PUBLIC DOCUMENT: TRADE SECRET DATA EXCISED · Black Dog Outage Schedule 4 DOC-192 Correction Schedule 5 Docket No. E002/GR-12-961 Larson Rebuttal Public Version i . Emissions Chemicals

PUBLIC DOCUMENT: TRADE SECRET DATA EXCISED

Rebuttal Testimony and Schedules Kent T. Larson

Before the Minnesota Public Utilities Commission State of Minnesota

In the Matter of the Application of Northern States Power Company for Authority to Increase Rates for Electric Service in Minnesota

Docket No. E002/GR-12-961 Exhibit___(KTL-2)

Operations and System Investments

March 25, 2013

Table of Contents

I. Introduction 1

II. Extended Plant Outages 5

A. Sherco Unit 3 5

1. In-Service Date 7

2. Plant Investments 10

3. Insurance Proceeds 13

B. Black Dog Units 2 and 5 16

III. Capital Additions 21

A. Overview 21

B. Projects with Post-December 2013 In-Service Dates 23

C. Company Proposal 25

D. Distribution Capital Additions 28

IV. Emissions Control Chemicals 29

V. Nobles Wind Project 34

VI. Other Issues 41

A. Third Party Transmission Revenues and Expenses 41

B. Other Revenue 42

C. Cost of Wind Integration 43

D. Momentary Average Interruption Frequency Index 47

VII. Summary and Recommendations 48

Schedules

Sherco 3 Update November 2012 Schedule 1

Sherco 3 Update February 2013 Schedule 2

Sherco Plant Additions Schedule 3

Black Dog Outage Schedule 4

DOC-192 Correction Schedule 5

Docket No. E002/GR-12-961 Larson Rebuttal

Public Version i

Emissions Chemicals Analysis Schedule 6

DOC-1141 Supplement Schedule 7

Docket No. E002/GR-12-961 Larson Rebuttal

Public Version ii

Public Version Docket No. E002/GR-12-961

Larson Rebuttal

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I. INTRODUCTION 1

2

Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3

A. My name is Kent T. Larson. I am the Senior Vice President of Operations for 4

Xcel Energy Services Inc. (XES). 5

6

Q. HAVE YOU PREVIOUSLY PROVIDED TESTIMONY IN THIS PROCEEDING? 7

A. Yes. I filed Direct Testimony that provided an overview of Northern States 8

Power Company’s capital and operation and maintenance budgets for the 9

Energy Supply, Transmission, and Distribution business units within the 10

Operations organization, for purposes of determining test year electric 11

revenue requirements and final rates in this proceeding. 12

13

Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY? 14

A. My Rebuttal Testimony responds to issues raised by Parties regarding our 15

system operations, capital investments, and operating and maintenance 16

expenses (O&M) in the 2013 test year. I provide additional information 17

sought by the Parties and offer some modifications to our request in response 18

to their recommendations. 19

20

Q. WHAT KEY ISSUES DID PARTIES RAISE REGARDING YOUR DIRECT TESTIMONY? 21

A. Questions regarding outages at Sherco 3 and Black Dog Units 2 and 5 were 22

the most significant issues raised by the Parties, with the Department 23

recommending disallowance of all costs associated with Sherco 3, amounting 24

to $36.6 million. Other issues included questions regarding our December 25

2013 capital additions, emissions control chemical costs, and recovery of our 26


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Nobles wind farm project costs. Parties recommend adjustments on these 1

issues reflecting different views and approaches. 2

3

Q. WHAT INFORMATION WILL YOU PROVIDE IN RESPONSE TO THESE ISSUES? 4

A. My Rebuttal Testimony will provide: 5

• Additional information regarding our extended outages at Sherco 3 and Black Dog 6

2 and 5. We share the Parties’ interest in bringing these plants back 7

online as quickly and efficiently as possible. This case is unique – we 8

have not had as significant an event as what occurred at Sherco 3, and 9

the concurrent outage at Black Dog is also uncommon. We are 10

committed to ensuring these plants return to service in a timely manner, 11

while positioning the plants to operate safely and reliably into the 12

future. My Rebuttal Testimony will provide additional detail on these 13

efforts, some of which continues to evolve as we work through the 14

Sherco 3 restoration effort. This additional information will provide 15

the factual support for the alternative recommendation we are making, 16

as summarized in the Rebuttal Testimony of Mr. Jeffrey C. Robinson. 17

• Capital project management procedures and performance results. The Company 18

has a robust process in place to manage and track capital projects, and 19

address emergent delays in the project schedule, which has resulted in 20

consistent on-time completion of projects. Our detailed review of each 21

project with a December 2013 in-service date identified four projects 22

that may not be placed in-service in 2013. We propose to remove 23

those projects from the test year, as reflected in an adjustment 24

described in Ms. Anne E. Heuer’s Rebuttal Testimony. We believe our 25

proposal reflects a more realistic expectation of the projects to be 26


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completed in the test year compared to removing every project with a 1

forecasted December 2013 in-service date. 2

• Updated information to support the emissions chemicals budget. We reviewed the 3

most recent pricing information and explored options to potentially 4

improve the accuracy of the 2013 budget. Our analysis showed that for 5

all plants, excluding Sherco 3, our initial budget is reasonable and 6

possibly slightly less than expected actual costs in 2013. Ms. Heuer 7

supports an adjustment to remove Sherco 3 chemical costs from the 8

test year. We believe our budget, with the adjustment for Sherco 3, 9

produces a more accurate result than one based on historical averages. 10

• Additional support for recovery of Nobles wind project costs. The Nobles wind 11

project was undertaken with Commission approval to meet a statutory 12

obligation to provide a certain percentage of our electricity resources 13

using renewable energy. Consistent with state energy policy and the 14

regulatory compact, it is appropriate to allow the Company to recover 15

its prudently incurred costs for a project required to meet renewable 16

energy obligations. Allowing the Company to recover its reasonable 17

and prudent costs does not disadvantage any of the parties that 18

responded to the request for proposals (RFP), as the project was not 19

competing with Independent Power Producers (IPP) when selected. 20

• Withdrawal of the Third Party Transmission Revenues and Expenses Tracker. 21

We continue to believe that a tracker mechanism may be the best way 22

to ensure that rates reflect the most accurate assessment of these 23

expenses and revenues. For purposes of resolving this case, however, 24

we agree to withdraw the tracker from consideration. We will continue 25

to evaluate this issue for possible inclusion in a future case. 26


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• Responses to miscellaneous issues. Parties raised other issues not explicitly 1

covered in my Direct Testimony, including Other Revenues from a 2

2012 transaction, the costs of wind integration and Momentary Average 3

Interruption Frequency Index (MAIFI) reporting. 4

5

Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS. 6

A. I recommend that the Commission approve the 2013 Operations capital 7

budget of $912 million, which reflects the adjustment of $11.2 million related 8

to four projects that are currently expected to be placed in-service after the 9

end of the test year; and the 2013 Operations O&M budget of $297 million, 10

which reflects the adjustment of $5.9 million related to Sherco Unit 3 O&M 11

costs, including chemicals. 12

13

Approval of my recommendations will support the continued investment and 14

expenses needed to provide safe, reliable, and clean energy to our customers. 15

We have taken steps to ensure that our budgets are as accurate as possible, 16

including reducing the request where supported by more recent information. 17

At the same time, we are not proposing to increase our request for 18

information that suggests higher Operations costs in the test year, but will 19

provide some examples of such cases to demonstrate to the Commission the 20

overall reasonableness of our request. 21

22

Q. HOW IS YOUR REBUTTAL TESTIMONY ORGANIZED? 23

A. First, I provide an update on Sherco 3’s expected return to service and discuss 24

the capital projects at Sherco 3. I also address questions raised by Ms. Nancy 25

Campbell of the Department related to the extended plant outage at Black 26

Dog 2 and 5, including the projects completed during the outage. I then 27


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address the capital projects in the test year, including explaining our process 1

for managing project schedules and identifying four projects that will likely not 2

be placed in-service in 2013. Finally, I respond to other specific issues raised 3

by the Parties, including variability in emissions control chemical costs, the 4

Nobles Wind Project, third party transmission revenues and expenses, the 5

2012 Other Revenue item noted by Ms. Campbell, costs of wind integration, 6

and MAIFI reporting. 7

8

II. EXTENDED PLANT OUTAGES 9

10

A. Sherco Unit 3 11

Q. WHAT ISSUES DID PARTIES RAISE REGARDING SHERCO 3? 12

A. The extended outage at Sherco 3 has become one of the most significant 13

issues in the case, as evidenced by the extent of testimony provided by Parties 14

and the impact to our case. Parties sought updated information on the unit’s 15

expected return to service, as well as a more complete explanation of 16

investments at the unit since the last rate case and the treatment of insurance 17

proceeds. The Department also requested information on the outages at Black 18

Dog Units 2 and 5, including projects completed during the outage and the 19

eligibility of any of the outage-related costs for warranty or insurance 20

reimbursement. 21

22

Q. DID PARTIES OFFER RECOMMENDATIONS RELATED TO SHERCO 3 COSTS? 23

A. Yes. Department witness Ms. Campbell recommends all costs directly 24

attributable to Sherco 3 be removed from the test year. Minnesota Chamber 25

of Commerce (MCC) witness Mr. Larry Schedin recommends that the 26

Company’s entire share of net investment in Sherco 3 be removed from rate 27


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base and placed in Construction Work in Progress (CWIP) until Sherco 3 is 1

back in service and fully accredited. Mr. Schedin also proposes that the 2

Company be denied recovery of replacement energy costs incurred due to the 3

outage, and that the Company should credit the Fuel Clause Adjustment for 4

lost asset based margins. Industrial, Commercial, and Institutional (ICI) 5

customer intervention group witness Mr. William Glahn recommends Sherco 6

3 be removed from rates until the unit is back in operation. 7

8

Q. WHAT IS THE COMPANY’S RESPONSE TO THESE RECOMMENDATIONS? 9

A. The failure of Sherco 3 was an unprecedented event that has led to extensive 10

restoration activities and a prolonged outage. We understand Parties’ 11

concerns about recovery of costs while the unit has been offline, as well as 12

Parties’ interests in getting the unit back into service. We share the goal of 13

getting Sherco 3 online as soon as possible and have been working hard to 14

keep the restoration on-track. At this time, we expect Sherco 3 to return to 15

service on or before September 30, 2013. Thus, the plant will operate and 16

provide service to customers during the test year. 17

18

In evaluating potential options to address the concerns raised, we looked for 19

solutions that would balance the various interests of the parties. The Rebuttal 20

Testimony of Mr. Robinson explains the Company’s proposed overall 21

adjustment, including why it is a reasonable alternative to complete 22

disallowance of the plant’s costs in rates. 23

24

As support for our proposal and in response to requests for additional 25

information, I discuss the expected return to service of Sherco 3, investments 26


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at the unit since the last case, treatment of insurance proceeds, and the outages 1

at Black Dog Units 2 and 5. 2

3

1. In-Service Date 4

Q. PLEASE DESCRIBE THE OUTAGE AFFECTING SHERCO 3. 5

A. In November 2011 there was a significant failure at Sherco 3, which resulted 6

in an extended outage. The event occurred at the end of a regularly scheduled 7

overhaul outage, which included completion of an uprate project for Unit 3. 8

During the testing procedure, specifically the overspeed test, the turbine and 9

generator instrumentation reported vibration levels significantly above normal, 10

and the unit shut down. The vibration damaged many of the steam, oil, and 11

hydrogen seals in the turbines and generator, and caused a fire. The turbine 12

generator, rotor and exciter (among other components) suffered significant 13

damage, requiring us to consider either total replacement (a multi-year 14

process) or extensive repairs. The Company has provided detailed reports to 15

the Commission regarding the November 2011 event and our restoration 16

efforts. These reports are provided as Exhibit___(KTL-2), Schedules 1 and 2 17

to my testimony. 18

19

Q. HAS THE EXPECTED IN-SERVICE DATE FOR SHERCO 3 CHANGED SINCE THE 20

COMPANY’S INITIAL FILING IN THIS CASE? 21

A. Yes. The Company began initial development of the 2013 budget in early 2012 22

and completed it in August 2012. For planning purposes, the 2013 budget 23

assumed a January 1, 2013 return to service. By the time of our initial filing, 24

the Company determined that additional time would be needed for the repairs. 25

In our November 2012 update to the Commission, we stated that we believed 26

Sherco 3 would resume operation around the end of first quarter 2013. As 27


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noted in our February 2013 update, we now expect the unit to return to 1

service in the third quarter of 2013. 2

3

Q. PLEASE EXPLAIN THE CAUSES FOR THE DELAY IN RETURNING THE UNIT TO 4

SERVICE. 5

A. As with any large, complex project, we have updated our schedule as we have 6

learned more about the extent of the damage and the scope and nature of the 7

necessary repairs. The November 2011 event resulted in serious damage, and 8

we needed to use a systematic approach to dismantle and repair Unit 3, in part 9

to ensure all necessary documentary evidence was preserved to facilitate 10

insurance or other claims. As we have discussed in our reports to the 11

Commission, as we progressed in the repair process and gained access to 12

additional layers of equipment and structures that could not be observed 13

during the initial damage assessment, we discovered the damage was more 14

extensive and the repair work would be more involved than initially 15

anticipated. The additional damage was not fully known until after we filed 16

our initial Application. 17

18

In addition, many of the techniques required to repair various components 19

were not known in the early phases of the project and, in some cases, had to 20

be developed during the repair process. There is no equivalent restoration 21

project anywhere in the world that could be used as a roadmap for this 22

project. The unique nature and extent of the damage resulting from the event 23

meant there was limited industry information to provide guidance on expected 24

repair cycle times. As such, expectations could not be validated against prior 25

industry experience. 26

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Q. WHAT IS THE CURRENT STATUS OF THE REPAIR AND RESTORATION PROCESS? 1

A. Repair and restoration work is progressing on Sherco 3. The majority of 2

offsite and onsite repairs of major components required for reassembly of 3

Unit 3 are complete and reassembly has begun. Of the equipment that was 4

still being repaired offsite as of our February 2013 update: 5

• The generator rotor was returned to the plant site in March and is 6

staged for installation into the generator; 7

• The reheat turbine components were returned to the site in February; 8

• The generator exciter components were returned to the site in February 9

in preparation for re-assembly. 10

11

The low pressure rotors are the most significant components that are currently 12

offsite, and they are expected to be returned to the plant in late March. 13

Reassembly will be followed by start-up, commissioning, and testing to verify 14

operational readiness prior to unit restart and return to service. 15

16

Q. ARE THERE SPECIFIC FACTORS OR RISKS THAT COULD DELAY THE RETURN TO 17

SERVICE OF SHERCO 3 BEYOND THE ANTICIPATED DATE? 18

A. The most significant risk that remains is the onsite reassembly of the 19

components that were repaired. We do anticipate some “fit-up” issues, and 20

those issues are reflected in the current reassembly schedule and the return-to-21

service timeframe. 22

23

Q. WHAT STEPS HAS THE COMPANY TAKEN TO MITIGATE THOSE FACTORS OR 24

RISKS? 25

A. The Company has taken a number of steps to mitigate the potential schedule 26

risk associated with the reassembly and fit-up of repaired components. First, 27


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whenever possible, repaired components were partially reassembled and 1

dimensionally checked at the repair shop before being returned to the plant 2

site. This ensured proper fit-up before the components were returned to the 3

site for reassembly. Second, independent quality control inspections were 4

conducted on components in the repair shops to ensure repairs were made in 5

accordance with the technical specifications (e.g. dimensions, clearances, 6

tolerances, etc.) before the components were returned to the plant site for re-7

assembly. Third, onsite quality control checks will be performed throughout 8

the reassembly process to ensure that any issues associated with fit-up are 9

promptly identified and resolved in a timely manner. Finally, various technical 10

experts are onsite during the reassembly to ensure all applicable specifications 11

and technical requirements are met. 12

13

Q. HOW DOES THE COMPANY PROPOSE TO UPDATE THE COMMISSION AND 14

PARTIES ON RESTORATION STATUS? 15

A. We propose to submit to the Commission an update on April 1 to coincide 16

with the expected return of critical turbine parts to the Sherco site, and 17

monthly reports thereafter. 18

19

2. Plant Investments 20

Q. DOES MS. CAMPBELL IDENTIFY INCREASES TO SHERCO 3 PLANT IN-SERVICE 21

SINCE THE LAST RATE CASE? 22

A. Yes. Ms. Campbell states that there is an increase to Sherco 3 plant in-service 23

of $46.7 million since our 2010 case, of which she states $31.1 million is 24

unsupported. She specifically identifies $2.924 million for a restoration project 25

that appears to be related to the failure event. Because she states the support 26

is inadequate for these plant additions, she is unable to confirm that the costs 27


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were not reimbursed or reimbursable by insurance proceeds, leaving 1

uncertainty about whether the Company has included costs reimbursed or 2

reimbursable by insurance in the rate case. 3

4

Q. PLEASE IDENTIFY AND BRIEFLY DESCRIBE THE SHERCO 3 PLANT ADDITIONS 5

THAT CONTRIBUTE TO THE INCREASE IN PLANT IN-SERVICE. 6

A. The actual and forecasted plant additions are $45.9 million. The $45.9 million 7

of plant additions are comprised of: 8

• Projects in 2010 and 2011. Of the $45.9 million, $21.9 million was for 9

projects not fully reflected in the 2011 test year, such as installation of a 10

slaking water heating system to improve efficiency and reduce the 11

amount of lime required to reduce sulfur dioxide (SO2 ) emissions, and 12

replacement of Unit 3 primary air heater baskets to improve air heater 13

performance and improve heat rate. The projects completed in 2011 14

were part of the scheduled overhaul or accelerated to coincide with the 15

overhaul in order to reduce project costs. 16

• Projects in 2012. Approximately $5.4 million of capital additions were 17

installed in 2012. Projects included some initiated in 2011, such as 18

baghouse refurbishment and backpass sootblowing system. The 19

projects were completed to take advantage of the unit being offline. 20

• Projects expected to be placed in-service in 2013. Approximately $18.6 million 21

of capital additions are expected to be placed in service in 2013. These 22

projects are being conducted concurrent with the Unit 3 restoration but 23

are not a part of the restoration project. They include replacement of 24

the Unit 3 cooling towers, and overhaul and capital replacement of the 25

two remaining coal mill gear boxes, which completes the cycle of coal 26


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mill (gearbox) replacement on all 10 Unit 3 coal mills. The projects were 1

planned for future years, but were accelerated to take advantage of the unit 2

already being offline, to reduce future outages. 3

4

Exhibit___(KTL-2), Schedule 3 to my Rebuttal Testimony includes a detailed 5

list of each project that makes up the $45.9 million of Sherco 3 additions. 6

7

Q. IS ANY PART OF THE $2.9 MILLION PROJECT LABELED AS A “RESTORATION 8

PROJECT” ELIGIBLE FOR INSURANCE REIMBURSEMENT? 9

A. No. The $2.9 million restoration project represents our estimate at the time of 10

filing of NSPM’s share of project costs related to the restoration of Sherco 3 11

that are ineligible for insurance reimbursement but will be placed in service in 12

2013 when Sherco 3 returns to service. Our current estimate is that a total of 13

approximately $13.8 million of restoration work will likely not be covered by 14

insurance, with NSPM and SMMPA sharing these costs in accordance with 15

the joint ownership agreement. 16

17

For example, as a result of the event, we discovered corrosion in the 18

condenser tubesheets. After removal of the tubes, we discovered tubesheet 19

thicknesses of less than 0.5 inches, which is less than the specified 1.5 inches. 20

We are installing new tubesheets in the most corroded areas. Based on 21

discussions with the insurance adjuster, we estimate that only 50 percent of 22

the costs will be covered by insurance. Similarly, the insurance adjuster has 23

estimated that 50 percent of pump repairs are a result of normal wear and tear 24

and thus ineligible for reimbursement. While we are disputing claims that we 25

believe have been incorrectly denied, for financial planning purposes, we have 26

assumed the insurance adjuster’s initial position is upheld. If the Company is 27


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successful in these claims, however, the additional recoveries would be 1

recorded to the appropriate accounts, similar to other insurance funds. 2

3

In some cases, the outage provides an opportunity to proactively address 4

potential future issues. For example, while we are working on the condenser 5

tubesheets, we are adding tubesheet lining to halt further corrosion of the tube 6

sheets and upgrading to serrated tubesheets to improve the tube-to-tube sheet 7

tightness and enhance long term reliability. These project costs are related to 8

the restoration, but are beyond what the insurance company believes is 9

necessary to return the unit to its previous condition. 10

11

Q. IS THE COMPANY SEEKING RECOVERY OF THE COSTS IN EXCESS OF $2.9 12

MILLION IN THIS RATE CASE? 13

A. No. And as I understand, Mr. Robinson’s proposal includes the 2013 14

depreciation on the $2.9 million of investment. 15

16

3. Insurance Proceeds 17

Q. PLEASE SUMMARIZE THE CAPITAL AND O&M COSTS RELATED TO SHERCO 3 18

THAT HAVE BEEN INCURRED AS A RESULT OF THE FAILURE. 19

A. Through February 2013, the Company has incurred approximately $144 20

million in costs as a direct result of the Sherco 3 event. As of December 31, 21

2012, the Company has submitted insurance claims for $110 million and has 22

received $104 million in reimbursement. Other insurance claims are pending 23

payment. We expect additional insurance claims and payments as the 24

restoration process continues and additional costs are incurred. 25

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Q. HAS THE COMPANY INCLUDED ANY COSTS IN THE TEST YEAR THAT WERE 1

REIMBURSED OR ARE REIMBURSABLE BY INSURANCE? 2

A. No. As I previously discussed, the capital additions included in the test year 3

are beyond the scope of the restoration project, as defined for insurance 4

purposes. 5

6

Q. WHAT PROCESS DOES THE COMPANY FOLLOW TO ENSURE THAT INSURANCE 7

PROCEEDS ARE ISOLATED FROM RATES? 8

A. The insurance claim process begins with the reporting of the loss event to the 9

hazard insurance department. A notice is then sent to the Company’s 10

insurance broker who sends the official first notice of loss to our panel of 11

insurers. Investigation activities are initiated following the initial reporting, 12

including site visits, evidence collection, and root cause analysis. 13

14

The recovery phase of the process includes damage assessment, repair, 15

reassembly and testing. A new work order is created to capture all repair and 16

restoration-related costs. In the case of Sherco 3, all charges related to the 17

restoration are captured in a work order and recorded in capital and O&M 18

restoration subledgers specifically set up for the restoration project. These 19

charges are reconciled monthly against any insurance reimbursements 20

received. 21

22

As the invoices are being paid, the adjusters validate these invoices against the 23

work completed. They will look for any betterments or damage not covered 24

by the insurance policy. The adjuster meets with the insurers periodically to 25

report on the status of the verification process and in the event of a larger 26

loss, like Sherco 3, request a partial payment. After all repairs are completed 27


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and all costs are captured, a final verification of costs is conducted by the 1

adjuster, including verifying purchase orders, reviewing bid packages, and 2

matching invoices to purchase orders. The final payment of insurance 3

proceeds is negotiated following verification. 4

5

Company witness Ms. Amy Stitt provides in her Rebuttal Testimony a detailed 6

discussion of the accounting treatment of insurance proceeds and how they 7

are appropriately credited to the restoration work orders. 8

9

Q. DOES MS. CAMPBELL HAVE A RECOMMENDATION RELATED TO INSURANCE 10

PROCEEDS FOR FUTURE RATE CASES? 11

A. Yes. Ms. Campbell states that all costs and insurance proceeds must be clearly 12

identified whenever the Company proposes to recover those costs in future 13

rate cases. Additionally, she recommends that the Commission require the 14

Company to identify in its next initial rate filing all repairs and rebuild costs of 15

Sherco 3 and all insurance proceeds that have been received over time, 16

whether those payments were for capital or expense costs. 17

18

Q. DOES THE COMPANY AGREE TO THIS RECOMMENDATION? 19

A. Ms. Stitt addresses Ms. Campbell’s recommendations regarding the restoration 20

costs and insurance proceeds in her Rebuttal Testimony. The Company 21

agrees to provide a full report of the restoration project cost and insurance 22

recovery information, but final information would not be available by the time 23

of the initial rate filing in our next rate case even if Sherco 3 returns to service 24

before September 30, 2013. Ms. Stitt provides recommendations regarding 25

future reports to the Commission, which could be analogous to the reports we 26

have provided regarding the restoration process. We also offer to provide the 27


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Commission and Department the results of the engineering report analyzing 1

the cause(s) of the event. 2

3

B. Black Dog Units 2 and 5 4

Q. DOES MS. CAMPBELL EXPRESS CONCERNS REGARDING OUTAGE COSTS FOR 5

BLACK DOG UNITS 2 AND 5? 6

A. Yes. Ms. Campbell states that her recommendation to remove all costs related 7

to Sherco 3 from the test year is based in part on concerns related to outage 8

costs for Black Dog Units 2 and 5. Ms. Campbell states that the Company 9

has not shown that it is reasonable to recover $22.9 million in costs related to 10

the extended plant outages at Black Dog. She is concerned that Siemens may 11

have caused or contributed to the outage, which would result in potential 12

reimbursement for the incurred costs, yet the Company did not provide 13

testimony on the outages or potential proceeds from Siemens or other 14

sources. 15

16

Q. WHAT IS THE COMPANY’S RESPONSE TO THESE CONCERNS? 17

A. The Company understands it could have provided more information in its 18

initial rate filing. It is reasonable to recover the $22.9 million in costs related 19

to the extended plant outage at Black Dog, however, because the projects 20

were needed to return these two important units to service or were accelerated 21

to coincide with the outage, thus lowering the overall cost of the projects or 22

avoiding or shortening future outages. The project costs were not covered by 23

warranty or our insurance policies. Thus, unlike Sherco 3, there were no 24

proceeds to offset the project costs. 25

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Q. PLEASE DESCRIBE THE EVENTS OR FACTORS THAT CAUSED OR CONTRIBUTED 1

TO THE OUTAGE. 2

A. The planned outage for Units 2 and 5 that began in September 2011 was 3

extended to allow for replacement of the exhaust cylinder to resolve cracking 4

and distortion issues with a strut on the exhaust cylinder. 5

6

We had experienced a similar strut failure in October 2010. At that time we 7

performed weld repairs and unit realignment and returned the unit to service. 8

Inspections were scheduled to monitor these areas closely. An inspection in 9

July 2011 indicated there was another crack formation in one of the struts. 10

The inspection in September 2011 showed the crack on this strut had 11

propagated to a point where running the unit posed significant risk to 12

equipment and our staff. The unit was taken out of service so we could 13

perform a weld repair similar to what was done in October 2010. However, 14

the weld repair led to a misalignment in the shaft between the compressor and 15

power sections of the turbine, which could not be fixed and necessitated 16

replacement. The strut damage also required replacement of the exhaust 17

cylinder, which cost $14.68 million. The amount of time needed to complete 18

the replacement was impacted by the need to have the new assembly and 19

components fabricated by the manufacturer and shipped to the site. I provide 20

a more detailed discussion of the outage, including a diagram of the exhaust 21

struts, in Exhibit___(KTL-2), Schedule 4. 22

23

Q. WERE OTHER PROJECTS COMPLETED ON UNIT 5 DURING THE OUTAGE? 24

A. Yes, we completed $8.27 million in additional projects on Unit 5 during the 25

outage. In order to avoid a planned eight-week outage in 2013 for a 26

generator rewind, we accelerated the rewind to 2012 to coincide with the 27


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ongoing outage. This project totaled $3.31 million. Similarly, with the 1

combustion turbine open, we found that the hot gas path parts were in need 2

of inspection and repair. The vendors contacted to provide repair bids all 3

concluded that the parts were at the end of life and could not be repaired 4

without risking subsequent extensive damage to the unit. Replacing the parts 5

while the turbine was open provided the most cost-effective path for 6

addressing this issue. The cost of the replacement hot gas path parts, as well 7

as the inspection, totaled $4.96 million. The units returned to service in 8

August 2012. 9

10

Q. HAS THE COMPANY RECEIVED REIMBURSEMENT OR OTHER COMPENSATION 11

RELATED TO THE OUTAGE FROM SIEMENS OR ANY OTHER SOURCE? 12

A. No. Both the struts and the hot gas path parts were beyond the 13

manufacturer’s warranty period and no longer covered. The repairs were not 14

eligible for insurance reimbursement. Fortunately, our inspections and 15

monitoring caught the issue before there was a serious failure and resulting 16

damage. 17

18

Q. HAVE THERE BEEN SUBSEQUENT OUTAGES AT BLACK DOG UNITS 2 AND 5? 19

A. Yes. The same Black Dog units were taken out of service on December 23, 20

2012 to repair the Unit 2 steam turbine after a turbine bearing high vibration 21

event. Because the two units cannot operate independently, they always go on 22

outage together. The high vibration caused the operators to trip the unit to 23

protect it from catastrophic failure. We replaced typical wear parts, such as 24

bearings and seal strips. This event was unrelated to the previous event. 25

26

27


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19

Q. WHAT IS THE CURRENT STATUS OF THE BLACKDOG 2 AND 5 UNITS? 1

A. The issues related to the Unit 2 high vibration event were resolved. However, 2

we are holding the units out of service until conditions allow for a safe start-3

up. Specifically, the high humidity and relatively low temperatures we are 4

experiencing in March can cause icing conditions in the turbine during a cold 5

start up, which could result in turbine damage. Cold start up after an 6

extensive outage requires additional holds at low load points, which can 7

increase the potential for icing in these weather conditions. We are closely 8

monitoring the situation and will bring the units online as soon as we can 9

safely do so. 10

11

Q. HAS THE COMPANY TAKEN STEPS TO MINIMIZE RISKS ASSOCIATED WITH 12

SUPPLIER AND VENDOR QUALITY AND PERFORMANCE ISSUES? 13

A. The Company uses competitive bidding processes, when possible, to take 14

advantage of competition between suppliers and contractors in order to keep 15

costs low for customers. We monitor supplier and contractor performance 16

and require corrections as appropriate. While quality and performance issues 17

cannot entirely be prevented in a business this complex, our suppliers and 18

vendors generally perform well. The Company’s General Conditions for 19

Major Supply Agreement (General Conditions Agreement 9386) contain 20

industry-accepted clauses with respect to damages, indemnity, and quality 21

assurance requirements, which provide standard contractual protections for 22

the Company (and indirectly ratepayers). 23

24

In order to mitigate the potential for contractor performance issues and 25

increased costs during plant outages, however, the Company is implementing 26

the following steps for capital and O&M projects: 27


Larson Rebuttal

20

• Implement more stringent quality assurance and contractor oversight. The Energy 1

Supply Quality Assurance Program establishes policies and procedures 2

to provide oversight of supplier and contractor performance. Under 3

this program, specific quality requirements are imposed on suppliers 4

and contractors through the contract. The contract requirements 5

provide detailed expectations for suppliers and contractors to 6

implement their quality program requirements during manufacturing 7

and installation of procured goods and services. In addition, the 8

contract permits the Company to perform oversight inspections at 9

supplier and contractor facilities, including Company field work areas, 10

to evaluate contractor and supplier fabrication and installation 11

performance. 12

• Negotiate more stringent liquidated damages for poor contractor performance on 13

projects that could affect outage duration. In addition to the damage 14

provisions, contractor performance issues are captured on project 15

closeout checklists and forwarded to Supply Chain for inclusion into 16

our data base for consideration in future bid cycles. 17

• Perform post-maintenance testing following installation of equipment to ensure the 18

supplied equipment meets our specifications. This allows us to resolve any 19

issues prior to the project’s completion and final payment. 20

21

We believe these enhancements will provide ongoing performance 22

improvement by suppliers and contractors, as we similarly work towards 23

continuous improvement by our own employees. 24

25

26

27


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21

III. CAPITAL ADDITIONS 1

2

A. Overview 3

Q. WHAT IS THE PURPOSE OF THIS PORTION OF YOUR REBUTTAL TESTIMONY? 4

A. I will respond to the concerns raised by Ms. Byrne of the Department related 5

to capital additions with estimated December 2013 in-service dates, and 6

Distribution capital additions specifically. I identify projects expected to be 7

placed in-service after the test year, and introduce a proposal to modify the 8

test year capital budget to remove these projects, explaining why the modified 9

budget is more reasonable than Ms. Byrne’s recommended adjustment. Also, 10

I discuss the impact of an error in the Distribution capital additions reported 11

in our initial response to Department Information Request No. DOC-192, 12

which was used to support Ms. Byrne’s recommendation. We supplemented 13

our response to DOC-192 on March 21, 2013. 14

15

Q. PLEASE SUMMARIZE THE ISSUES RAISED BY MS. BYRNE. 16

A. Ms. Byrne identified 30 projects that are forecasted to be put into service in 17

December 2013, of which 25 are included in the test year and five are 18

proposed for recovery through the Transmission Cost Recovery (TCR) Rider. 19

She states it is not reasonable to expect all (or any) of the projects to be in-20

service on time, given construction and other possible delays. She 21

recommends a rate case adjustment of $71.3 million, representing the removal 22

from the test year of the 25 projects not eligible for rider recovery. Five of the 23

25 projects are nuclear projects and are addressed in the Rebuttal Testimony 24

of Company witness Mr. Timothy J. O’Connor. 25

26


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22

As support for this recommended adjustment, Ms. Byrne expresses concern 1

about the proposed Distribution capital additions, stating that actual capital 2

additions have been significantly below the test year budget over the past four 3

years. Because of this, she states the Company has not demonstrated that it is 4

reasonable to increase the Distribution budget by 15.5 percent over 2012 5

actual results. 6

7

Q. WHAT IS YOUR RESPONSE TO MS. BYRNE’S RECOMMENDED ADJUSTMENT? 8

A. Ms. Byrne’s recommendation to disallow recovery for every project with a 9

December 2013 in-service date is inconsistent with what we know about the 10

status of the projects and our demonstrated performance of delivering 11

projects on-time. Therefore, it would result in a less accurate capital budget 12

than our proposed budget and should not be approved. Certainly, there have 13

been specific and unique instances, such as with Sherco 3, where projects have 14

experienced significant delays. As I discuss below, however, our overall 15

performance shows that our project estimation process and project 16

management protocols are effective at gauging the time and cost required to 17

complete a project and keeping projects on-track. These factors provide 18

reasonable assurance that the majority of identified projects will be placed into 19

service in 2013. 20

21

Also, as I discuss below, due to an inadvertent error in the Distribution capital 22

additions reported in our response to Department Information Request No. 23

DOC-192, actual Distribution capital additions exceeded the test year budget 24

over the four-year period, as opposed to being significantly less. Our 25

supplemental response to DOC-192 is provided as Exhibit___(KTL-2), 26

Schedule 5 to my testimony. 27


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23

B. Projects with Post-December 2013 In-Service Dates 1

Q. PLEASE IDENTIFY THE PROJECTS THAT ARE NOW NOT EXPECTED TO BE IN-2

SERVICE IN THE TEST YEAR. 3

A. The four projects proposed for removal from the 2013 test year include the 4

following: 5

• Freeport Substation Upgrade. We are converting this substation from 4 kV 6

to 12.5 kV. The project is delayed due to a scope change. The original 7

scope called for rebuilding on the existing substation site, but further 8

analysis revealed that the site is too small to accommodate the new 9

substation. The project is delayed as we work through the process of 10

acquiring land. 11

• West Creek Substation to Scott County Substation Line. This project involves 12

building a 115 kV transmission line from West Creek substation to 13

Scott County substation for load-serving needs in the Chaska area 14

southwest of Minneapolis. The project is part of the Highway 212 15

Conversion that is currently going through the Certificate of Need and 16

Route Permit Application process (Docket No. E002/CN-11-826). We 17

have adjusted the in-service date to better align with the timing of the 18

regulatory approval process. 19

• Scott County Substation Termination. The work at Scott County substation 20

is to terminate the new 115 kV line from West Creek into a 115 kV bay. 21

This project is also delayed due to timing of the Certificate of Need and 22

Route Permit Application process. 23

• Pipestone to Tracy Line. This transmission project was cancelled as 24

originally scoped and replaced with a project with a smaller scope. We 25

were able to reduce the scope (and cost) as a result of evaluation during 26

the value engineering phase, which concluded that we could modify 27


Larson Rebuttal

24

rather than replace numerous structures. Consequently, a new project 1

was created to refurbish the line that included a fewer number of pole 2

and cross-arm replacements, and the prior project was cancelled. The 3

new project was placed in-service in February 2013. 4

5

Q. WHAT ADDITIONAL SUPPORT CAN YOU PROVIDE TO CONFIRM THE 6

LIKELIHOOD THAT THE REMAINING 21 PROJECTS WILL BE PLACED IN-SERVICE 7

IN 2013? 8

A. Because our project management procedure requires consistent monitoring of 9

project status and assessment of risks, we are able to confirm that these 21 10

specific projects are currently on-track for 2013 completion. Of the six 11

transmission projects forecasted to be placed in-service in December 2013, 12

three are currently expected to be completed no later than November. This is 13

common, as our project estimation guidelines require our estimators to 14

consider potential risks and complications. As stated in the Capital Project 15

Governance Policies discussed later in my testimony, estimators are instructed 16

to reflect the most likely and realistic scenario and never assume that they are 17

estimating a perfect project. For this reason, in-service dates should not be 18

considered to reflect the best case scenario, but our best estimation of a 19

realistic scenario, given past project experiences. Thus, we disagree with Ms. 20

Byrne’s claim that the Company has not considered possible construction or 21

other delays. 22

23

Additionally, we are confident that eight of the nine distribution projects Ms. 24

Byrne identified as having December 2013 in-service dates will be complete 25

earlier in 2013 and in some cases much earlier. One project is already 26

complete and four projects are on track to be completed by the end of March 27


Larson Rebuttal

25

2013 to be ready to serve summer peak loads. Two others are in progress and 1

expected to be in-service by August 1. The last project involves replacing a 2

substation transformer to meet an industrial customer’s increasing demands 3

and has a projected in-service date of November 6, 2013. That project is 4

timed to meet the customer’s scheduled requirements. 5

6

C. Company Proposal 7

Q. DOES THE COMPANY PROPOSE MODIFICATIONS TO THE OPERATIONS TEST 8

YEAR CAPITAL BUDGET RELATED TO THESE FOUR PROJECTS? 9

A. Yes. The Company proposes to remove from the test year the costs 10

associated with the four projects no longer expected to be completed in 2013. 11

The capital costs associated with these projects total $11.2 million. Removing 12

these costs from the capital budget results in a reduction in the test year capital 13

additions from $923.2 million to $912 million. Ms. Heuer details the 2013 test 14

year revenue requirement impact in her Rebuttal Testimony. 15

16

Q. WHY IS THE COMPANY’S ADJUSTMENT REASONABLE? 17

A. We reviewed each of the projects with December 2013 in-service dates in light 18

of current information about project status and potential risk factors. Our 19

review identified the projects that are known or expected to be delayed or 20

cancelled for specific, documented reasons, as well as those expected to be 21

completed prior to December 2013. Thus, we have up-to-date information on 22

the projects scheduled for completion later in the year. Based on this 23

information, it is unrealistic to assume that every project with an estimated in-24

service date in December 2013 will not be completed in the test year. 25

Adopting a recommendation based on this assumption would result in a test 26

year that significantly understates known capital additions. 27


Larson Rebuttal

26

Q. WHAT STEPS DOES THE COMPANY TAKE TO MITIGATE DELAYS AND KEEP 1

PROJECTS ON SCHEDULE? 2

A. Xcel Energy has Capital Project Governance Policies that address the 3

fundamental governance requirements for Transmission projects (including 4

Distribution substation projects) and Energy Supply within the capital project 5

portfolio. The policies provide a road map on how to execute, monitor and 6

control a typical capital project. 7

8

Each approved capital project has a project schedule developed at its 9

inception (often two to three years in advance of the proposed in-service date) 10

within the project scheduling software. The Project Manager, working with 11

the Project Controls team, Engineering team, and other project participants, 12

will develop and approve the initial project schedule. Once schedules are 13

created and approved they must be monitored and updated on a monthly 14

basis. 15

16

For any projects that fall behind schedule, the Project Managers and Project 17

Controls team must work with the project stakeholders to develop an action 18

plan to get the affected activities back on schedule. In some cases, a 19

Project Change Request (PCR) may be required, which documents the change, 20

the reasons for the change, and the required approvals. The Schedule PCR 21

Committee must approve or reject a PCR. This Committee is comprised of 22

the directors who design and build the facilities, as well as management. If the 23

project change is properly justified and approved, a new project baseline is 24

established and the project would move back to a “green” or “on-track” 25

condition status. 26

27


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27

Q. HOW HAS THE OPERATIONS GROUP PERFORMED WITH REGARD TO ON-TIME 1

COMPLETION OF PROJECTS? 2

A. The key performance indicator that Xcel Energy uses to monitor and control 3

capital Transmission (and Distribution substation) project schedules is 4

the Schedule Performance Index (SPI). The SPI measures the work 5

accomplished by comparing the planned work (baseline) to what was actually 6

accomplished. From a baseline of 100 percent, each day of delay deducts two 7

percent from the score, while each day ahead of a scheduled milestone adds 8

two percent, up to 10 percent. On a monthly basis, major scheduling 9

milestones are measured against the project’s approved schedule. The major 10

milestones are: permitting complete, engineering complete, end construction 11

milestone, and project in-service date. Many other employee-level milestones 12

are also captured for each project such as: perform survey, create control 13

drawings, and create physical design. 14

15

Results are tracked for each project. For larger projects with estimated costs 16

greater than $25 million, the in-service date SPI was 110 percent, which 17

indicates that these larger projects were placed in-service prior to the 18

forecasted in-service date. For smaller projects, the in-service date SPI was 19

96.3 percent, which indicates the projects were placed into service an average 20

of only two days after the scheduled in-service date. 21

22

Energy Supply also has a strong track record of completing projects on 23

schedule. The vast majority of Energy Supply Board Level projects have been 24

completed ahead of schedule, dating back to the Black Dog Unit 5 project in 25

2002. Other major projects completed ahead of schedule include: 1) the King, 26

High Bridge, and Riverside MERP projects; 2) the Blue Lake and Angus 27


Larson Rebuttal

28

Anson combustion turbine projects; and 3) the Grand Meadows and Nobles 1

wind projects. The majority of the smaller (less than $25 million) Energy 2

Supply projects are done in support of our generating fleet and are installed 3

during scheduled plant outages. We therefore believe the in-service dates 4

reflected in the 2013 budget, as updated, reasonably reflect the projects that 5

will be in service by year-end 2013. 6

7

D. Distribution Capital Additions 8

Q. DID MS. BYRNE RAISE CONCERNS SPECIFIC TO DISTRIBUTION CAPITAL 9

ADDITIONS? 10

A. Yes, Ms. Byrne states that the Company has been over-recovering the costs of 11

Distribution capital additions since 2009 based on comparing the annual 12

project costs included in test years with actual capital additions. Additionally, 13

she states that the Company has not shown that it is reasonable to increase the 14

test year Distribution budget by over 15 percent compared to 2012 actuals. 15

16

Q. WHAT IS YOUR RESPONSE TO MS. BYRNE’S STATEMENTS? 17

A. Upon closer review of our response to Information Request No. DOC-192, 18

we discovered that the 2009 test year amount for Distribution included in our 19

response did not include an adjustment made to the 2009 test year after the 20

2009 Distribution budget was developed. The adjustment reflected the 21

postponement of a large project. This adjustment of $36.8 million resulted in 22

a 2009 test year budget of $121.8 million, as opposed to $158.6 million we 23

included in our initial response. We apologize for this error, and we 24

supplemented our response to DOC-192 when we discovered it. Table 1 25

below reflects the corrected 2009 number, and shows that over the four-year 26

period, Distribution capital additions actually exceeded the test year budgets 27


Larson Rebuttal

29

by $5 million, or one percent. Thus, Distribution has a solid track record of 1

placing projects into service as planned. 2

3

Table 1: Distribution Capital Additions ($000)

2009 TY 2009

Actual 2010

Actual 2011 TY 2011

Actual 2012

Actual

Distribution - Total Company $121,801 $116,402 $117,063 $131,755 $149,121 $129,605Deviation from TY ($5,398) ($4,737) $17,366 ($2,150)Total Deviation 2009-2012 $5,080

4

With regard to the increase to the Distribution capital budget for 2013, I refer 5

back to my Direct Testimony, where I discussed the main investment drivers, 6

including maintaining and improving existing substation and distribution line 7

assets, increasing system capacity and flexibility, and relocating facilities within 8

public right-of-ways. We believe that with the correction noted above, we 9

have adequately supported our past performance and future investments. 10

11

IV. EMISSIONS CONTROL CHEMICALS 12

13


A. I respond to the chemicals cost adjustment proposed by Ms. Campbell. I 15

discuss the updated pricing information that supports the reasonableness of 16

our original proposal. I also respond to concerns about past variability in 17

chemical costs. 18

19

Q. PLEASE SUMMARIZE THE ISSUES RAISED BY MS. CAMPBELL. 20

A. Ms. Campbell expresses concern about the level of emissions control chemical 21

costs included in the test year because she states actual chemical costs do not 22

support the Company’s claims of increased costs in the test year and the 23


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30

assumption of normal operation of Sherco 3 is unreasonable. Based on her 1

review of chemical usage and cost by chemical and by plant, Ms. Campbell 2

recommends an adjustment to the budget. The adjustment was developed by 3

taking a four-year average of actual chemical costs for lime at the Red Wing 4

and Wilmarth plants and ammonia at the King, Black Dog, High Bridge, and 5

Riverside plants. Mercury sorbent costs at King were adjusted to match 2012 6

actual costs and the lime costs at King were accepted as proposed. Ms. 7

Campbell excluded all chemical costs for Sherco 3. Her adjustment results in 8

a total emissions control estimate of $6.2 million at the NSPM total Company 9

level, representing a $6.5 million or 51 percent reduction from our proposed 10

budget. 11

12

Q. WHAT IS YOUR RESPONSE TO MS. CAMPBELL’S RECOMMENDED ADJUSTMENT? 13

A. Our goal is to propose a chemicals budget that is as accurate as possible, 14

recognizing the inherent variability in cost drivers. To address Ms. Campbell’s 15

concerns about the chemical budgets, we explored options that would 16

recognize more up-to-date chemical prices while addressing potential 17

variability in usage. For example, similar to Ms. Campbell’s approach, we 18

excluded Sherco 3 chemical costs, and looked at applying current pricing to 19

average actual historical volumes and actual annual usage where there was little 20

history. That approach, however, resulted in a net increase to the test year 21

budget of approximately $315,000 due to the significant increase in ammonia 22

prices. We provide our calculations as Exhibit___(KTL-2), Schedule 6. This 23

analysis helps demonstrate the reasonableness of our test year budget. 24

Therefore, except for Sherco 3, we disagree with Ms. Campbell’s 25

recommended adjustment because the adjustment would result in under-26


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31

recovery of emissions chemical costs, given what we now know about 2013 1

chemical pricing. 2

3

As previously mentioned, however, we agree to an adjustment to remove all 4

Sherco 3 emissions and other chemical costs from the test year, resulting in a 5

reduction of $5.1 million on a Total Company basis from the test year. This 6

adjustment is reflected in the Rebuttal Testimony of Ms. Heuer. Table 2 7

below summarizes the Company and Department emissions control chemicals 8

proposals. 9

10

Table 2: 2013 Test Year Emissions Control Chemicals Proposals ($000)

NSPM

Initial Company Budget

Modified Company Budget

Ms. Campbell Recommendation

[TRADE SECRET BEGINS: Sherco Unit 3 - Excluding SMMPA Share $0Other Generating Plants $6,206Total $6,206 TRADE SECRET ENDS]

* Does not include Sherco 3 operations chemicals (approximately $0.6 million) included in Heuer test year 11 adjustment 12 13

Q. DOES THE COMPANY HAVE UPDATED INFORMATION THAT SUPPORTS THE 14

COMPANY’S TEST YEAR CHEMICALS BUDGET, EXCLUDING SHERCO 3? 15

A. Yes. We now have updated pricing information based on executed contracts 16

and purchase orders under which we are currently purchasing chemicals. On 17

average, lime prices declined four percent relative to our budget and mercury 18

sorbent prices declined 14 percent. However, the average price our King, 19

High Bridge, and Riverside plants will pay for ammonia increased 39 percent 20

relative to our test year budget. 21

22


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32

Q. WHAT ARE THE MAIN DRIVERS OF VARIABILITY IN CHEMICAL COSTS? 1

A. There are several dynamics that create uncertainties in forecasting chemical 2

costs. First, actual chemical costs are driven by how much we run the plants. 3

How much we run many plants is now largely determined by the MISO 4

regional market dispatch, meaning that we have less control than we have had 5

in the past over a plant’s generation levels. This impacts our ability to 6

accurately forecast a unit’s generation in a given year. Second, the prices we 7

pay for chemicals are influenced by global supply and demand, which is in 8

turn driven by numerous factors across multiple industries. For example, as 9

noted in our response to Information Request No. DOC-191, recent increases 10

in the global demand for ammonia prompted our supplier to move us from a 11

more stable market fixed price to a supply and demand price based on the 12

market. This will increase our costs for ammonia and introduce greater price 13

volatility. Ms. Campbell provided a copy of our response to DOC-191 as 14

Schedule NAC-1 to her testimony. 15

16

Q. PLEASE EXPLAIN THE MAIN REASONS FOR PAST DEVIATIONS BETWEEN 17

BUDGETED AND ACTUAL CHEMICAL COSTS. 18

A. We identified three primary drivers that contributed to the deviations: 1) 19

calibration of a new mercury control system at the King plant; 2) variability in 20

usage of ammonia at King and High Bridge plants; 3) ammonia pricing; and 4) 21

the Sherco 3 outage for a portion of 2011 and all of 2012. 22

• New Mercury Control System. The mercury sorbent usage assumed for the 23

King plant in the 2011 test year was based on the manufacturer’s 24

recommendations, since the mercury control system was new and we 25

had no past data on which to form an estimate. As we gained 26

experience with the system, however, we were able to optimize it to 27


Larson Rebuttal

33

reduce chemical usage. Thus, actual sorbent usage at King was over 6.2 1

million pounds less than the manufacturer’s estimate that formed the 2

basis of our test year budget. 3

• Ammonia Usage at King Plant. Actual ammonia use at King was 4

approximately 29,000 tons in 2009, which closely matched the 2009 test 5

year budget. Ammonia usage decreased over the 2010 to 2012 period, 6

averaging 21,000 tons, due in part to efficiencies in the pounds of 7

ammonia per MMBtu used to control nitrous oxide (NOx) emissions. 8

• Ammonia Usage at High Bridge. Actual ammonia use at High Bridge has 9

averaged approximately 800 tons over the 2009 to 2012 period, peaking 10

at 1,070 tons in 2012. The 2009 and 2011 test year budgets assumed 11

approximately 2,600 and 1,700 tons, respectively, based on projected 12

plant generation. Actual generation in these years was significantly less 13

than projected, resulting in less ammonia usage than budgeted. 14

• Ammonia Pricing. In 2009 and 2010, our actual price per ton for 15

ammonia was significantly less than our test year budget due to impacts 16

of the weakened economy on the market price of ammonia. For the 17

2011 test year we reduced our budgeted price per ton; however, the 18

actual price per ton in 2011 and 2012 far exceeded the budget. 19

• Sherco Unit 3 Outage. The 2011 test year budgets for lime and mercury 20

sorbent at Sherco 3 assumed normal operation in the test year. With 21

the incident at Sherco 3 and the resulting extended outage, actual 22

chemical costs were $4.8 million less over the 2011 and 2012 period 23

than the assumed test year level on an NSPM basis. 24

25

26


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34

Q. DOES MS. CAMPBELL HAVE A RECOMMENDATION RELATED TO EMISSION 1

CONTROL CHEMICALS FOR FUTURE RATE CASES? 2

A. Yes, she recommends that the Commission require the Company to provide 3

support in the initial case for chemical costs, including volumes and prices, 4

and historical data and competitive bidding, as was provided in the Company’s 5

response to DOC Information Request No. 191. 6

7

Q. DOES THE COMPANY AGREE TO THIS RECOMMENDATION? 8

A. Yes. We agree to provide information similar to that provided in response to 9

DOC-191 in initial filings in future rate cases. 10

11

V. NOBLES WIND PROJECT 12

13


A I will respond to the concerns raised by Ms. Campbell and Mr. Schedin 15

concerning our request to recover the $7.5 million in capital costs for the 16

Nobles project above the estimate presented in Docket No. E002/M-08-1437 17

(RES Eligibility Docket). In that Docket, the Commission determined that 18

Nobles was an eligible energy technology needed to meet the Company’s 19

statutory obligations for renewable generation resources under Minn. Stat. § 20

216B.1691 (RES Statute). The calculation of the $7.5 million was provided in 21

our response to Information Request No. DOC-1139, a copy of which is 22

included with Ms. Campbell’s testimony at Schedule NAC-27. It is the 23

difference between the total cost of the project, which was $489.7 million, and 24

the $482.3 million authorized for recovery by the Commission through the 25

RES Rider. 26

27


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35

Q. PLEASE SUMMARIZE THE ISSUES RAISED BY MS. CAMPBELL AND MR. SCHEDIN, 1

AND YOUR RESPONSE. 2

A. Ms. Campbell’s principal argument is that the Company should not be allowed 3

to recover capital costs in excess of the estimated capital cost presented in the 4

RES Eligibility Docket. Mr. Schedin also argues that cost recovery should be 5

limited to the cost estimate provided in the RES Eligibility Docket. Ms. 6

Campbell states that allowing cost recovery would give the Company a 7

competitive advantage over an Independent Power Producer (IPP) in resource 8

selection. Ms. Campbell is also concerned that the amount of landowner 9

payments may be overstated. I will explain that the Company had express 10

Commission approval to self-provide one-third of its wind projects, and that 11

Nobles was in that one-third category. Therefore, Nobles was not competing 12

with IPP’s. The Company’s RFP that resulted in the selection of Nobles only 13

sought construction projects that the Company would own. Allowing the 14

Company to recover its prudently incurred costs for a project required to meet 15

our renewable energy obligations would instead reflect the reasonable cost of 16

providing that resource. 17

18

Q. PLEASE EXPLAIN WHY NOBLES AND THE OTHER PROJECTS THAT COMPETED 19

WITH NOBLES DID NOT COMPETE WITH IPP ALTERNATIVES. 20

A. The Company filed a Renewable Energy Plan with the Commission on 21

December 10, 2007, pursuant to Minn. Stat. § 216B.1691, stating how it 22

proposed to satisfy its statutory duty to obtain electricity from renewable 23

sources. In the plan, we proposed to acquire roughly a third of the electricity 24

by contracting with IPPs, another third by contracting with community-based 25

energy developers, and the final third from generators owned by the 26

Company. In its June 19, 2009 ORDER APPROVING TARGET PORTFOLIO 27


Larson Rebuttal

36

ALLOCATION WITHIN XCEL’S RENEWABLE ENERGY PLAN, at 9, the 1

Commission approved the proposed portfolio approach, stating in part: 2

The statute directs the Commission to consider Xcel [Energy]’s 3 allocation of resources among C-BED, non C-BED and utility-4 owned projects, and the extent to which this allocation promotes 5 the state’s interest in rural economic development, the reliability of 6 the transmission grid, and minimizing costs to ratepayers. The 7 Commission approves of Xcel [Energy]’s strategy of pursuing wind 8 powered energy sources with a variety of ownership structures. If 9 any one type of structure proves to be more expensive or less 10 reliable than expected, this strategy can be expected to moderate any 11 resulting harm. 12

13

The support for a portfolio approach was also explicitly approved in Ordering 14

Paragraph 1, at 11, which states: 15

The Commission hereby approves the proposal of Northern States 16 Power Company d/b/a Xcel Energy to pursue a portfolio of 17 renewable energy resources, and approves a preliminary target 18 allocation deriving one-third of the portfolio’s electricity from 19 independent power producers, one-third from community-based 20 economic development producers, and one third from utility-21 owned resources. 22

23

In addition to the 2007 Renewable Energy Plan, our proposal to own Nobles 24

was considered by the Commission as part of its approval of our Nobles RES 25

eligibility application. The Commission’s June 10, 2009 (June 10th Order) in 26

the RES Eligibility Docket established Nobles as an eligible energy technology 27

under Minn. Stat. § 216B.1691 (RES Statute). 28

29

Q. UNDER WHICH PART OF THE AUTHORIZED PORTFOLIO DID THE RFP THAT 30

RESULTED IN THE SELECTION OF NOBLES FIT? 31

A. Nobles was planned and approved to be acquired under the one-third of the 32

portfolio to be Company-owned. As stated on page 7 of the Company’s 33


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37

October 5, 2011 Renewable Energy Standard filing in Docket No. E002/M-1

10-1066, the Nobles Wind Project was selected pursuant to the 2007 2

competitive bidding process that evaluated 30 proposals submitted pursuant 3

to an RFP for up to 500 MW of wind energy generation to be owned by the 4

Company. The Nobles Wind Project was planned and constructed as a 201 5

MW wind generator project. 6

7

Q. DOES ALLOWING XCEL ENERGY TO RECOVER ITS ACTUAL, PRUDENT COSTS OF 8

BRINGING NOBLES ON LINE GIVE IT AN ADVANTAGE OVER IPP ALTERNATES? 9

A. No. Only Company-owned alternatives competed under the RFP. There was 10

never an intent (or a requirement by the Commission) to compare the cost of 11

Nobles to the cost of an IPP in the selection process. Rather, the plan was to 12

have a portfolio of each. As a Company-owned project, if the installed cost of 13

Nobles had come in under budget, the total cost included in rates would be 14

the installed cost; an IPP bidder, by contrast, would be under no obligation to 15

reduce the PPA price. In my Direct Testimony, I also discussed other 16

advantages of Company ownership (including $14.8 million of bonus 17

depreciation benefit to customers). That there are both risks and advantages 18

to Company ownership is precisely why the Commission approved a portfolio 19

approach. The selection process for the Nobles project was thus quite 20

different from the process the Commission recently ordered in Docket No. 21

E002/CN-12-1240 for selection of the Company’s next generation addition. 22

23

Q. MS. CAMPBELL STATES THAT THE COMPANY SHOULD NOT BE SELECTED AS 24

THE WINNING BIDDER AND THEN BE ALLOWED TO INCREASE THE COST OF 25

THE PROJECT. IS THAT ARGUMENT APPLICABLE TO THESE FACTS? 26


Larson Rebuttal

38

A. No. The Nobles project was not in competition with any IPP alternative. 1

The Company sought bids only for the construction of a project by other 2

parties that would be owned and operated by the Company. Construction by 3

the Company was not an available alternative in that RFP. Therefore, 4

allowing the Company to recover its reasonable and prudent costs does not 5

disadvantage any of the parties that responded to the RFP. 6

7

Q. WOULD NOBLES HAVE BEEN SELECTED IF THE INCREMENTAL COSTS HAD 8

BEEN IDENTIFIED DURING THE RFP REVIEW PROCESS? 9

A. Yes. The incremental capital costs, which I described in my Direct 10

Testimony, were the Company’s internal costs associated with managing the 11

Nobles Project during construction and the ongoing landowner costs the 12

Company incurs. The Company would have incurred those same project-13

oversight costs during construction and ongoing landowner costs for any of 14

the other alternative projects under consideration in the RFP. Consequently, 15

Nobles’ “advantage” over the other alternatives was unaffected by not 16

including those internal costs in the initial evaluation. 17

18

Q. DOES MS. CAMPBELL QUESTION THE VALIDITY OF ANY OF THE COSTS FOR 19

WHICH RECOVERY IS SOUGHT? 20

A. Yes. Ms. Campbell raises two matters. First, she criticized the Company for 21

not explaining why the current amount for which cost recovery is sought is 22

$7.5 million and not the $13.703 million of capital costs originally budgeted 23

for and determined not eligible for recovery under the RES Rider rate. I agree 24

that we could have better explained the reasons for the reduction in those 25

costs in our filing. While the ALJ Report in our 2010 rate case did not 26

support recovery of the costs because they had not been included in the initial 27


Larson Rebuttal

39

cost estimate, it was my understanding that the ALJ’s Report (paragraphs 407 1

through 416) found the costs to be prudent and necessary costs of bringing 2

the project online. I also addressed in my Direct Testimony the three cost 3

issues that potentially had not been fully resolved in the last rate case: 1) that 4

we are seeking to recover actual costs not the earlier estimated costs; 2) the 5

reason overhead costs increased; and 3) that landowner costs had not been 6

double counted. 7

8

The reason the capital costs are lower than estimated for the 2011 test year is 9

explained in our response to DOC Information Request No. 1139, a copy of 10

which is included with Ms. Campbell’s testimony at Schedule NAC-27. As 11

explained in that response, the Nobles project was not yet complete at the 12

time the estimates of incremental costs for 2011 were made. The project was 13

subsequently completed and went into service at a lower cost. Our 2013 test 14

year reflects that lower actual cost. 15

16

Q. DOES MS. CAMPBELL DISPUTE THE REASONABLENESS OF ANY OF THE CAPITAL 17

COSTS? 18

A. Yes. As I noted above, in the last rate case Ms. Campbell was concerned that 19

we might have double counted landowner costs. The ALJ Report, in Finding 20

409, found that landowner payments had not been double counted. Ms. 21

Campbell has again stated that it is not possible for both O&M and capital 22

landowner costs to have increased in 2011. 23

24

Q. DID BOTH O&M AND CAPITAL LANDOWNER COSTS INCREASE IN 2011? 25

A. Yes. The O&M increase was discussed by Ms. Graika in her Direct 26

Testimony in Docket E002/GR-10-961. On pages 10 and 11, which includes 27


Larson Rebuttal

40

her Table 1, she lists those O&M costs that increased in the 2011 budget 1

compared to then forecasted 2010 O&M expenses. Because Nobles did not 2

become operational until December 2010 (after we filed the 2011 test year 3

rate case), when compared to 2010 expenses, the landowner O&M costs 4

increased in the 2011 budget. 5

6

Q. PLEASE EXPLAIN WHY THERE IS NO DOUBLE COUNTING OF THESE COSTS. 7

A. As explained in my Direct Testimony, landowners at Nobles were provided 8

two payment options. Under option 1, the landowner receives annual rental 9

payments, which are included in O&M. In 2011, Ms. Graika identified O&M 10

expenses for land leases for Grand Meadow and Nobles of $1.226 million on a 11

Total Company basis. In the 2013 test year we have budgeted $1.118 Total 12

Company ($823,000 Minnesota jurisdiction) in O&M for land leases payments 13

for Grand Meadow and Nobles. Under option 2, the landowner received an 14

upfront one-time cash payment. Those payments were capitalized and are 15

depreciated over the life of the lease. More Nobles landowners requested the 16

lump payment option than we had forecasted, which is why the actual capital 17

costs for landowner payments is $2.177 million higher than had been 18

expected. 19

20

Had capitalized landowner payments been lower, annual landowner payments 21

in our O&M budget would be commensurately higher than we presented. 22

The two types of payments are completely separate and there is no double 23

payment of those costs. The fact that 2013 O&M costs are nearly identical to 24

2011 O&M costs provides further evidence that the costs were not overstated 25

in the 2011 budget. 26

27


Larson Rebuttal

41

Q. SHOULD ANY ADJUSTMENT BE MADE TO THE COMPANY’S REVENUE 1

REQUIREMENT FOR NOBLES? 2

A. No. The project was undertaken with express Commission approval, to meet 3

a statutory obligation to provide electricity service using renewable energy. 4

The additional capital costs were incurred to bring on line a safe and reliable 5

source of renewable energy, consistent with our Renewable Energy Plan and 6

the RES Eligibility Docket. The costs of Nobles are prudent and necessary 7

costs of providing service. 8

9

Q. CLEARLY SOME PARTIES HAVE REVIEWED THE SAME FACTS AND COME TO A 10

DIFFERENT CONCLUSION. IS THERE AN ALTERNATIVE SOLUTION TO FULL 11

DISALLOWANCE? 12

A. If the Commission does not believe the Company should get full recovery of 13

the $7.5 million of additional costs, then it should look for an alternative other 14

than full disallowance. The Commission could consider, for example, the 15

treatment of investment made in cancelled plant, where the utility recovers a 16

return of (i.e., depreciation) but not a return on its investment over a 17

reasonable period of time, such as 10 years. Ms. Heuer provides an illustrative 18

calculation of the impact of such a Commission ruling in her Rebuttal 19

Testimony. 20

21

VI. OTHER ISSUES 22

23

A. Third Party Transmission Revenues and Expenses 24

Q. WHAT RECOMMENDATIONS WERE MADE REGARDING THE COMPANY’S 25

PROPOSED TRANSMISSION EXPENSE AND REVENUE TRACKER? 26


Larson Rebuttal

42

A. Ms. Campbell and ICI witness Mr. Glahn recommended that the Company’s 1

proposed tracker be denied. Ms. Campbell expressed concern that availability 2

of a tracker mechanism would reduce the Company’s incentive to minimize 3

costs, and raised other issues. Mr. Glahn is concerned about a piecemeal or 4

single-issue approach to ratemaking. 5

6

Q. WHAT IS THE COMPANY’S RESPONSE TO THESE RECOMMENDATIONS? 7

A. Our goal in proposing the tracker for third party transmission expenses and 8

revenues was to more accurately capture actual expenses and revenues, 9

recognizing that certain cost and revenue items are variable from year to year 10

and largely out of the Company’s control. We continue to believe that a 11

tracker mechanism may be the best way to ensure that rates reflect the most 12

accurate assessment of these expenses and revenues. However, for purposes 13

of resolving this case, we agree to withdraw the tracker from consideration. 14

We will continue to evaluate this issue for possible inclusion in a future case. 15

16

B. Other Revenue 17

Q. WHAT ISSUE DOES MS. CAMPBELL RAISE WITH RESPECT TO THE COMPANY’S 18

TEST YEAR OTHER REVENUE? 19

A. Ms. Campbell noted that NSPM received revenue in 2012 that was not 20

explained in detail in our response to Information Request DOC-1141. Ms. 21

Campbell proposes to make an adjustment to the test year Other Revenue 22

based on a three year historic average of revenues, and questions why the 23

specific 2012 revenue was not returned to ratepayers. Ms. Stitt discusses the 24

Company’s recommended adjustments to Ms. Campbell’s historic average 25

calculation in her Rebuttal Testimony. My testimony addresses the 26


Larson Rebuttal

43

Transmission Service Transfer Agreement cited by Ms. Campbell, the source 1

of the additional one-time 2012 revenue. 2

3

Q. PLEASE DESCRIBE THE AGREEMENT. 4

A. The transaction is discussed in detail in our supplemental response to DOC-5

1141, submitted on March 20, 2011. A copy of our Trade Secret supplemental 6

response to DOC-1141 is provided as Exhibit ___(KTL-2), Schedule 7 to my 7

testimony. The revenues were related to a one-time transmission transaction. 8

As I understand, wholesale transmission revenues and costs are included in 9

base rates, so the revenues were not eligible for Fuel Clause treatment, for 10

example. Ms. Stitt’s proposed update to Other Revenues reduces the 2013 11

revenue requirement and returns to customers a portion of the one-time 2012 12

transmission revenue. 13

14

C. Costs of Wind Integration 15

Q. DOES XCEL LARGE INDUSTRIALS WITNESS MR. JEFFRY POLLOCK MAKE A 16

RECOMMENDATION RELATED TO THE COSTS OF WIND INTEGRATION? 17

A. Yes. Mr. Pollock is concerned that increasing amounts of wind generation on 18

the NSP System are resulting in higher variable costs to maintain system 19

reliability. He states that without an in-depth study, it is difficult to assess all 20

of the impacts of wind integration, including the cost impacts on the 21

Company’s other generating resources. Thus, he recommends that the 22

Commission require the Company in its next rate case filing to include a study 23

quantifying the operational and cost impacts of integrating both current and 24

future wind resources on its system. 25

26

Q. WHAT IS THE COMPANY’S RESPONSE TO THIS RECOMMENDATION? 27


Larson Rebuttal

44

A. The studies and reports cited by Mr. Pollock and attached to his testimony 1

were performed to evaluate the impact of integrating wind generation 2

resources on all three Xcel Energy operating company systems (the NSP 3

System, PSCo and SPS). Each of these systems faces very different 4

operational circumstances. For example, the detailed study of the PSCo 5

system (Schedule 18 to Mr. Pollock’s testimony) reflects the specific 6

challenges facing PSCo, namely that the PSCo system and balancing authority 7

is bordered on the east by the DC ties to the Eastern Interconnection, and on 8

the west by the Western Area Power Administration system and the Rocky 9

Mountains. Thus, the PSCo system is basically an electrical peninsula with 10

relatively weak transmission interconnections to other systems. There is also 11

no organized wholesale energy market in the Western Interconnection to 12

perform joint dispatch optimization, which can mitigate integration costs and 13

operational impacts due to variable resources. As such, the non-wind 14

generation resources on the PSCo system may be affected over time if wind 15

generation penetration continues to increase, because fossil generation directly 16

connected to the PSCo system must perform almost all the balancing of 17

variations in generation and loads on that system. 18

19

By contrast, the NSP System is the Xcel Energy operating company system 20

most able to integrate wind generation resources because of: 21

• the relatively strong existing transmission network, which will be 22

augmented by construction of the CapX2020 Group 1 projects and 23

other regional transmission upgrades; 24

• the availability of transmission service under a regional tariff; and 25

• the existence of the MISO day-ahead and real-time energy and ancillary 26

services markets. 27


Larson Rebuttal

45

1

These features – in particular the MISO markets – mean that fossil generation 2

on the NSP System faces significantly less “cycling” to respond to variations 3

from wind generation. Specifically, generation resources throughout the 4

MISO regional balancing authority respond every five minutes to the 5

variations in output by wind generation located within the NSP System local 6

balancing authority. 7

8

In addition, the Xcel Energy operating companies have worked with the 9

National Center for Atmospheric Research and Global Weather Corporation 10

to develop much more sophisticated systems to predict changes in wind 11

generation output. This ability to accurately anticipate the wind resource 12

production allows more efficient system dispatch by reducing the amount of 13

backup generation held on standby. A significant result of this is reduced 14

on/off “cycling” impacts and reduced costs associated with unit commitment. 15

In MISO this residual unit commitment cost is manifest as Revenue 16

Sufficiency Guarantee (RSG) charges, which are mitigated by the better 17

forecasts. 18

19

Q. WERE YOU PERSONALLY AWARE OF THE JULY 2010 PRESENTATION BY GENE 20

DANNEMAN OF XCEL ENERGY DISCUSSED IN MR. POLLOCK’S TESTIMONY? 21

A. No. As the Senior VP of Operations, and in my prior role as Vice President 22

and Chief Energy Supply Officer, I was aware that Energy Supply personnel 23

were evaluating the impacts of wind generation on the three operating 24

company systems, and the potential for increased “cycling” issues. I was not 25

personally aware of the July 2010 “Regulatory Briefing” presentation by Mr. 26

Danneman. 27


Larson Rebuttal

46

1

Q. DOES THE COMPANY OPPOSE MR. POLLOCK’S PROPOSAL FOR A STUDY 2

QUANTIFYING THE IMPACT OF ADDITIONAL WIND GENERATION RESOURCES 3

ON THE NSP SYSTEM? 4

A. No. It is important to remember, however, that the wind generation 5

resources being added to the NSP System are largely mandated by Minnesota’s 6

Renewable Energy Objective (REO) requirements, which require the 7

Company to serve 30 percent of its retail energy sales in Minnesota with 8

renewable energy by 2020. The Company is planning to continually assess the 9

price of renewable energy resources to comply with this standard and will 10

pursue cost-effective projects as they are identified. 11

12

We agree with XLI that it is appropriate to study the potential operational 13

impacts of that additional wind generation, but believe the study should be 14

considered as part of our 2014 Resource Plan, to be filed in February 2014, 15

rather than the 2014 test year rate case, for two reasons. First, the 16

Commission order requiring the study would not be issued until early 17

September 2013, and the report probably could not be completed by 18

November 2013, when we file our 2014 test year rate case. Second, 19

submitting the study as part of the Resource Plan would allow the 20

Commission to consider the information as it decides on the size, type and 21

timing of future renewable energy additions needed to comply with the REO 22

requirements. 23

24

The Company would also like to work with XLI regarding the scope of the 25

proposed study. We do not believe a study comparable to the PSCo system 26

study attached to Mr. Pollock’s testimony (Schedule 18) is necessary for the 27


Larson Rebuttal

47

NSP System, given the operational differences I noted. In addition, a less 1

comprehensive study would reduce the cost of the study to ratepayers. 2

3

4

D. Momentary Average Interruption Frequency Index (MAIFI) 5

Q. DOES MCC WITNESS MR. SCHEDIN MAKE A RECOMMENDATION RELATED TO 6

RELIABILITY? 7

A. Yes. Mr. Schedin recommends that the Commission order the Company to 8

bring MAIFI reporting up to the same level of importance for Commercial 9

and Industrial (C&I) customers as SAIDI, SAIFI, and CAIDI with trend lines, 10

improvement goals, management incentives, and C&I customer transparency 11

added. 12

13

Q. WHAT IS THE COMPANY’S RESPONSE TO THIS RECOMMENDATION? 14

A. Providing quality service to our customers is a Company priority. As 15

discussed by Company witness Mr. Michael C. Gersack in his Direct 16

Testimony, overall, our customers are very satisfied with our reliability 17

performance. Currently, the Company provides service quality reporting 18

consistent with the Commission’s requirements. MAIFI is currently reported 19

within our annual service quality filing under the Minnesota Rules. In 20

complying with this reporting requirement, the Company clarified the extent 21

to which it is able to report MAIFI information, given its infrastructure and 22

corresponding ability to track interruptions to this level of detail. 23

24

In Minnesota, we are currently able to report momentary outages experienced 25

at the feeder-level for customers served by SCADA enabled substations, 26

which cover approximately 92% of our retail customers. There are pieces of 27


Larson Rebuttal

48

equipment within the distribution system that can operate (e.g., a field 1

recloser) causing momentary outages to customers; however, we do not have 2

the infrastructure to track these momentary events. 3

4

We continue to review our operations, equipment, and ability to leverage 5

technology, and will expand our SCADA, metering, and other capabilities as 6

they become cost effective and provide corresponding value to our customers. 7

We do not believe it is appropriate to increase MAIFI reporting at this time 8

beyond our current MAIFI reporting capabilities, as reported within our 9

annual service quality filing. 10

11

Q. WHAT WOULD BE NEEDED FOR THE COMPANY TO EXPAND ITS MAIFI 12

REPORTING CAPABILITIES? 13

A. In order to track MAIFI for all customers and momentary events, as proposed 14

by Mr. Schedin, we would need to install new metering and communication 15

infrastructure on the Company’s system. The costs of these upgrades to our 16

infrastructure would be substantial, currently estimated at approximately $130 17

million for the meter upgrades alone. This preliminary estimate does not 18

include any of the costs associated with the information system changes that 19

would be required to actually use and process this data. 20

21

VII. SUMMARY AND RECOMMENDATIONS 22

23

Q. PLEASE SUMMARIZE YOUR TESTIMONY AND RECOMMENDATIONS. 24

A. The Company’s proposals strive to effectively balance the various interests 25

represented in the case. Our Sherco 3 proposal is supported by the expected 26

return to service of Sherco 3 in third quarter 2013, the investments we are 27


Larson Rebuttal

49

making to ensure the plant operates safely and reliably when it comes back on-1

line, and the isolation of reimbursable costs from the test year. Our 2

emissions chemicals proposal reflects the costs we expect to incur in the test 3

year at current prices. Our capital projects proposal reflects realistic 4

assumptions about the projects that will be completed in 2013 and is 5

supported by our rigorous project management procedures and demonstrated 6

overall performance in delivering projects on schedule. Our proposal for 7

Nobles reflects our cost-based utility ownership of that project, and is 8

consistent with Commission orders. 9

10

I recommend the Commission approve the 2013 Operations capital and O&M 11

budgets, as modified by our proposals. I have shown that our modified 12

budgets are an accurate representation of the costs we incur to provide safe, 13

reliable, and clean energy. These costs are necessary to continue to deliver 14

high-quality service to our customers, both now and over the long term. 15

16

Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY? 17

A. Yes, it does. 18

414 Nicollet Mall Minneapolis, Minnesota 55401

PUBLIC DOCUMENT

TRADE SECRET DATA EXCISED November 7, 2012

—Via Electronic Filing— Burl W. Haar Executive Secretary Minnesota Public Utilities Commission 121 7th Place East, Suite 350 St. Paul, MN 55101 RE: SHERCO UNIT 3 RESTORATION UPDATE

DECEMBER 2011 FUEL CLAUSE ADJUSTMENT DOCKET NO. E002/M-11-1173

Dear Dr. Haar: Northern States Power Company, doing business as Xcel Energy, provides this update to the Minnesota Public Utilities Commission on restoration activities at the Sherburne County Generating Station Unit 3 after the event that occurred on November 19, 2011. In our December 6, 2011 letter in this docket, we committed to provide periodic updates to the Commission. In this update we discuss our actions to date and the estimated replacement power costs. Portions of the information provided in this update are considered trade secret data pursuant to Minn. Stat. § 13.37 and have been marked accordingly. We maintain the confidentiality of this data, which has independent economic value from not being generally known or accessibly by proper means by others who could obtain economic value from its disclosure. ACTIONS TO DATE As discussed in our May 10, 2012 update in this docket, we developed a response plan the day after the event. Our response plan included the following three phases:

• Phase 1: Documentation and Evidence Collection • Phase 2: Clean up, Disassembly, and Damage Assessment

Northern States Power Company

Docket No. E002/GR-12-961 Exhibit___(KTL-2), Schedule 1 Page 1 of 4

• Phase 3: Repair and Restoration We have now largely completed Phases 1 and 2, and continue to make very good progress in Phase 3. STATUS OF COMPONENT REPAIRS AND ESTIMATED RETURN TO SERVICE Below we provide an update on the following major components of Sherco 3 that were directly impacted by the event:

• The high pressure (HP) turbine and the intermediate pressure (IP) turbine: The repair of the High Pressure (HP) and Intermediate Pressure (IP) turbine sections is progressing well. The repaired IP turbine rotor has been returned to the Sherco Plant site. We anticipate return of the repaired HP turbine rotor in mid-November 2012.

• The generator/rotor and stator: The Original Equipment Manufacturer (OEM) continues to make repairs on the Generator Rotor including fabrication of a stub-shaft to repair the Generator-to-Exciter portion of the assembly. We anticipate the repaired Generator Rotor will be returned to the Sherco plant in January 2013. We are also continuing the on-site restacking of the Generator Stator and anticipate lowering the Generator Stator to its horizontal position in December 2012.

• The exciter:

The off-site fabrication of the Exciter cabinet is in-progress. The rewind of the Exciter rotor and stator are also in-progress. We anticipate return of the Exciter to the Sherco Plant site in January 2013.

• The condenser: The condenser repair (re-tubing) is in the final stages of testing and closeout activities. Following the return of components from off-site repair facilities, and as on-site repairs are completed, unit restoration and reassembly will occur. We anticipate the majority of reassembly activities to occur between mid-December 2012 and early March 2013. Reassembly will be followed by systems start-up, commissioning and testing to verify operational readiness prior to unit restart and return to service. While many repair and restoration activities have yet to be completed, and the preliminary schedule could change, our restoration plan targets Sherco 3 returning to service sometime around the end of the first quarter of 2013.



REPLACEMENT POWER COSTS AND CORRECTED ESTIMATING PROCESS The outage of the Sherco 3 unit has required the Company to replace that generation with other resources, either by dispatching other NSP System units or purchasing in the MISO energy market. Xcel Energy offers our base load coal units, including Sherco 3, in the MISO market as “Must Run” facilities. This means that regardless of whether or not the cost to run the unit exceeds the MISO market locational marginal price (LMP), it is assumed the unit will be online at some level at all times. This is because baseload units like Sherco 3 (and our nuclear plants) are not designed to be entirely removed from service once they are on-line, and there are limitations on how much we can change the output of an individual generator between hours without potentially damaging the unit. We manage the output of the units to take advantage of lower cost replacement energy when possible, while seeking to avoid higher O&M costs or unplanned outages (and resulting replacement energy costs) that could occur if the baseload units are forced to run in a manner inconsistent with their design parameters. We calculate our replacement energy cost for our Must Run units by taking the difference between the MISO hourly LMP price and the average hourly cost it takes to run the unit at the expected load for that hour. Historically, we reported zero outage costs in cases where our costs to run the specific unit would have exceeded the LMP price. In other words, we did not take a credit when LMP prices were below the cost of the specific unit and the Company was actually saving costs to ratepayers by having the unit offline. For example if a unit cost $15/Mwh and the LMP for that hour was $10/Mwh, there would technically be a $5/Mwh benefit to our ratepayers by not running the unit. However, instead of recognizing it as a $5/Mwh credit when calculating our replacement energy costs for that hour, we assigned a benefit of zero. In order to better align our forecast and our actual costs, as well estimate the real impact to ratepayers, we have now changed our calculation methodology for estimating replacement power costs resulting from an outage. We will now recognize the cost credits in these situations as we believe this is the correct way to calculate the true replacement power costs. For example, in hours where the MISO LMP was below the production cost at Sherco 3, we will reflect the energy cost savings resulting from the fact Sherco 3 was entirely off-line. To implement this revision, we will need to revise its future monthly FCA reports, which calculate outage costs. We also plan to file revised calculations of outage costs for July 2011 to June 2012 in our 2011-12 AAA report filed September 1, 2012, to reflect the new methodology; and updated calculations in each our monthly FCA report dockets filed since July 1, 2012. Using the above described revised estimation methodology, we currently estimate the following replacement power costs related to the Sherco 3 outage:



[TRADE SECRET BEGINS Total Reported Outage Costs1 (November 2011-August 2012): Total Forecasted Costs (September 2012 - March 2013): TRADE SECRET ENDS] Total Estimated Outage Costs (November 2011- March 2013): $23.2 million The majority of the costs associated with the Sherco 3 outage occurred in May through August 2012. These costs were higher than we originally forecasted due to high loads from the unusually hot summer weather and the associated higher LMP prices. In the months of November 2011 through April 2012, where our monthly Sherco 3 unit costs would have exceeded the monthly MISO LMP price, use of the more correct replacement cost estimation process results in a [TRADE SECRET BEGINS TRADE SECRET ENDS] benefit to ratepayers rather than a zero cost impact. We note that the current replacement power cost estimate for September 2012 to March 2013 is subject to change, based upon natural gas commodity fuel and MISO electricity market conditions.

CONCLUSION

We appreciate the opportunity to update the Commission on our work to restore Sherco 3 to service. We will continue to provide periodic updates to the Commission as our work continues and more information is available. Please contact me at [email protected] or (612) 215-4593 if there are any questions regarding this update. Sincerely, /s/ CHRISTOPHER B. CLARK REGIONAL VICE PRESIDENT RATES & REGULATORY AFFAIRS ENCLOSURES c: Service List

1 Total costs reported to the Commission in prior FCA filings, adjusted to reflect the new methodology.



mailto:[email protected]

414 Nicollet Mall Minneapolis, MN 55401

PUBLIC DOCUMENT TRADE SECRET DATA EXCISED

February 19, 2013 —Via Electronic Filing—

Burl W. Haar Executive Secretary Minnesota Public Utilities Commission 121 7th Place East, Suite 350 St. Paul, MN 55101 RE: SHERCO UNIT 3 RESTORATION UPDATE

DOCKET NO. E002/AA-11-1173 Dear Dr. Haar: Northern States Power Company, doing business as Xcel Energy, provides this update to the Minnesota Public Utilities Commission on restoration activities at the Sherburne County Generating Station Unit 3 after the event that occurred on November 19, 2011. In our December 6, 2011 letter in this docket, we committed to provide periodic updates to the Commission. We provide our update in the following sections:

• Overview, discussing the scope of the repair work to date and providing updated information on the expected return-to-service timeframe;

• Restoration Project Details, discussing four specific repair activities that illustrate the size, scope, and complexity of the project;

• Progress Update by Major Component, providing a status summary and completion percentage for each major component affected by the event; and

• Replacement Power Costs, providing estimated replacement power costs through March 2013.

Portions of the information provided in this update are considered trade secret data pursuant to Minn. Stat. § 13.37 and have been marked accordingly. We maintain the confidentiality of this data, which has independent economic value from not being generally known or accessible by proper means by others who could obtain economic value from its disclosure.



A. Overview In previous updates in this docket, we identified three phases of work for the Sherco 3 restoration project:

• Phase 1: Documentation and Evidence Collection • Phase 2: Clean up, Disassembly, and Damage Assessment • Phase 3: Repair and Restoration

Phases 1 and 2 are complete. Phase 3 repair and restoration activities are well underway, and many individual projects have been completed. Later in this report, we provide updates to the information in our November 7, 2012 filing on the status of each of the major components affected by the event. As we are now well into the repair and restoration phase and have gained additional knowledge and experience, we believe it would be helpful at this point to provide an overview of the process to date. Providing this additional information may be helpful as this is the largest unit restoration that we have ever performed, and industry-wide, there are no equivalent restoration projects against which it can be compared. We also provide in the next section a description of some of the repair activities that are underway or have been completed, illustrating some of the complexities of this project. Our restoration strategy has been to ensure that the unit will return to reliable and safe service for long-term operation. We have focused our efforts on minimizing temporary repairs that may serve to speed the return of the unit to service, but would ultimately require additional future repairs. Throughout this process, we have continued to develop repair solutions to avoid the cost and schedule implications of complete replacement of the turbine and generator components, while at the same time ensuring the unit will be restored to pre-event conditions. Our assessment of the schedule, costs, and scope of repair work supports our initial decision to repair Sherco 3, as we expect to bring this unit back on line well in advance of the projected return-to-service had we placed orders for all new steam turbine generator components immediately following the event. As with any large, complex project, we have updated our initial schedule as we have learned more about the extent of the damage and the scope and nature of the necessary repairs. In our last update to the Commission, we reported that we expected Sherco 3 to return to service by the end of first quarter 2013. However, while we expect Unit 3 to return-to-service in 2013, based on current information, the return-to-service date for Sherco 3 will be delayed beyond first quarter 2013.

2




The most significant factor contributing to this delay is the additional damage discovered during the repair process itself. While the initial Phase 2 damage assessment was completed during the summer of 2012, we were not able to schedule many of the repairs until months later because contractor shop space and personnel were unavailable to begin repairs immediately. In many instances, it was during the actual repair process that the extent of the damage became fully known as we gained access to hidden layers of equipment and structures that could not be observed during the initial damage assessment. For many of the repairs, both at offsite repair facilities and at the plant, the damage was more extensive and the repair work more involved than initially anticipated. In addition, many of the techniques required to repair various components were not known in the early phases of the project and, in some cases, had to be developed during the repair process. Likewise, there is no equivalent restoration project that could be used as a roadmap for this project. The unique nature and extent of the damage resulting from the event meant there was limited industry information to provide guidance on expected repair cycle times. As such, expectations could not be validated against prior industry experience. Because we are still in the process of performing repairs and certain components being repaired offsite have yet to be returned to the plant, we currently do not have a specific return-to-service date. [TRADE SECRET BEGINS TRADE SECRET ENDS] Once the remaining major components are returned to the plant, we will be at a point in the process similar to where we would be after a major overhaul or when preparing to start up and commission a new generating unit. At that time, we will have more specific information, will be able to reassess the remaining restoration, reassembly, and start-up work, and expect to provide an updated return-to-service date. We will file our next update with the Commission in April to provide this updated information. B. Restoration Project Details In this section, we discuss four specific repair activities that illustrate the size, scope, and complexity of the Sherco 3 restoration project.

• Generator Stator Restack This project was completed at of the end of January 2013, which was later than the October 2012 date originally anticipated. We had to complete significant portions of the process twice due to alignment issues that occurred during the first restack. This

3



restacking and alignment work was challenging due to the limited industry experience for generators of similar design and size, or extent of damage, as Sherco 3. Restacking the generator stator required first lifting and rotating the generator from its usual horizontal position to a vertical position. It took several weeks of planning and preparation and about two weeks to set up the equipment necessary for the lifting process. The actual lift took about two days.

This is the generator stator being lifted to a vertical position for re-stacking.

Once the generator was in its vertical position, there were two shifts of workers inside the generator each day for approximately seven weeks, rebuilding the core of the machine by stacking approximately 400,000 thin pieces of steel plate segments by hand, one on top of another like bricks in a circle. After restacking of the steel plates was complete, the generator (now weighing about 390 tons) was lifted and rotated back to the horizontal position. Then, copper stator bars were slid into the 24-foot long by 1¾-inch wide slots formed by the steel plates.

4



This photo shows the internal stacking of the generator stator, as well as the slots

where the copper bars need to fit, after it was rotated to a vertical position. After we completed our initial restacking process, we determined there was an alignment problem between the stator bars and the steel plates. Although there were alignment checks performed throughout the entire restacking process, the room for error was approximately 1/32 inch, and the contractor was unable to get the proper fit needed to complete the reassembly process. As a result, we again lifted and rotated the generator back to the vertical position, removed the majority of the steel plates, and repeated the restack, performing additional alignment checks throughout the process. At the conclusion of this second stacking process, the stator bars fit into the slots with the proper clearances and tolerances.

• High Pressure/Intermediate Pressure Turbine Rotors We knew from our initial assessment that the newly installed HP/IP turbine rotors sustained significant damage, and were therefore sent offsite for repair. However, we did not know the extent of the damage or how long the process would take until the complete disassembly, assessment, engineering, and repair process was completed. In the case of these rotors, the turbine blades were not damaged, but the shrouds – the metal bands encircling the ends of turbine blades – sustained significant damage. In contrast to the low pressure turbine rotors, where the blades can be easily removed and replaced if necessary, the blades in the HP and IP turbine rotors are integral with

5



the shrouds, thus the shroud cannot be easily removed and replaced. As a result, the repair technique selected to repair the blade shrouds was to remove damaged material by careful machining until only clean (undamaged) material remained. The HP/IP rotors were not able to be repaired to a like-new condition due to the amount of material that had to be removed to clear all damaged material from the components. The manufacturer of the rotors established limits regarding how much material could be removed. Removal of material beyond these limits would result in unacceptably high stress levels during operation. After removing material to these limits on several sections of the HP and IP rotors, it was determined the manufacturer could not remove all the damage. While the damage that remains is relatively minor and the rotors can be safely operated, these rotors will require monitoring and detailed inspections on a 2½-year inspection interval instead of the expected 10-year interval. Plans are being developed to purchase new rotors, expected to be covered by insurance, which would restore the unit to the 10-year inspection interval.

• Onsite Turbine Repairs and Machining The onsite turbine repairs consist of detailed visual non-destructive examinations, dimensional inspections, engineering assessments, detailed repair plans, welding, and machining. The type of damage on the turbines was more severe and went deeper than expected, and thus required considerably more time to perform each of the activities than anticipated. For example, one type of damage observed on the equipment was machine surface self-welding. This phenomenon occurred on many flat and curved surfaces where machine parts are in contact with each other. The horizontal joining surfaces are the most obvious location where this phenomenon was observed, but it was also found under the feet of the turbine after the turbines had been completely lifted from their foundations to replace the damaged foundation system, which was not expected. This damage required repairs to restore the machined surfaces to their proper form, fit, and function, and the additional damage found meant additional time was required to complete the work. In addition, this was not routine maintenance type work, but instead required innovative engineering and technology development and specialized repair technique creation as the details of the damage were discovered. One of the techniques used to repair the damage to the machined horizontal joint surfaces of the LP turbines required the use of large laser guided machine tools that were custom designed and fitted for the Sherco 3 turbines. The installation of these tools and procedures to apply them required extensive engineering and set-up time that occurred as the work progressed.

6



This is one of specialty tools brought in to repair the surfaces of the turbines.

The mounted laser on the right guides the tool.

• Front and Mid Standards The front and mid-standards support the HP and IP turbines. These standards could not be removed for inspections until all the other turbine components were removed. The high energy piping systems had to be temporarily restrained and then cut to allow the turbine shells to be removed. After the standards were exposed, more damage became apparent. The standards were then sent offsite for a thorough evaluation and assessment with repair recommendations. The examinations and assessments revealed additional damage. After the repair recommendations were approved, the repair work was completed. However, during the repairs additional damage was noted, potentially caused by the residual stresses in the standards as a result of the event. We note that this process, assessment, and repair requirements were similar for the generator end shields. Specialized repair strategies and techniques had to be developed to restore the standards and the generator end shield to serviceable condition. C. Progress Update by Major Component Attachment A is a visual summary of our progress to date by component. Below we provide a summary of the status of each major component.

7



• Generator Rotor and Stator (65% complete) As discussed above, the generator stator was repaired (restacked) on site. The stator restacking is complete and the generator stator has been returned to a horizontal position. This portion of the project was completed at the end of January 2013 and the stator bars have now all been successfully installed. The generator rotor was repaired offsite. The windings have been installed in the rotor, including the retaining rings. The final machining steps are complete and high speed balancing is complete. The generator rotor will be returned to the plant site in the next two weeks.

• High Pressure and Intermediate/Reheat Turbines (75% complete) The high pressure and reheat steam turbines outer casings were repaired onsite. The internal parts were repaired offsite. As reported in our in our last update, we expected the repaired high pressure turbine rotor to be returned to the plant in November 2012 and that timeline was met. There was additional related repair work for both HP and IP outer shells that was performed on-site. This was final surface machining work that was required to insure proper fit of the components during reassembly. This additional machining work will result in completion of the repairs in February 2013 instead of December 2012 as we had previously anticipated. The reheat steam turbine repairs are nearly complete and all reheat turbine components are expected to return to the site in February.

• Low Pressure Turbines (LP-A and LP-B) (65% complete) The low pressure turbines sustained substantially more damage than the other turbine sections during the event. Similar to the other turbine sections, some major components of these turbines were repaired on site while some were sent offsite for repairs. The onsite repairs are nearing completion. However, due to the extent of the damage to the LP turbine components there was additional repair time required. Repairs for these components are anticipated to be completed in April 2013 rather than January 2013, as previously reported. Minor onsite repairs will continue through unit assembly as additional necessary work is identified as the parts are fully assembled with each other.

8



The offsite repairs are also nearing completion and most critical turbine parts are expected to be returned to the site in April. The low pressure rotors are the most significant components that are currently offsite, and they are expected to be returned to the plant in late March.

These are the damaged LP turbine blades after the event.

These blades should look like the new blade in the below photo.

A new LP turbine blade.

• Main Condenser (95% complete) The on-site repair (re-tubing) of the main condenser is complete. Final testing will be performed during system start-up and commissioning. This repair was completed according to our previous schedule and expectations.

9




• Generator Exciter (55% complete) The off-site repair of the generator exciter is complete. While the exciter enclosures and cabinet repairs were completed as scheduled, additional time will be required for the reassembly of the exciter. We anticipate return of the exciter to the plant for assembly in February, followed by installation on the unit.

• Balance of Plant Systems and Components As described in our previous updates, many miscellaneous components and plant systems were affected by the steam turbine failure. All balance of plant systems and components have been evaluated for event-related damage, and those that required replacement or repair are in progress. D. Replacement Power Costs

Using the estimation methodology we discussed in our November 7, 2012 update in this docket, the table below provides our estimated replacement power costs related to the Sherco 3 outage. The cost estimate for February and March 2013 is subject to change, based upon natural gas commodity fuel and MISO electricity market conditions.

Total Reported Outage Costs (November 2011- January 2013)

[TRADE SECRET BEGINS

Total Forecasted Costs (February 2013 - March 2013

TRADE SECRET ENDS]

Total Estimated Outage Costs (November 2011- March 2013) $33.2 million

We also note that the MISO resource adequacy tariff requirements do not require the Company to procure replacement capacity while the Sherco 3 facility is on extended outage.

CONCLUSION We appreciate the opportunity to update the Commission on our work to restore Sherco 3 to service. We will continue to provide periodic updates to the Commission, with our next update expected to be filed in April. Please contact me at [email protected] or (612) 215-4593 if there are any questions regarding this update.

10



mailto:[email protected]

Sincerely, /s/ CHRISTOPHER B. CLARK REGIONAL VICE PRESIDENT RATES AND REGULATORY AFFAIRS Enclosures c: Service List

11



Mid Standard

& Thrust Bearing

text

Front

Standard

HP Turbine

Cross Over

LP-A Turbine LP – B TurbineGenerator

Exciter

IP Turbine

Xcel Energy

SHERCO 3

Restoration Project

Update: Feb. 12, 2013

90%

10SHOP REPAIR

WORK

SITE REPAIR

WORK

ASSEMBLY

STARTUP

N/A

5% - Fixators Set

Not Started

100% Complete

100% Complete

0% - Waiting for standards

Not Started

Notes:

1. BOP Mech/Electrical/Controls/Instrumentation/New Parts orders

work not represented here, however, all is on track to support the re-

assembly and startup of unit.

99%

98%

2% - Waiting for standards

Not Started

90% Rotors/Diaphragms

5% - LEH’s set and aligned

Not Started

90% Rotors/Diaphragms

5% - LEH’s set and aligned

Not Started

100% Restack Complete

5% Rewind

2% - baseplate set

Not Started

99% Stator/Frame

100% Rectifiers

100% – Doghouse Body

95% – Doghouse Electrical

0% - Alterrex Assembly

2% - baseplate set

Not Started

75% Generator End Shields

95% Generator Rotor

Percent

Complete

Standards HP Turbine IP Turbine LP Turbine - A LP Turbine - B Generator Exciter

71% 75% 73% 67% 65% 68% 58%

99% 95%



Northern States Power Company Docket No. E002/GR-12-961Exhibit__(KTL-2), Schedule 3

Page 1 of 2Sherco Unit 3 Capital Additions ($), 2011-2013

parent description amount11635985 SHC3C BFPT Overspeed Ctrl Repl 14,160 11487928 SHC3C Mill Overhaul Rpl Pulv G 346,637 11487728 SHC3C Mill Overhaul Rpl Pulv G 687,093 11636497 SHC3C Unit 3 Restoration 2,941,961 11487992 SHC3C U3 Cooling Tower Repl 14,568,910

2013 Budget 18,558,760

parent description amount10611309 SHCJ Demin System Replacement 1,589 10637236 SHCJC Coal Yard Computer 4,448 10785670 SHC U3 Repl Ash Silo Mixers 36,171 10785682 SHCJC Recnstr Coal Yard Ditch L 1,202 10785737 SHCJ UJ 57 Belt Conv Gallery H 3,310 10786221 SHC3C 11 Mill Ovrhl-Rpl Pulvzr 13 11074770 SHCJC UJ Yard Scraper Repl 201 (834) 11075097 SHCJC UJ Yard Scraper Repl 201 (831) 11230990 SHC3C U3 Baghouse Bag Repl (170) 11348035 SHC3C Repl Primary Air Heatr B 36 11350828 SHC3C U3 Spray Dryer Chamber L 0 11353257 SHCJC UJ PLC Replacements 102,042 11358567 SHC3C U3 Slaking Water Heating 6,954 11373772 SHC3C U3 2016 Mill OH Repl Pul 6,269 11410368 SHC3C U3 Belt 6 to 7 Chute Rep 27,000 11488125 SHC3C Condenser Dogbone Repl 35,017 11500251 SHC3C Silo CO Detection Syst I 14,265 11532371 SHC3C U3 Generator Bushing Repl 0 11532375 SHC3C U3 Bottom Ash Drains Repl 1,062 11564303 SHC3C Lighting Replacement 72,667 11564305 SHCJC Replace Crane 0 11635985 SHC3C BFPT Overspeed Ctrl Repl 139,102 11348592 SHC3C Boiler Section Repl 2020 178,605 11520377 SHC3C Inst Elevator Fire Contr 99,865 11487736 SHC3C Mill Overhaul Rpl Pulv G 316,427 11217238 SHC3C U3 Backpass Sootblwng Sy 2,607,739 11230990 SHC3C U3 Baghouse Bag Repl 1,664,591 11487746 SHC3C Watr Fill Statn Data Col 71,600

2012 Total 5,388,139

parent description amount10239400 SHC U3 AQCS Computer (59_41) (1,069) 10239410 SHC J - Dumper Positioner Arm (8,820) 10361195 SHC U3 Max 1 DCS and DAI Re 49,927 10510351 SHCJC Purchase of Yard Loader 11 10611143 SHC U3 Install Nox Controls - 0 10611309 SHCJ Demin System Replacement 1,416,336 10611324 SHC3C Unit 3 Landfill Capping - 10634118 SHC3C Mercury Control 78,766 10634130 SHCJC Barn Dust Control West E 932,958 10637223 SHC3C Unit 3 Landfill Cell 3 (15,156) 10637236 SHCJC Coal Yard Computer 5,109,957 10785670 SHC U3 Repl Ash Silo Mixers 953,811 10785682 SHCJC Recnstr Coal Yard Ditch L 61,234 10785737 SHCJ UJ 57 Belt Conv Gallery H 467,842 10785754 SHCJ UJ 51 Belt Conv Gallery H 275,522 10785788 SHC3C U3 CEMS Analyzer Repl 167 10785993 SHC3C 09 Mill Ovrhl-Rpl Pulv G (24) 10786009 SHCJC Ut J Yard Scraper Replac (75,301) 10786157 SHC3C 10 Mill Ovrh-Rpl Plvrzr 299,856 10786221 SHC3C 11 Mill Ovrhl-Rpl Pulvzr 302,445 10939612 SHC3C U3 CTOW Nozzle Repl 62,686


Page 2 of 211074770 SHCJC UJ Yard Scraper Repl 201 1,289,274 11075097 SHCJC UJ Yard Scraper Repl 201 1,284,413 11152576 SHCJC UJ 54 Belt Conv Gallery 2,709 11167548 SHC3C Boiler Heat Flux Sensors - 11214576 SHC3C U3 31-13 CTOW Cell Rebui 200,457 11228141 SHC3C U3 CTOW Cells Repl Louve (41) 11230990 SHC3C U3 Baghouse Bag Repl 2,395,261 11267337 SHC3C U3 Repl 31 & 32 Lime Blo 153,072 11279653 SHCJC UJ Construct Gas Storage 297,294 11348035 SHC3C Repl Primary Air Heatr B 455,152 11348434 SHC3C Replace Condensate Pump 97,436 11350828 SHC3C U3 Spray Dryer Chamber L 480,834 11353257 SHCJC UJ PLC Replacements 2,750,561 11358567 SHC3C U3 Slaking Water Heating 246,392 11360142 SHCJC Repl Super Sucker Truck 261,091 11373772 SHC3C U3 2016 Mill OH Repl Pul 351,175 11387642 SHCJC CESP Stacker Slew Bearin (1,072) 11387646 SHCJC CESP Stacker Truck Assem (957) 11410368 SHC3C U3 Belt 6 to 7 Chute Rep 431,179 11418582 SHC3C U3 Mill Overh Rpl Pulv Gearbx 212,628 11426918 SHC3C U3 Boiler Roof repl 202,375 11426925 SHC3C U3 Repl Road Near U3 Sta 65,974 11426930 SHCJC UJ Purch Heavy Duty Forklift 117,790 11428136 SHCJC Coal Yard Skid Loader 37,187 11439911 SHC3C U3 Ash Transfer Blower R 59,151 11445422 SHC3C U3 Repl Insul FSH Header 42,548 11488125 SHC3C Condenser Dogbone Repl 27,319 11500251 SHC3C Silo CO Detection Syst I 119,964 11532371 SHC3C U3 Generator Bushing Repl 158,798 11532375 SHC3C U3 Bottom Ash Drains Repl 164,336 11564305 SHCJC Replace Crane 99,533

2011 Total 21,912,982

Grand Total 45,859,881

*Note- There is a $156 difference between capital additions on page 1 and page 2 that we were unable to reconcile

Northern States Power Company Docket No. E002/GR-12-961 Exhibit__(KTL-2), Schedule 4

Page 1 of 2

Description of Black Dog Units 2 and 5 Outage (September 2011 - August 2012)

Black Dog Units 2 and 5 were taken out of service on September 23, 2011 for a

planned Black Dog all-unit outage. During this outage, an inspection of the

combustion turbine exhaust cylinder revealed cracking in one of the six struts (strut

#6) supporting the exhaust bearing assembly on Unit 5. Struts provide support for

the exhaust bearing assembly on the combustion turbine. The cracking to the strut

was severe enough to pose significant risk to the equipment and a potential safety

issue to the staff at the plant. No other struts showed an indication of any cracks.

Siemens, as the manufacturer of the turbine, was contracted to perform the repair

according to their approved strut repair welding procedure. Figure 1 below is a

diagram of the strut assembly with the struts numbered.

Figure 1: Strut Assembly Diagram

#6

#5

#4 #3

#2

#1

Because movement of the exhaust bearing assembly can occur during the welding

repair process, we had to perform an alignment of the turbine components to ensure

we would not have a rub of the moving and stationary components (blades, vanes,

Northern States Power Company Docket No. E002/GR-12-961 Exhibit__(KTL-2), Schedule 4

Page 2 of 2 etc.) during unit operations, which could result in significant damage to the

combustion turbine. This required that we open up the combustion turbine casing to

measure and adjust various internal components to ensure proper clearances and

alignment per manufacturer specifications. In doing so, we found the bearing housing

had moved down an additional 1/10th of an inch, which meant we could not realign to

obtain the necessary clearances at the torque tube. This torque tube is the transition

point between the compressor section and turbine section of the combustion turbine.

Inadequate clearances in this area would create a rub at about the mid-span of the

combustion turbine assembly resulting in significant overheating and bowing of the

machine. Siemens concluded that we could not make further adjustments or repairs

or operate the unit without causing significant damage to the unit.

The unit was placed in a non-operational mode until the strut assembly and exhaust

could be replaced. We immediately entered into discussions with Siemens and other

vendors to obtain potential solutions to the problem, as well as pricing and

turnaround time. It was determined that Siemens had the only viable solution and

quickest turnaround to remedy this issue. As such, we signed a contract with Siemens

for the replacement. The unit returned to service slightly ahead of schedule on

August 9, 2012.

Non Public Document – Contains Trade Secret Data Public Document – Trade Secret Data Excised Public Document Xcel Energy Docket No.: E002/GR-12-961 Response To: Department of Commerce Information Request No. 192Requestor: Nancy Campbell, Dale Lusti & Angela Byrne Date Received: January 8, 2013 CORRECTION _________________________________________________________________

Question: Subject: Energy Supply, Transmission and Distribution Reference: Direct Testimony of Kent T. Larson page 9 and Table 1 A. Please provide capital additions for Energy Supply, Transmission, Distribution

for 2009 actual, 2010 actual, 2009 test year, 2011 test year, 2011 actual, 2012 actual, 2013 test year. Please provide on total company and Minnesota jurisdictional basis, including support for allocator used.

B. Please provide a breakout by capital project and plant for Energy Supply capital

additions for 2013, including brief description of each project, why project is needed, support for estimated cost of the project, impact on depreciation life of the facility and why, and support for in-service date of the project.

C. Please provide a breakout by capital project for Transmission capital additions

for 2013, including brief description of each project, why project is needed, support for estimated cost of the project, impact on depreciation life of the facility and why, and support for in-service date of the project.

D. Please break out capital projects for transmission included in rate case and capital

projects included for transmission recovery rider (TCR) and explain how these two do not overlap.

E. Please provide a breakout by capital project for Distribution capital additions for

2013, including brief description of each project, why project is needed, support for estimated cost of the project, impact on depreciation life of the facility and why, and support for in-service date of the project.

F. Please provide operating and maintenance (O&M) expense for Energy Supply,

Transmission, Distribution for 2009 actual, 2010 actual, 2009 test year, 2011 test year, 2011 actual, 2012 actual, 2013 test year. Please provide on total company



2

and Minnesota jurisdictional basis, including support for allocator used. Please include explanations for the differences between 2012 actual and 2013 test year amounts.

Response: A. Please see Attachment A for the capital additions requested. The Company does

not jurisdictionalize or allocate capital additions. Capital additions are jurisdictionalized and allocated in the revenue requirement calculation process, not at the budgeting stage. A portion of the revenue requirement associated with plant in service would be allocated to NSPW through the Interchange agreement. The 2012 actual capital additions provided in Attachment A differ from what was included in Mr. Larson’s Direct Testimony due to timing and the use of a forecast versus actual data.

B. Please see Attachment B for the list of capital projects for Energy Supply along

with a brief description and justification. Please see our response to Information Request DOC-133 for the impact of additions on depreciable life. The estimated cost and in-service date of projects are determined through the project estimating process. Attachment G includes a summary of the project estimating process along with a checklist that is used to aid in development of project estimates.

C. Please see Attachment C for the list of 2013 Transmission capital additions

greater than $1 million. The projects detailed in Attachment C represent 97.26% (or $320 million) of the $329.1 million total Transmission 2013 capital additions shown in Attachment A. Attachment C includes a brief description, an explanation of the reason that each project is needed and support for the in-service date.

All capital project estimates are to be created in Xcel Energy’s Hard Dollar

estimating software that utilizes a historical actual cost data from previously completed project, with a projected escalation multiplier and is updated frequently. Three levels of project estimates are to be created for each transmission project: Scoping, Appropriation, and Engineering Estimates.

Please see our response to Information Request DOC-133 for the impact of

additions on depreciable life. D. Please see Attachment D for a list showing which of the 2013 Transmission

capital additions greater than $1 million are recovered through the TCR or which are recovered through base rates. Note that each project is listed as being recovered either through the TCR or base rates. There are no projects that are assigned recovery via both mechanisms.



3

E. Please see Attachment E for the list of 2013 Distribution capital additions with a

brief description. See DOC-133 for the impact of additions on depreciable life. This information is also provided in our response to part B of DOC-1107.

F. Please see Attachment F for operating and maintenance (O&M) expenses for

Energy Supply, Transmission, Distribution Operations for 2009 actual, 2010 actual, 2009 test year, 2011 test year, 2011 actual, 2012 preliminary actual, 2013 test year, including explanations for the differences between 2012 actual and 2013 test year amounts.

_________________________________________________________________ CORRECTION Attachment A of our original response to DOC-192 showed an incorrect value for the 2009 Test Year Amount of capital additions for the Distribution function. The $158,589,397 did not reflect a downward adjustment made in the course of developing the 2009 rate case test year. The correct 2009 Test Year amount for Distribution plant additions is $121,800,644. The Distribution Capital Adjustment was discussed Ms. Anne Heuer’s Direct Testimony in Docket No. E002/GR-08-1065 at page 59. The adjustment is summarized in Ms Heuer’s, Schedule 2, page 2 of 2, in Schedule 4a and further detailed in Volume 4 Workpapers in Adjustment A.7. We apologize for not recognizing the error prior to sending the discovery response. Given this correction, and referring to the Direct Testimony of Angela Byrne (Byrne Direct, page 25), our actual versus test-year over/under recovery amounts by year become $5.4 million under for Test Year 2009, $4.7 million under for Test Year 2010, $17.4 million over for Test Year 2011, and $2.2 million under for Test Year 2012. The cumulative net actual versus Test Year amounts for 2009 – 2012 is $5.1 million over. Please see Attachment A – Corrected. Witness: Kent Larson Preparer: Michael Bliss Title: Accounting Analyst Department: Capital Asset Accounting Telephone: 612-330-6216 Preparer: Roger Schluessel Title: Regional Capital Project Director, NSP Department: Engineering and Construction



4

Telephone: 612-330-2939 Preparer: Brad Nelson Title: Transmission Project Manager Department: Transmission Project Management Telephone: 608-789-3623 Preparer: Shannon Forss Title: Manager, Investment Delivery Department: System Planning & Strategy – North Telephone: (651) 229-2261 Preparer: Greg Robinson Title: Manager, O&M and Capital Reporting Department: Financial Forecasting Telephone: 612-215-4631 Preparer: Mary Pope Title: Senior Rate Analyst Department: Revenue Requirements North Telephone: 612-330-6574 Date: January 29, 2013 SUPPLEMENT: March 20, 2013



Northern States Power Company Docket No. E002/GR-12-961Capital Additions Information Request DOC-192Total Company Attachment A - CORRECTED

Page 1 of 1

Capital Additions Energy Supply Transmission Distribution2009 Actual 311,686,430$ 124,505,357$ 116,402,188$ 2010 Actual 573,565,135$ 117,526,242$ 117,063,217$ 2011 Actual 80,112,221$ 164,129,597$ 149,121,465$ 2012 Actual 98,559,665$ 139,084,227$ 129,604,703$

Capital Additions Energy Supply Transmission Distribution2009 Test Year 320,772,248$ 110,052,011$ 121,800,644$ 2011 Test Year 95,746,208$ 162,645,405$ 131,755,109$ 2013 Test Year 92,721,430$ 329,077,436$ 149,744,932$

Over/under recovery2009 (9,085,818)$ 14,453,346$ (5,398,456)$ 2010 252,792,886$ 7,474,231$ (4,737,427)$ 2011 (15,633,987)$ 1,484,192$ 17,366,356$ 2012 2,813,457$ (23,561,177)$ (2,150,406)$

Total 230,886,538$ (149,408)$ 5,080,067$




Page 1 of 1PUBLIC DOCUMENT: TRADE SECRET DATA EXCISED

Emission Control Chemicals Analysis, Excluding Sherco Unit 3 Northern States Power Company - Minnesota

[TRADE SECRET DATA BEGINS:Usage 2009 Actual 2010 Actual 2011 Actual 2012 Actual 2013 Budget Average Usage Usage BasisLime (tons) AS King Plant 13,326 14,118 11,290 16,509 avg of 4 yearsRed Wing Plant 4,676 7,094 4,228 3,099 avg of 4 yearsWilmarth Plant 2,606 2,572 3,908 4,237 avg of 4 yearsMercury Sorbent (lbs)AS King Plant - - 247,360 542,720 2012 ActualAmmonia (tons)AS King Plant 28,850 21,989 20,817 19,819 avg of 4 yearsBlack Dog Plant 781 288 140 91 avg of 4 yearsHigh Bride Plant 747 475 855 1,069 avg of 4 yearsRiverside Plant 105 252 101 356 avg of 4 years

Price per lb/ton 2009 Actual 2010 Actual 2011 Actual 2012 Actual 2013 Budget 2013 Current Pricing

Assumptions LimeAS King Plant 113.30$ 101.00$ 116.64$ 117.00$ Red Wing Plant 113.30$ 101.00$ 126.13$ 131.98$ Wilmarth Plant 113.30$ 101.00$ 119.00$ 87.15$ Mercury SorbentAS King Plant -$ -$ 0.94$ 0.73$ AmmoniaAS King Plant 96.58$ 133.36$ 141.85$ 155.00$ Black Dog Plant 96.58$ 133.36$ 210.00$ 201.39$ High Bride Plant 96.58$ 133.36$ 184.58$ 150.60$ Riverside Plant 96.58$ 133.36$ 193.60$ 150.60$

Overall Cost ($000) 2009 Actual 2010 Actual 2011 Actual 2012 Actual 2013 Budget

2013 Budget- Avg Usage & Current

Pricing DOC

Recommendation Lime *AS King Plant 1,510$ 1,426$ 1,317$ 1,932$ A -$ 2013 TYRed Wing Plant 530$ 729$ 533$ 409$ A 550$ 4 Yr AverageWilmarth Plant 295$ 260$ 309$ 369$ A 308$ 4 Yr AverageMercury Sorbent *AS King Plant -$ -$ 231$ 396$ A 396$ 2012 ActualAmmoniaAS King Plant 2,787$ 2,932$ 2,953$ 3,072$ A 2,936$ 4 Yr AverageBlack Dog Plant 76$ 38$ 29$ 18$ A 40$ 4 Yr AverageHigh Bride Plant 72$ 63$ 96$ 161$ A 98$ 4 Yr AverageRiverside Plant 10$ 34$ 20$ 54$ A 29$ 4 Yr AverageTotal Emission Control Chemicals * 5,279$ 5,482$ 5,490$ 6,412$ 4,359$

2013 Budget - Original ($000)2013 Budget- Avg Usage and Current Pricing ($000)Delta

[TRADE SECRET DATA ENDS]


Non Public Document – Contains Trade Secret Data Public Document – Trade Secret Data Excised Public Document Xcel Energy Docket No.: E002/GR-12-961 Response To: Department of Commerce Information Request No. 1141Requestor: Nancy Campbell, Dale Lusti & Angela Byrne SUPPLEMENT Date Received: January 23, 2013 _________________________________________________________________

Question: Subject: Other Revenue Reference: Xcel’s response to DOC IR 127, Attachment B A. Champion Distribution and Champion Transmission customers are listed as an

Exclusion Item for Other Revenue in Xcel’s response to DOC IR 127 on Attachment B page 4 of 4. Please provide the following regarding this Exclusion Item: (1) Briefly describe these customers. (2) Please explain and support why the Company believe these customers are “non-regulated” for purposes of FERC accounting. (3) Please describe types of services these customers have taken or are taking, including related MW or mWh. (4) Please identify what years Champion Distribution and Champion Transmission has taken service from the Company, including if these customers continue to take service from the Company in 2013. (5) Please provide for 2010 to 2013 the revenues, expenses, and resulting net income from these customers. Please provide on total Company and Minnesota Jurisdictional basis, including appropriate allocator.

B. DOC compared 2010 to 2012 actual Other Operating Revenues provided by Xcel

in response to DOC IR 127, Attachment B to 2013 test year budget Other Operating Revenues found in Workpaper Volume 4, Tab R1-2. Please explain why line item 21 Network Transmission has a 2013 test year budget of only $28.5 million total Company and only $25.1 million for Minnesota (note Minnesota appears to be both Minnesota and Wisconsin jurisdictions without Interchange Agreement exclusion – please confirm this and provide MN Jurisdictional amounts for 2013 to 2010 data) when 2012 actual Network Transmission Revenues in DOC IR 127, Attachment B, page 3 of 4, Line 21 was approximately $55.7 million total




Company and $49.0 million Minnesota. Also 2011 actual Network Transmission Revenue on line 21, Attachment B, page 2 of 4 was approximately $55.8 million total Company and $49.3 million Minnesota.

C. DOC compared 2010 to 2012 actual Other Operating Revenues provided by Xcel

in response to DOC IR 127, Attachment B to 2013 test year budget Other Operating Revenues found in Workpaper Volume 4, Tab R1-2. Please explain why line item 26 “Other” has a 2013 test year budget of only $9.2 million total Company and only $8.8 million for Minnesota (note Minnesota appears to be both Minnesota and Wisconsin jurisdictions without Interchange Agreement exclusion – please confirm this and provide MN Jurisdictional amounts for 2013 to 2010 data) when 2012 actual “Other” on line 28, Attachment B, page 3 of 4 was approximately $20.4 million total Company and $19.3 million Minnesota. Also 2011 actual “Other” on line 27, Attachment B, page 2 of 4 was approximately $10.5 million total Company and $10.2 million Minnesota. Also 2010 actual “Other” on line 27, Attachment B, page 1 of 4 was approximately $12.0 million total Company and $11.6 million Minnesota.

D. For (C) above please provide a breakout of the categories and related revenue

amounts that make-up “Other” for Other Operating Revenue for 2010, 2011, 2012 and 2013.

SUPPLEMENTAL RESPONSE: This supplement provides additional information only to our response to part C of this question. Our original response to DOC-1141 dated February 6, 2013 is not repeated here.

Explanation of a One-Time Payment in 2012 Related to a Transmission Service Transfer Agreement

In our original response to part C, we identified a one-time payment related to a transmission service transfer agreement which shows as the “Other” category of Other Operating Revenue. NSP currently has a number of contractual arrangements with Manitoba Hydro (“MH”) that govern the transfer (purchase or sale) and transmission of energy both north and south. NSP currently has power purchase contracts with MH for 850 MW (500 MW year-round plus 350 MW of summer season Diversity Exchange) that expire in 2015. From 2015-2025, this resource is replaced with contracts totaling 725/675 MW (375 MW summer, 325 winter, plus 350 MW of summer season Seasonal Diversity). In 2021, NSP’s year-round purchase could increase from 375/325 MW to 500/450 MW if MH is successful in constructing additional hydro generation. NSP has transmission reservations and contractual

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PUBLIC DOCUMENT: TRADE SECRET DATA EXCISED commitments with MH in place for southbound transmission, which is sufficient to support these purchases. Conversely, MH has contracts in place for the purchase of capacity and energy from NSP under certain circumstances. MH has rarely called upon purchases under these arrangements as MH generally views these arrangements to be a hedge against the potential for drought conditions. Traditionally, NSP held the northbound transmission reservations from the NSP System to the international border supporting northbound sales. The transmission service reservations were provided by pre-Order No. 888 grandfathered agreements (as part of the bundled power sales arrangements) that provided the right for NSP to use firm transmission capacity, but did not provide for any payment or revenue associated with the transmission reservations. [TRADE SECRET DATA BEGINS:

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PUBLIC DOCUMENT: TRADE SECRET DATA EXCISED TRADE SECRET DATA ENDS] Please note this response contains information the Company considers to be trade secret data as defined by Minn. Stat. §13.37(1)(b). The information derives an independent economic value from not being generally known or readily ascertainable by others who could obtain a financial advantage from their use. Thus, Xcel Energy maintains this information as trade secret. _________________________________________________________________ Witness: Anne E. Heuer Preparer: Tom McDonough/John Salazar/Jennifer Pytlick Title: Manager/Director/Consultant Department: Market Operations/Energy Trading/Transmission Accounting

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PUBLIC DOCUMENT: TRADE SECRET DATA EXCISED Telephone: 612-337-2258/303-571-7453/303-571-2782 Date: Supplemented: March 20, 2013

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Documents

PUBLIC DOCUMENT: TRADE SECRET DATA EXCISED · Black Dog Outage Schedule 4 DOC-192 Correction Schedule 5 Docket No. E002/GR-12-961 Larson Rebuttal Public Version i . Emissions Chemicals