IS THERE ADDITIONAL EVIDENCE THAT THE CONSORTIUM HAS 17

DIFFICULTY FORECASTING NEAR TERM ACTIVITIES WITHIN 18

FORECASTED DURATIONS? 19

A. Yes. Please refer to the table below. This table shows the history of the 20

Operations Control Center ("OCC") re-forecasting completion dates for very short 21

term activities. As one can see from the table, Milestone Activities A, B, and C 22

were each re-forecast by the OCC numerous times. Milestone Activity C was 23

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forecast to be complete from 6/18 in the Weekly Metrics (“WM”) dated 4/4/2014 1

to 'To Be Determined' (“TBD”) in the Weekly Metrics dated 5/30/2014. So 2

within 49 days of forecasting the OCC has gone from a completion date of 6/18 to 3

a forecast of To Be Determined. 4

5

Milestone Activity

WM 5/30 OCC

WM 5/23 OCC

WM 5/16 OCC

WM 5/09 OCC

WM 5/02 OCC

WM 4/28 OCC

WM 4/21 OCC

WM 4/11 OCC

WM 4/04 OCC

WM 3/28 OCC

A Xxxxxxxxxxxxxxxxxxxxx xxxxx 5/30* 5/28 5/24 5/18 5/18 5/13 5/13 5/5 5/5 5/5

B XXXXXXXXXXXXXXXXXX XXXX 6/13 6/13 6/13 6/9 6/9 5/16 5/16 5/16 5/16 4/29

C Xxxxxxxxxxxxxxxxxxxxxx XXXX TBD 7/7 7/7 6/27 6/27 6/18 6/18 6/18 6/18 N/A

*= Activity Complete WM=Weekly Metrics

6

Q. WHAT IS THE SIGNIFICANCE OF THE OCC NOT HAVING THE 7

ABILITY TO ACCURATELY FORECAST COMPLETION OF NEAR 8

TERM CONSTRUCTION ACTIVITIES? 9

A. It is Staff's understanding that the purpose of the OCC is to consolidate all 10

functional areas necessary for completion of construction activities to one location 11

such that these activities can be managed to completion according to forecast 12

dates. It is a state of the art control and monitoring facility intended to ultimately 13

drive schedule adherence by ensuring design, quality, procurement, and execution 14

risks have been resolved in a timely manner so that construction can proceed 15

when intended. The facility is staffed with representatives from all disciplines of 16

the Consortium organization as well as representation from the Company. 17

18

PUBLIC DISCLOSURE



23

Q. IN STAFF'S OPINION HAS THE OCC BEEN SUCCESSFUL IN 1

MEETING ITS PRIMARY PURPOSE? 2

A. Although it has definitely improved the visibility of activities across all functional 3

areas, the OCC's actual performance has been sporadic to meet forecast activity 4

completion dates. 5

6

Q. HOW HAS THE CONSORTIUM BEEN ABLE TO MAINTAIN THE CODs 7

WITH THE RECOGNITION OF CURRENT FORECAST DELAYS? 8

A. The Consortium has maintained the current CODs primarily by compressing the 9

duration of onsite Shield Building erection. 10

11

Q. DO STAFF AND THE CM HAVE RESERVATIONS ABOUT THE 12

CONSORTIUM’S ASSUMPTION THAT IT CAN ERECT THE SHIELD 13

BUILDING ONSITE IN A SHORTER TIME PERIOD THAN INITIALLY 14

FORECAST? 15

A. Yes, the Staff and CM have concerns for several reasons. First, the Shield 16

Building is truly a first of a kind (“FOAK”) design, fabricate, and assemble 17

activity. This type of structure has never been built in the world. Second, the 18

Shield Building is an integral component of the defense in depth4 required by 19

NRC of any nuclear unit. The Shield Building must therefore be constructed to 20

tight tolerances uncommon to other types of civil construction. Third, to date 21

4Defense in depth refers to redundant safety trains that reduce the risk of a release of radiation to an

acceptable level in the event of a loss of coolant accident.

PUBLIC DISCLOSURE



24

many Unit 3 nuclear island activities have not been completed as scheduled. 1

Therefore, to assume that the duration for site erection of the Shield Building can 2

be significantly compressed appears to be unsupportable and speculative given the 3

Consortium’s history of delays in fabrication and assembly of sub-modules to full 4

modules, and the Shield Building’s first of a kind design. 5

6

Q. HAS THE COMPANY AGREED WITH THE CONSORTIUM'S 7

ASSERTION IT CAN COMPRESS THE ERECTION OF THE SHIELD 8

BUILDING? 9

A. According to the Company's filing, the CODs are maintained and therefore the 10

Company appears to agree that the Shield Building construction can be 11

compressed. 12

13

Q. WHAT IS THE SCHEDULE RISK POSED BY THE DIGITIAL 14

INSTRUMENTATION AND CONTROL (“I&C”) DESIGN OF THE 15

AP1000? 16

A. No nuclear plant operating in the United States today uses a fully digital control 17

system. Design of the AP1000 digital control system is also a First of a Kind 18

activity. As with any first of a kind activity there is a significant risk that design, 19

installation and testing of the digital control systems will take longer than 20

anticipated and will impact the Project schedule. The current schedule to develop 21

the digital control design, that supports the Plant Reference Simulator needed to 22

train and license plant operators, has no float remaining. In addition, there is little 23

PUBLIC DISCLOSURE



25

experience with digital control systems for nuclear power plants within the 1

Consortium, the Company or the NRC. 2

3

Q. ARE THERE OTHER SCHEDULE RISKS FACING THE PROJECT AT 4

THIS TIME? 5

A. Yes there are. These risks include: 6

Technical difficulties with development of key pieces of equipment in the 7

AP1000 design including the canned rotor reactor coolant pumps and the squib 8

valves. 9

The ability of the Company and the Consortium to complete and submit to the 10

NRC the required 875 ITAACs (per unit) needed to receive the 103(g) letter from 11

the NRC. The 103(g) letter certifies that all ITAAC have been successfully 12

completed is required prior to fuel load. 13

The likelihood that startup testing and resolution of problems identified during 14

startup testing will take longer than presently planned. 15

16

Q. WHAT IS YOUR OVERALL ASSESSMENT OF THE PROJECT 17

SCHEDULE AT THIS TIME? 18

A. The Company and the Consortium face many challenges to meet the current 19

CODs of late 2017 for Unit 3 and late 2018 for Unit 4. The Company and 20

Consortium agree that additional mitigation is required to meet these dates. 21

However, this additional mitigation has not been identified and will be developed 22

PUBLIC DISCLOSURE



26

over the next 3 to 5 months. As stated above, the Project's April 2014 IPS 1

maintains the current CODs by reducing the duration to construct the Shield 2

Building, a first of a kind structure never before constructed. Activities related to 3

the nuclear island have taken longer than initially planned, not shorter. In 4

addition to construction of the Shield Building in a shorter duration than planned, 5

the Company and the Consortium face other challenges as described above. To 6

meet the April 2014 IPS CODs, additional mitigation will need to be identified 7

and successfully implemented by the Company and the Consortium. To put it 8

succinctly, the Company and the Consortium must execute the balance of work 9

containing many mitigation efforts to maintain the April 2014 IPS CODs. 10

11

Q. WHAT FORMS OF SCHEDULE MITIGATION IS STAFF AWARE OF 12

THAT WILL BE USED BY THE COMPANY AND THE CONSORTIUM 13

AND WHAT RISKS COME WITH EACH? 14

A. Schedule mitigation typically involves working additional man hours in a given 15

period with longer and/or additional shifts for a given activity. For example, a 16

night shift could be added to a critical path activity to shorten the duration of that 17

activity. Another form of schedule mitigation is adding more work fronts for a 18

given activity. In this case, additional vendors could be contracted to provide 19

critical components if the initial vendor is not able to meet the Project needs. In 20

addition, some work can be performed at risk under a Preliminary Amendment 21

Request (“PAR”) before final NRC regulatory approval is received for a License 22

Amendment Request. These forms of schedule mitigation all come with risks. 23

PUBLIC DISCLOSURE



27

Adding additional labor and/or shifts to an activity will not reduce the duration for 1

that activity if the required design and material available to support the work is 2

unavailable. In addition, a larger workforce does not often equate to a linear 3

increase in production. Or put another way, a doubling of the labor does not 4

mean there will be a doubling of the output. For example the labor force may 5

become more inefficient due to congestion in work areas or inexperience of newly 6

hired laborers with the required standards of nuclear construction. Opening more 7

work fronts by adding new vendors exposes the Project to risks that the new 8

vendors might not have the robust quality and work processes required for nuclear 9

construction work. Finally, performing construction at risk could be counter-10

productive if the at risk construction does not ultimately meet regulatory 11

requirements and must be removed. 12

13

Q WITH REGARD TO OPENING UP WORK FRONTS WHICH ENTITY IS 14

RESPONSIBLE FOR THE FINAL QUALITY OF THAT WORK? 15

A. As the licensee, Southern Nuclear Company5 ("SNC") is ultimately responsible 16

for all work quality that is safety related and placed in the Units regardless of who 17

performs that work or who is responsible under the EPC Agreement. Appendix B 18

to 10 CFR 52 I Organization states "The applicant shall [emphasis added] be 19

responsible for the establishment and execution of the quality assurance program. 20

The applicant [emphasis added] may delegate to others, such as contractors, 21

agents, or consultants, the work of establishing and executing the quality 22

5 SNC operates Southern Company’s fleet of nuclear units.

PUBLIC DISCLOSURE



28

assurance program, or any part thereof, but shall [emphasis added] retain 1

responsibility for the quality assurance program." In this context the 'applicant' is 2

SNC. 3

4

Q. WHAT IS STAFF'S AND THE CM’S EXPECTATION WITH REGARD 5

TO SNC'S OBLIGATIONS UNDER APPENDIX B? 6

A The Staff and CM expect SNC to perform its due diligence and oversight in the 7

selection and review of any new Consortium vendor that is engaged to fabricate, 8

assemble, and/or construct safety related systems, structures, and components. 9

10

Q. WHY IS THE COMPANY’S AND THE CONSORTIUM’S DUE 11

DILIGENCE AND OVERSIGHT SO CRITICAL TO THE PROJECT? 12

A. The Company and the Consortium have gained valuable lessons learned via the 13

Lake Charles Facility from contracting with a vendor that was not prepared for 14

the rigor of nuclear construction. Proper due diligence can reduce the risk that a 15

vendor is selected that cannot perform quality fabrication at the production rate 16

that meets construction need dates. If the prior challenges experienced at the 17

Lake Charles Facility are repeated, the Project will experience additional delays. 18

IV. RECOMMENDATIONS 19

Q. WHAT IS YOUR RECOMMENDATION REGARDING VERIFICATION 20

AND APPROVAL OF EXPENDITURES DURING THE 9th

/10th VCM 21

PERIOD? 22

PUBLIC DISCLOSURE



29

A. We recommend that the expenditures of $389 million incurred during the 9th/10th

1

VCM be verified and approved. As Staff has previously explained, “verification 2

and approval” of costs means a determination that such costs have actually been 3

spent on the Project and does not preclude a subsequent disallowance by the 4

Commission. 5

6

Q. THE COMPANY IN ITS FILING RECOMMENDS THE REMOVAL OF 7

RESPONSES TO STIPULATED QUESTIONS FOR FUTURE VCMS. DO 8

STAFF AND THE CM AGREE WITH THESE RECOMMENDATIONS? 9

10

A. Yes. Staff and the CM agree with the Company’s recommendations to remove 11

required responses to numbers 4, 10 and 13. Staff does however reserve the right 12

to request the inclusion of new responses for future VCMs. 13

14

Q. DOES THIS CONCLUDE YOUR TESTIMONY? 15

A. Yes it does. 16

EXHIBIT STF-SR/WRJ-1

Resume of Steven D. Roetger


Georgia Public Service Commission Analyst

1

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. 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 o Elevated team's performance to improve consistency, accuracy, and

timeliness of service o Identified client missed revenue opportunities and communicated to

Operations for recapture and/or inclusion with future invoicing

• Key Requirements o Train, motivate, and develop 3 financial analysts to achieve an outstanding

level of service and performance

o Direct workflow to maintain efficiency and productivity without compromising

standards

o Analyze departmental financials to maximize profitability by reviewing

contracts, perform variance analyzes, and ensure complete transaction

billing

o Review complex contracts and interpret for finance reconciliation and billing

procedures

o Prepare client budgets and forecasts

Marine Bank of Florida Marathon, Florida 2003-2005 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 o Identified high-risk, time sensitive accounts for dedicated review to

significantly reduce financial risk to the Bank

o In partnership with the CFO reduced audit management exceptions from 13

to zero year over year o Launched new wire department procedures to decrease response time,

increase capacity, and improve customer service without increasing staff o 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



2

o Comprehensive GIL management including reconciliations, adjusting

entries, and monthly/annual close

o Manage and review the activities of 3 accounting and 2 deposit operations

personnel responsible for accounts payable, wires, ACH operations, VISA

checkcard operations, branch settlements, electronic funds transfers, and

check clearing.

o Establish and refine departmental policies and procedures to improve

accuracy and timeliness of reporting, facilitate employee transition, and

meet audit requirements o Oversee Federal Reserve, FHLB, and IBB correspondent accounts o Support the CFO to meet external audit requirements o Oversee the Bank's daily cash position to minimize overnight net interest

expense o 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 o Re-established accurate and timely monthly reporting to the Corporate

Office o 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 o Comprehensive G/L management including reconciliations, adjusting

entries, and monthly/annual close o Manage the annual audit process o Accounts payable and account receivable

o Payroll and annual bonus calculations

Bridgetown Grill Restaurants Inc. Atlanta, Georgia 1996-1997 Interim Controller Primary responsibilities were to re-establish a reliable Accounting

process and once established facilitate the transition to a new Controller.

• Key achievements o Established internal controls to better manage purchases, inventories, and

reduce cash variances

o Developed Accounting procedures for Unit Managers and trained the

management staff on those procedures

o Assisted the Owner in evaluating an outside purchase offer • Key requirements

o Comprehensive G/L management including reconciliations, adjusting



3

entries, and monthly close procedures o Coordinate the annual audit process o Manage accounts payable and payroll processing o Manage credit card transaction procedures to reduce charge backs

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

o Partnered with Management to streamline the procedure for The Statement

of Cash Flows

o Corrected the BPS calculation (the error proved to be insignificant for the

time period)

o Streamlined governmental reporting and incorporated detailed procedures

for each report

o Provided a Companywide vacation and sick time accrual analysis

• Key requirements o Worked, as part of a team, on the Consolidated Financial Statements of

TBS, Inc.

o Develop various footnotes to the Financial Statements o Provide analysis of accounts for actual to budget and actual to rolling 12

month forecast variances o Provide analysis of, and recommendations for, lease capitalizations o Coordinate with 72 Operating Unit Controllers for the content and timely

receipt of Unit financial data

o Prepare debt covenant calculations for 4 issues and provide forecasts with sensitivity analysis

o Prepare all U.S. Department of Commerce and U.S. Treasury Department statistical reports

Software PeopleSoft/n Vision reporting, Kirchman/Bankway and IPS Sendero banking software, MSA accounting software, Excel, Outtask, and Word

Education MBA Georgia State University in Finance (70% complete) BBA Georgia State University in Finance with an equivalent in Accounting

EXHIBIT STF-SR/WRJ-2

Resume of William R. Jacobs, Ph.D.

William R. Jacobs, Jr. GDS Associates, Inc.

Executive Consultant Page 1 of 7

GDS Associates, Inc., 1850 Parkway Place, Suite 800, Marietta, GA 30067

(770) 425-8100

(770) 426-0303 – Fax

[email protected]

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.




(770) 425-8100

(770) 426-0303 – Fax

[email protected]

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.




(770) 425-8100

(770) 426-0303 – Fax

[email protected]

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.




(770) 425-8100

(770) 426-0303 – Fax

[email protected]

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




(770) 425-8100

(770) 426-0303 – Fax

[email protected]

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.




(770) 425-8100

(770) 426-0303 – Fax

[email protected]

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.




(770) 425-8100

(770) 426-0303 – Fax

[email protected]

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.

Documents

PUBLIC DISCLOSUREmediad.publicbroadcasting.net/p/wabe/files/Jacobs_Testimony_9&10_VCM-PD.pdf10 STF-SR/WRJ-1 Resume of Steven D. Roetger 11 STF-SR/WRJ-2 Resume of William R. Jacobs,