1 of 7 - depreciation and remaining lives - perkett testimony

PUBLIC DOCUMENT – TRADE SECRET DATA EXCISED

Direct Testimony and Schedules Lisa H. Perkett

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-13-868 Exhibit___(LHP-1)

Depreciation and Remaining Lives and

Capitalization of Certain Costs

November 4, 2013


Table of Contents I. Introduction 1

II. Depreciation for Production Assets 8

A. 2012 and 2013 Review of Remaining Lives 8

B. 2014 Review of Remaining Lives 14

1. Sherco Unit 3 17

2. Monticello LCM/EPU Project 20

3. Sherco Units 1 and 2 22

4. Black Dog Units 3 and 4 24

5. Prairie Island Administration Building and License Renewal Phase II

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C. Multi-Year Rate Plan Remaining Lives Analysis 26

III. Depreciation for Transmission, Distribution, and General Assets 31

A. 2012 TD&G Depreciation Study 31

B. Multi-Year Rate Plan Depreciation Analysis 34

C. Reserve Surplus Rate Moderation Proposal 36

IV. Nuclear Decommissioning Costs 40

A. 2011 Triennial Nuclear Decommissioning Study 41

B. Multi-Year Rate Plan Decommissioning Analysis 42

C. DOE Settlement Payment Rate Moderation Proposal 43

V. Compliance Items 43

A. Nuclear Plant Theoretical Reserve 43

B. AFUDC and CWIP 51

1. Background 52

2. AFUDC Rate Calculation 55

3. Appropriate CWIP and AFUDC Thresholds 59

C. Capitalization of Transmission Studies 63

i Docket No. E002/GR-13-868 Perkett Direct


D. CWIP and RWIP 68

VI. Conclusion 70

Schedules Statement of Qualifications Schedule 1Commission’s Order Points Addressed in Testimony Schedule 2Black Dog Remediation Cost Roll Forward Schedule 3Sherco 3 Depreciation Deferral Sample Accounting Schedule 4Monticello EPU CWIP Schedule 5Alliance Consulting Group Letter/Black & Veatch Report Schedule 6Sherco 3 Life Change Schedule 7Multi-Year Rate Plan Additions Schedule 8New Wind Depreciation Schedule 9General Ledger Depreciation Schedule 10Transmission, Distribution & Generation Depreciation Schedule 11DOE Refund Distribution Schedule 12Nuclear Theoretical Reserve Schedule 13AFUDC Rate Calculation Schedule 14FERC Orders 561 and 561-A Schedule 15Expensed Transmission Studies Schedule 16 Pre-Filed Discovery Appendix A

ii Docket No. E002/GR-13-868 Perkett Direct


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I. INTRODUCTION

Q. PLEASE STATE YOUR NAME AND OCCUPATION.

A. My name is Lisa H. Perkett. I am the Director of Capital Asset Accounting

for Xcel Energy Services Inc., which provides services to Northern States

Power Company (NSPM or the Company).

Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE.

A. I have 33 years of experience in utility accounting. In my current role, I am

responsible for managing our capital asset accounting policies, maintaining

accounting and tax records for capital assets, ensuring capital asset-related

reporting and regulatory requirements are met, maintaining plant information

for ratemaking purposes, and managing the capital investment cost recovery

process. My resume is included as Exhibit ___(LHP-1), Schedule 1.

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

A. I support the level of depreciation expense included in the test year, providing

information on remaining lives, net salvage rates, and deprecation expense for

all Company assets. In general, the Commission investigates and makes

depreciation decisions in proceedings separate from rate cases for:

• production assets;

• transmission, distribution, and general assets; and

• nuclear decommissioning costs.

The Commission can also make depreciation decisions in rate cases, which

occurred in our 2013 electric rate case (Docket No. E002/GR-12-961). In my

testimony, I refer to the three separate deprecation proceedings and our 2013

1 Docket No. E002/GR-13-868 Perkett Direct


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rate case as they provide the basis for the depreciation expense included in the

2014 test year.

In addition, because we are proposing a multi-year rate plan as part of this

case, I provide the depreciation information required by the Commission in its

June 17, 2013 Order Establishing Terms, Conditions, and Procedures for

Multiyear Rate Plans in Docket No. E,G999/M-12-587.

I also provide support for the rate moderation plan we are proposing in this

case, specifically:

• use of a three-year amortization period for the theoretical reserve

surplus for transmission, distribution, and general assets; and

• use of DOE settlement funds to offset the 2015 revenue requirement.

Company witnesses Mr. Christopher B. Clark and Mr. Jeffrey C. Robinson

provide additional discussion of these proposals in their Direct Testimony.

Finally, I provide other information in compliance with the Commission’s

order in our 2013 rate case. Specifically, I discuss:

• the theoretical depreciation reserve for nuclear assets;

• accounting requirements for Allowance of Funds Used During

Construction (AFUDC) and Construction Work in Progress (CWIP);

• capitalization of transmission studies; and

• CWIP and Removal Work in Progress (RWIP) costs.

Q. WHAT IS THE RELATIONSHIP BETWEEN THE SEPARATE DEPRECIATION

PROCEEDINGS AND A GENERAL RATE CASE?



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A. The proceedings in which depreciation rates are established do not always

match the timing of a rate case. However, the appropriate level of

depreciation expense for a test year should reflect the Commission’s decisions

in the separate depreciation proceedings. To that end, we have incorporated

our proposals from our pending depreciation proceedings, certain future

expected changes in depreciation, and the Commission’s decisions in our 2013

rate case that are reflected in the 2014 test-year revenue requirement. Should

the Commission’s decisions in the separate depreciation proceedings result in

a different depreciation expense than what we have proposed, we will

incorporate those changes into the revenue requirement in this case.

Q. WHAT PROCESS DOES THE COMMISSION USE TO REVIEW DEPRECIATION FOR

PRODUCTION ASSETS?

A. In general, each year in February, we file an annual review of remaining lives

for production assets, proposing changes to depreciation expense based on

any changes to remaining lives or net salvage rates identified in our annual

review. Our 2012 Review of Remaining Lives is currently pending before the

Commission in Docket No. E,G002/D-12-151.

Q. HAS THE COMPANY FILED ITS 2013 REVIEW OF REMAINING LIVES?

A. Yes. We did not submit our 2013 Review of Remaining Lives in February of

2013 because our rate case was pending at that time, and we expected

depreciation decisions to be made in that case. Instead, we submitted our

2013 filing on October 1, 2013 as a supplement in our 2012 remaining lives

docket. This supplement updated our 2012 filing to incorporate the

Commission’s decisions in our 2013 rate case. The information presented in

our October 1, 2013 supplement was already reflected in the revenue



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requirement approved in our 2013 rate case, and also is reflected in the 2014

revenue requirement in this case.

Q. WHEN WILL THE COMPANY SUBMIT ITS NEXT REVIEW OF REMAINING LIVES?

A. Subject to new filing requirements that could be included in the Commission’s

forthcoming order in Docket No. E,G002/D-12-151, we expect to file our

next annual review of remaining lives in February 2014. As required by prior

Commission order, my testimony in this case includes a discussion of the

changes we expect to propose in our 2014 Review of Remaining Lives.

Q. WHAT IS THE PROCESS FOR COMMISSION REVIEW OF DEPRECIATION FOR

TRANSMISSION, DISTRIBUTION, AND GENERAL ASSETS?

A. Every five years, we file a depreciation study reviewing the average service

lives and net salvage rates for transmission, distribution, and general assets and

propose changes to depreciation expense based on the results of our study.

Our most recent five-year study (2012 Study, or the Study), filed in July 2012,

is currently pending before the Commission in Docket No. E,G002/D-12-

858.

Q. WHAT CHANGES DID YOU PROPOSE IN DOCKET NO. E,G002/D-12-858?

A. In addition to average service life and net salvage changes identified by the

2012 Study, the Study incorporated our proposal to change from an average

service life to a remaining life methodology for transmission, distribution, and

general assets, which is the methodology we currently use for production

assets. Use of the remaining life methodology eliminates the difference

between the actual and theoretical depreciation reserves – the net reserve – by

amortizing this reserve surplus (or deficit) over the remaining lives of the



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assets. This change resulted in a decrease in depreciation expense compared

to our last five-year study.

Q. YOU MENTIONED THE 2012 DOCKET IS CURRENTLY PENDING BEFORE THE

COMMISSION. DID THE COMMISSION MAKE A DETERMINATION ABOUT THE

THEORETICAL RESERVE SURPLUS IN THE 2013 RATE CASE?

A. Yes. In our 2013 rate case (Order Point 11), the Commission required the

Company to amortize the theoretical reserve surplus for transmission,

distribution, and general plant for both electric and common assets over eight

years beginning in 2013. On October 1, 2013, we filed a supplement in our

2012 docket to implement the eight-year amortization, which was already

reflected in the revenue requirement approved in our 2013 rate case.

Q. ARE YOU PROPOSING TO USE THE RESERVE SURPLUS FOR ANY ADDITIONAL

RATE MODERATION IN THIS CASE?

A. Yes. We are proposing a three-year amortization of the theoretical reserve

surplus beginning in 2014 to provide further rate moderation for our

customers. The Commission ordered an eight-year amortization of the

jurisdictional surplus for the transmission, distribution, and general assets for

the electric and common utilities beginning in 2013. The three-year

amortization proposed by the Company would amortize 50 percent of the

remaining surplus in 2014, 30 percent in 2015, and 20 percent in 2016.

Q. WHAT IS THE COMMISSION’S PROCESS FOR REVIEWING NUCLEAR

DECOMMISSIONING COSTS?



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A. We submit for Commission approval a triennial review of decommissioning

costs. Our latest triennial study, submitted in November 2011, was approved

by the Commission in December 2012 in Docket No. E002/M-11-939.

Q. IS THE COMMISSION’S DECISION IN THAT CASE INCORPORATED INTO THE 2014

TEST YEAR?

A. Yes. The Commission approved an annual nuclear decommissioning accrual

amount of $14.2 million in that case, and also approved our proposal that the

accrual be funded using Department of Energy (DOE) settlement payments.

As a result, it is currently not necessary to collect any decommissioning funds

from customers, and there was no impact to the test-year cost of service in our

2013 rate case. Likewise, there is no revenue requirement impact in the 2014

test year.

Q. DO YOU PROPOSE ANY CHANGES IN THIS CASE REGARDING THE USE OF THE

DOE SETTLEMENT PAYMENTS?

A. Yes. Currently, the Company is required to place the 2013 DOE settlement

funds in excess of the accrual amount into the decommissioning fund. On

October 22, 2013, we made a filing in Docket Nos. E002/M-11-939 and

E002/M-11-807 requesting that the Commission allow the Company to place

the 2013 DOE settlement payments in excess of the approved accrual amount

in an external escrow account separate from the decommissioning escrow

fund. Doing so would preserve the option for the Commission to use these

funds for additional rate moderation in this case. Our proposal in this case is

to use the excess funds in 2013 and 2014, totaling approximately $35.7 million,

to reduce the 2015 revenue requirement.



Q. HOW HAVE YOU ORGANIZED THE REMAINDER OF YOUR TESTIMONY? 1

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A. I present my testimony in the following sections:

• Depreciation for Production Assets, providing information on our pending

2012 and 2013 Review of Remaining Lives, compliance with the

Commission’s order in our 2013 rate case related to depreciation for

production assets, and changes we expect to propose in our 2014

Review of Remaining Lives. This section also provides depreciation

information for production assets required to support a multi-year rate

plan proposal.

• Depreciation for Transmission, Distribution, and General Assets, providing an

overview of our pending 2012 Study and implementation of the eight-

year amortization of the theoretical reserve surplus required in our 2013

rate case. This section also provides the depreciation information for

transmission, distribution, and general assets required to support a

multi-year rate plan proposal and presents our proposal to use a three-

year amortization period for the theoretical reserve surplus beginning in

2014.

• Nuclear Decommissioning Costs, providing an overview of our 2011

Triennial Nuclear Decommissioning proceeding, discussing how the

decommissioning accrual would carry forward through multi-year rate

plan period, and presenting our proposal to use the DOE settlement

payments in excess of the approved accrual amount to offset the 2015

revenue requirement.

• Compliance Items, presenting information in compliance with the

Commission’s order in our 2013 rate case on the theoretical

depreciation reserve for nuclear assets, accounting requirements for

AFUDC and CWIP, and capitalization of transmission studies. I also



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provide a description of CWIP and RWIP to support the testimony of

various business area witnesses.

Q. YOU MENTIONED YOU ARE PROVIDING CERTAIN INFORMATION IN

COMPLIANCE WITH THE COMMISSION’S ORDER IN THE COMPANY’S 2013 RATE

CASE. CAN YOU PROVIDE DETAILS ON THE SPECIFIC ORDER POINTS YOU

ADDRESS?

A. Exhibit___(LHP-1), Schedule 2 provides a list of the Commission’s order

points from our 2013 rate case that I address and indicates where each

requirement is addressed in my testimony or schedules.

Q. DO YOU PROVIDE ANY ADDITIONAL INFORMATION RELATED TO

DEPRECIATION?

A. Yes. To prepare testimony for this case, we reviewed the discovery related to

depreciation from the 2013 rate case. We incorporated some of this discovery

into my testimony through expanded discussion and schedules. We are also

providing additional information in the form of pre-filed discovery, which can

be found in Appendix A to my testimony. Appendix A also provides a list of

each information request from the 2013 rate case that I have incorporated,

indicating where it is included in my testimony or schedules, or if it is provided

in Appendix A.

II. DEPRECIATION FOR PRODUCTION ASSETS

A. 2012 and 2013 Review of Remaining Lives

Q. PLEASE SUMMARIZE THE STATUS OF THE COMPANY’S 2012 AND 2013 REVIEW

OF REMAINING LIVES.



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A. We submitted our 2012 Review of Remaining Lives in Docket No. E002/D-

12-151 on February 17, 2012. During the comment period, we modified our

2012 proposal in response to the Comments of the Minnesota Department of

Commerce (Department), and the Department recommended approval of our

modified 2012 proposal in Response Comments dated August 17, 2012.

In its September 3, 2013 order in our electric rate case, the Commission

approved a revenue requirement that reflected our modified 2012 proposal,

and additionally, a life extension for the Granite City peaking plant and

adjustments related to Sherco Unit 3, Black Dog, and Monticello.

To implement the Commission’s decisions in our 2013 rate case, we submitted

our 2013 Review of Remaining Lives on October 1, 2013 as a supplement in

our 2012 docket. This supplement:

• started from our modified 2012 proposal, including the depreciation

reserve reallocation related to the Minnesota Valley plant;

• reflected one-year passage of time updates from 2012 to 2013;

• included the Granite City life extension of six years; and

• reflected the Commission’s rate case decisions related to Black Dog

remediation, Sherco Unit 3, and the Monticello LCM/EPU project.

The approved revenue requirement in our 2013 rate case reflected this

information.

Q. IS THE 2014 REVENUE REQUIREMENT CONSISTENT WITH THE INFORMATION

INCLUDED IN YOUR 2013 REVIEW OF REMAINING LIVES?

A. Yes. The 2014 test year revenue requirement is based on the information

outlined above, and additionally includes one-year passage of time updates



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from 2013 to 2014. These updates were included in the 2014 budget, thus no

adjustment is required to reflect these updates in the 2014 revenue

requirement.

Q. PLEASE BRIEFLY DISCUSS THE 2013 DEPRECIATION CHANGES THAT RESULT

FROM THE COMMISSION ORDER IN THE 2013 RATE CASE FOR MINNESOTA

VALLEY.

A. Our 2012 Review of Remaining Lives included the following changes that also

were reflected in the approved 2013 rate case revenue requirement:

• updated removal cost estimates for the Minnesota Valley plant;

• updated demolition, remediation, and decommissioning cost estimates

for the Minnesota Falls Dam; and

• a reallocation of the 2012 year-end accumulated depreciation reserve

balances among the individual units in steam production to fully

depreciate the Minnesota Valley plant to reflect the fact that it is no

longer in operation.

A full discussion of these changes is included in our 2013 Review of

Remaining Lives submitted October 1, 2013 in Docket No. E,G002/D-12-

151. These changes were included in the 2014 budget, thus no adjustment is

required to reflect these changes in the 2014 revenue requirement.


FROM THE COMMISSION ORDER IN THE 2013 RATE CASE FOR GRANITE CITY.

A. The remaining life for Granite City was zero years as of January 1, 2013.

However, the plant is not being retired, and a major upgrade to the operating

control systems on Units 1 and 2 was placed in service in June 2013, at a total



capitalized amount of $307,929. To ensure the cost of the upgrades was not

immediately expensed in 2013, we proposed in our 2013 rate case to assign a

new six-year life to the Granite City plant to begin when these new assets went

in service.

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1

A full discussion of this change is included in our 2013 Review of Remaining

Lives submitted October 1, 2013 in Docket No. E,G002/D-12-151 and is

reflected in the approved 2013 rate case revenue requirement. This change

was included in the 2014 budget, so no adjustment is required to reflect this in

the 2014 revenue requirement.


FROM THE COMMISSION ORDER IN THE 2013 RATE CASE FOR BLACK DOG

UNITS 3 AND 4.

A. The 2010 removal cost study for Black Dog Units 3 and 4 did not include the

cost to remove the coal pile and the ash ponds beneath the coal pile.

Subsequent to completion of the 2010 study, we entered into a Voluntary

Investigation and Cleanup (VIC) program with the State of Minnesota to

remediate the land. The program requires the Company to fully remediate the

land where the coal pile and ash ponds are located.

In our 2013 rate case, the Commission approved a 15-year amortization

period, effective January 1, 2013, for the increased removal costs of $33.2

1 See 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, DIRECT TESTIMONY AND SCHEDULES OF LISA H. PERKETT.



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million, resulting in an increase to annual expense of $2.2 million for steam

production.

A full discussion of this change is included in our 2013 Review of Remaining

Lives submitted October 1, 2013 in Docket No. E,G002/D-12-151 and is

reflected in the approved 2013 rate case revenue requirement. This change

was not included in the 2014 budget and, therefore, Company witness Ms.

Anne E. Heuer, in her Direct Testimony, includes an adjustment to reflect this

change to the 2014 test year revenue requirement. A schedule showing the

total Company calculation is provided as Exhibit___(LHP-1), Schedule 3.


FROM THE COMMISSION ORDER IN THE 2013 RATE CASE FOR SHERCO UNIT 3.

A. In our 2013 rate case (Order Point 7), the Commission approved deferred

accounting for Sherco Unit 3’s 2013 depreciation expense. This resulted in

$14.1 million of deferred depreciation expense for 2013, with recovery over

the remaining life of Sherco Unit 3 beginning January 1, 2014. The 2013

Review of Remaining Lives presented the estimated impact of the deferral

based on beginning plant balances, the basis for all comparisons. The

calculation for this proceeding uses actual and forecasted plant balances by

month throughout 2013. Thus, there is a $0.7 million difference between the

deferral amount presented in our 2013 Review of Remaining Lives and this

case at a jurisdictional level. The amortization is discussed below in Section B,

2014 Review of Remaining Lives. This change was not included in the 2014

budget and therefore Ms. Heuer, in her Direct Testimony, includes an

adjustment to reflect this change to the 2014 test year revenue requirement. A



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schedule showing the total Company calculation and the sample accounting is

provided as Exhibit___(LHP-1), Schedule 4.


FROM THE COMMISSION ORDER IN THE 2013 RATE CASE FOR THE

MONTICELLO LCM/EPU PROJECT.

A. In our 2013 rate case (Order Point 3), the Commission required the Company

to transfer 41.6 percent of the additional Monticello LCM/EPU project costs

incurred since the 2010 rate case to CWIP effective January 1, 2013.

Accordingly, the Company transferred $28.5 million to CWIP from plant in

service for the 2011 and 2012 incremental additions to rate base. In addition,

the Commission required 41.6 percent of the 2013 adjusted additions in our

2013 rate base plus 41.6 percent of any addition over and above the adjusted

2013 rate base to remain in CWIP until the EPU license is in service and the

prudency review has been completed. The 2013 additions retained in CWIP

have been reflected in this proceeding. In contrast, our 2013 Review of

Remaining Lives filed on October 1, 2013 bases its calculations on beginning

plant, thus only the impact of the Commission’s rate order on the 2011 and

2012 years are represented in that filing. The impact of these adjustments on

2014 and beyond is discussed below in Section B, 2014 Review of Remaining

Lives.

This change was not included in the 2014 budget and therefore Ms. Heuer, in

her Direct Testimony, includes an adjustment to reflect this change to the

2014 test year revenue requirement. A schedule showing the total Company

calculation is provided as Exhibit___(LHP-1), Schedule 5.



Q. HOW WILL THE COMPANY ADDRESS THE OUTCOMES OF THE 2012 AND 2013

REVIEW OF REMAINING LIVES DOCKET IN THIS RATE CASE?

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A. If the Commission issues an order in the 2012 and 2013 Review of Remaining

Lives docket that results in a different 2013 depreciation expense than

discussed above, we will incorporate those changes into the 2014 test year

revenue requirement in this case.

B. 2014 Review of Remaining Lives

Q. WHY DO YOU PRESENT INFORMATION ON YOUR UPCOMING 2014 REVIEW OF

REMAINING LIVES IN THIS RATE CASE?

A. The Commission’s June 16, 2010 Order in our 2010 Remaining Lives

proceeding (Docket No. E,G002/D-10-173) requires that rate case filings

provide information on significant changes to depreciation that we expect to

request in our next annual remaining lives filing. Specifically, the Commission

required Xcel Energy “in its pre-filed direct testimony in its next rate case, to

identify significant additions to plant investment proposed to be included in

rates, and discuss how a life extension for each such plant has been reflected

in the depreciation rates used in the rate case, or why a life extension has not

been proposed.” We believe this requirement was intended to apply to all

future rate cases.

Q. WHAT CHANGES DO YOU EXPECT TO PROPOSE IN YOUR 2014 REVIEW OF

REMAINING LIVES?

A. In addition to a one-year passage of time update, we expect the only changes

we will propose in our 2014 Review of Remaining Lives will be those

necessary to reflect the 2014 impact of the Commission’s decisions in our

2013 rate case related to Sherco Unit 3 and the Monticello LCM/EPU project.



Q. HAVE THE SHERCO 3 AND MONTICELLO LCM/EPU CHANGES BEEN

REFLECTED IN THE 2014 TEST YEAR REVENUE REQUIREMENT?

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A. Yes. While they were not included in the 2014 budget, we have included

adjustments to the 2014 test year revenue requirement to reflect these changes.

Ms. Heuer presents these adjustments in her Direct Testimony.

Q. DID YOU REVIEW OTHER POTENTIAL CHANGES FOR INCLUSION IN THE 2014

REVIEW OF REMAINING LIVES?

A. Yes. In this section, I also discuss our review of planned or potential plant

investments at Sherco Units 1 and 2, Black Dog Units 3 and 4, the Prairie

Island Administration Building, and the Prairie Island License Renewal Phase

II. Based on this review, we do not believe any changes to remaining lives are

necessary, and thus have not incorporated any changes to the 2014 test year

revenue requirement for these plants.

Q. PLEASE DESCRIBE THE PROCESS USED TO IDENTIFY CHANGES THE COMPANY

ANTICIPATES INCLUDING IN THE 2014 REVIEW OF REMAINING LIVES FILING.

A. We followed the same process used to complete each remaining life filing.

Annually, our depreciation analysts meet with the employees who are

knowledgeable about the planning, construction, and operations at each

facility. During these meetings, we review each facility to:

1) understand the major overhauls, rebuilds, and routine construction

projects performed in the past few years;

2) consider the scope of current and upcoming projects; and

3) forecast the likelihood of the facility achieving the currently-approved

remaining life in light of the past, current, and near future projects.



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If we determine that the current remaining life is no longer appropriate, we

propose a modification to the remaining life for that facility. This information

is responsive to Information Request XLI-209 in our 2013 rate case.

We also consider the likelihood that a planned major overhaul, rebuild, or

routine construction project will occur in the next 10 to 12 months, and its

probable effect on each facility. If there is uncertainty whether the work will

occur, we reduce the weight given to this factor in our remaining life analysis.

Each year, we review the projects scheduled for each plant to gauge if there is

more or less certainty of completion, and we adjust our analysis accordingly.

Occasionally, there is a significant individual event that influences a change to

remaining life – for example, the operating license renewal at Monticello.

More often, however, it is a culmination of several smaller factors that, when

considered together, support a change in the remaining life. If just one or two

of these small changes are present, the factors may not be strong enough to

influence a life change. As time passes each year, more of these smaller

factors may be realized such that a change would become appropriate.

Q. WHAT WORK HAS THE COMPANY PERFORMED TO COMPLY WITH THE 2010

REMAINING LIVES ORDER?

A. As required by that Order, we included an evaluation of the “significant”

additions to plant investment expected in the next several years. As we do for

each remaining life filing, we reviewed the appropriateness of the current

approved end-of-life dates for production facilities. We also reviewed any

significant changes to operating plans or other regulatory changes that could

provide an impetus to change the remaining life in this proceeding.



Q. HOW DID YOU DEFINE THE TERM “SIGNIFICANT” AS SET FORTH IN THE 2010

REMAINING LIVES ORDER?

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A. For purposes of my testimony, “significant” additions refer to any

construction activities that either singly or in combination with another project

lead to a probable extension of the current remaining life of a particular facility

or unit. I believe this definition is consistent with the 2010 Remaining Lives

Order as it addresses the Commission’s concerns related to changes in

remaining lives and the impacts of the changes on rates for customers.

1. Sherco Unit 3

Q. PLEASE DISCUSS SHERCO UNIT 3 AND THE TREATMENT OF PLANT PLACED

INTO HELD FOR FUTURE USE (HFU).

A. In November 2011, Sherco 3 experienced a significant failure during testing

while returning to service following a scheduled maintenance overhaul. At

that time, $24.3 million in plant additions related to the upgrade project were

ready for service. When the unit came off-line, these assets were placed in a

HFU account, FERC Account 105. No depreciation is calculated while the

assets are in this account; however, they are included in rate base. When

Sherco 3 returned to service in September 2013, these assets were moved back

to Plant in Service and began depreciation. In our 2013 rate case, the

Commission ordered the depreciation expense for 2013 on all of Sherco 3 to

be deferred until January 1, 2014, thus the depreciation expense for these

assets from September through December 2013 is included in the Sherco 3

deferral.


FROM THE COMMISSION ORDER IN THE 2013 RATE CASE FOR SHERCO UNIT 3.



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A. As discussed in Section A above, we deferred Sherco Unit 3’s 2013

depreciation expense of $14.1 million on a total Company basis ($10.5 million

for the Minnesota electric jurisdiction). Starting in 2014, for the Minnesota

electric jurisdiction, the amortization is $0.5 million per year for 21 years. This

change was not included in the 2014 budget and, therefore, Ms. Heuer, in her

Direct Testimony, includes an adjustment to reflect this change to the 2014

test year revenue requirement. A schedule showing the total Company

calculation is provided as Exhibit__(LHP-1), Schedule 4.

Q. WAS THE REMAINING LIFE OF SHERCO UNIT 3 AFFECTED BY THE EXTENDED

OUTAGE?

A. Yes. In the 2013 rate case, the Commission accepted the Company’s proposal

to suspend the 21-year remaining life for Sherco Unit 3 as of January 1, 2012

for the period of the outage. The Commission accepted the proposed 21-year

remaining life of Sherco Unit 3 as a placeholder, directing the Company to

have an engineer evaluate Sherco Unit 3 and provide that analysis in its next

rate case.

Q. PLEASE DESCRIBE THE SHERCO 3 ENGINEERING REVIEW AND RESULTS.

A. In response to the Commission’s Order Point 8, the Company contracted with

Black & Veatch, a firm familiar with the equipment at Sherco Unit 3 to

conduct a review for the expected remaining usefulness of the entire unit. In

addition, Sherco operations and construction personnel participated in the

analysis along with the Capital Asset Accounting department, which is

responsible for the overall depreciation of the unit. In addition, Dane Watson

of Alliance Consulting Group, an engineer specializing in depreciation analysis,

provided an independent review of the remaining life from a depreciation



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perspective. It was our collective conclusion that the outage did not materially

affect the existing remaining life of Sherco Unit 3 and that the 21-year

remaining life is appropriate given the current structure of the unit. A copy of

the Alliance Consulting letter and Black & Veatch report is provided as

Exhibit___(LHP-1), Schedule 6.

Q. PLEASE SUMMARIZE THE BASIS FOR THE STUDY’S CONCLUSION THAT THE 21-

YEAR REMAINING LIFE IS APPROPRIATE.

A. The remaining useful life of the entire Sherco Unit 3 plant is a function of the

condition of the plant as a whole rather than any single component. The

Black & Veatch report summarizes that in the case of a steam generating coal

plant, the component that most likely affects the plant’s remaining useful life is

the boiler. There were several components of the unit that were severely

damaged in the incident, but the boiler was neither damaged nor affected.

The analysis of Sherco 3’s remaining life was based on all components. The

turbine, generator, and exciter were repaired or rebuilt to return the plant to

the condition that existed when the unit was damaged in November 2011.

The exciter, for example, was replaced with a refurbished exciter of a similar

vintage to the damaged equipment purchased from another plant. Even if the

exciter was deemed the most critical component in determining the plant’s

remaining useful life, replacement with a similar vintage exciter does not

warrant an extension in the life of the plant.

In addition to reviewing the current state of the unit, we reviewed the current

long-term forecast. There are future capital additions expected within the 21-

year remaining life. The most impactful of potential future additions would be



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substantial investments in boiler plant equipment and the addition of

environmental control equipment. Since the Company’s long-term forecast is

still speculative at this time, and any adjustment to remaining life should be

made once the improvements have demonstrated longer usefulness of the

facility, we do not recommend any change to the 21-year remaining life. At

such time that a definitive plan exists and the investment is shown to add to

the remaining life, the Company would propose an extension to the plant’s

remaining life in its annual review of remaining lives.

Q. WHAT CHANGE RELATED TO SHERCO 3 WILL BE INCLUDED IN THE 2014

REVIEW OF REMAINING LIVES?

A. In our 2014 Review of Remaining Lives, we will be proposing the 21-year

remaining life for Sherco Unit 3 beginning January 1, 2014.

Q. HAS THIS CHANGE BEEN REFLECTED IN THE 2014 TEST YEAR REVENUE

REQUIREMENT?

A. Yes. This change was not included in the 2014 budget and, therefore, Ms.

Heuer, in her Direct Testimony, includes an adjustment to reflect this change

to the 2014 test year revenue requirement. A schedule showing the total

Company calculation is provided as Exhibit___(LHP-1), Schedule 7.

2. Monticello LCM/EPU Project

Q. PLEASE BRIEFLY DISCUSS THE 2014 CHANGES THAT RESULT FROM THE

COMMISSION ORDER IN THE 2013 RATE CASE FOR THE MONTICELLO

LCM/EPU PROJECT.

A. In our 2013 Review of Remaining Lives filed on October 1, 2013, the

Company presented the placement of $34.8 million into CWIP, which



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decreased the 2013 depreciation expense. The amount shown moving back to

CWIP in this filing was limited to the changes to the 2013 beginning balance.

The Commission also ordered that 41.6 percent of the 2013 addition remain in

CWIP until the uprate can be used, which is expected to be in January 2014.

This amount did not include $15.0 million of expenditures, which were

reclassified from removal costs to CWIP in the 2011 test year in Docket No.

E002/GR-10-971. The reclassification to CWIP in that case reduced the

difference between actual plant additions and amounts forecasted in 2011.

Thus, we subtracted 41.6 percent of the $15.0 million of removal costs from

the $34.8 million, resulting in a total amount of $28.5 million related to the

Monticello LCM/EPU project placed in CWIP in this case.

The amount placed in CWIP pursuant to the Commission’s Order in our 2013

rate case for the 2013 addition of $247.1 million is approximately $102.8

million. The license costs also remain in CWIP until January 2014. Lastly,

41.6 percent of any addition over and above the last rate case addition in 2013

was to remain in CWIP. In total, $161.0 million is to remain in CWIP until

the license for the uprate is received and the uprate is in use. Leaving these

assets in CWIP increased the AFUDC associated with the asset by $6.4

million.

Q. WHAT CHANGE RELATED TO THE MONTICELLO LCM/EPU PROJECT WILL BE

INCLUDED IN THE 2014 REVIEW OF REMAINING LIVES?

A. Our 2014 Review of Remaining Lives will reflect an addition of $167.4 million

placed in service as of January 2014 related to the Commission’s order from

the 2013 rate case. Depreciation will begin in January 2014 for this asset, with

an increase to 2014 depreciation expense of $0.3 million compared to the



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depreciation expense that would have been recorded absent the Commission’s

Order.

Q. HAS THIS CHANGE BEEN REFLECTED IN THE 2014 TEST YEAR REVENUE

REQUIREMENT?



to the 2014 test year revenue requirement. A schedule showing the total

Company calculation is provided as Exhibit___(LHP-1), Schedule 5.

3. Sherco Units 1 and 2

Q. BRIEFLY SUMMARIZE THE CURRENT REMAINING LIFE FOR SHERCO UNITS 1

AND 2.

A. Sherco Units 1 and 2 currently have a remaining life of nine years as of January

1, 2014, as approved in the Commission’s September 8, 2011 order in our

2011 Review of Remaining Lives. Based on their in service years of 1976 and

1977, respectively, the whole life of these units is 46 and 45 years. Our

pending 2012 and 2013 Review of Remaining Lives filings recommend no

changes to the remaining life of Sherco Units 1 and 2. As part of the

Company’s 2011-2025 Integrated Resource Plan, the Company agreed to

complete a Life Cycle Management Study for Sherco Units 1 and 2. The

Company submitted this Study on July 1, 2013 in Docket E002/RP-13-368.

This is the study identified in Information Request XLI-207 in the 2013 rate

case.

Q. BRIEFLY DESCRIBE THE PARAMETERS OF THE SHERCO UNITS 1 AND 2 STUDY.



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A. The study was commissioned to examine the feasibility and cost-effectiveness

of a variety of scenarios related to Sherco Units 1 and 2 including retrofitting,

retirement and continued operations. The study outlined a base case, which

assumed continued operation of the Units until 2040 including installation of

carbon dioxide emissions control equipment and other equipment to comply

with likely Environmental Protection Agency (EPA) regulations. Alternative

scenarios were presented to: 1) retrofit the Units with SCR equipment; or 2) to

retire the Units in 2018-2019 and replace the capacity through a combination

of conservation and capacity powered renewable energy sources. The goal of

the study was to examine the least-cost scenarios to reduce greenhouse gas

emissions relative to 2005 levels by at least 15 percent by 2015, 30 percent by

2025, and 80 percent by 2050.

Q. BRIEFLY SUMMARIZE THE CONCLUSIONS OF THE STUDY AND YOUR REVIEW OF

THE REMAINING LIFE FOR SHERCO UNITS 1 AND 2.

A. The study concludes that the most prudent course of action at this time is to

continue to operate Sherco Units 1 and 2 until such time that there is greater

certainty on the development of environmental regulations. To ensure timely

action when such information is available, the study recommends the

Commission require an analysis when: 1) air quality regulations establish a

need for SCR equipment; or 2) a carbon regulation framework takes shape.

The study’s base case recommendation to continue operations through 2040

was based on the assumption that SCR equipment would be installed at some

point in the next 10 to 15 years. Since a decision has not been made to invest

in emission equipment upgrades needed to continue operating beyond the



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current remaining life through 2022, we do not at this time recommend a

change in the remaining life for these two units.

4. Black Dog Units 3 and 4

Q. BRIEFLY SUMMARIZE YOUR REVIEW OF THE REMAINING LIFE FOR BLACK DOG

UNITS 3 AND 4.

A. Black Dog Units 3 and 4 currently have a remaining life of two years as of

January 1, 2014. Since these units have a fairly short remaining life, these units

were reviewed to confirm that the two-year remaining life is still accurate. We

discussed the remaining life with operating personnel familiar with the units’

operations and the environmental constraints. The two units can operate on

either coal or gas. It is expected that the two units will operate until April

2015. Depending on the environmental constraints on the units, they may

serve as emergency peak load for a short time thereafter.

If the units remain in service beyond December 2015, the Company would

treat the depreciation similar to other peaking units at Key City and Blue Lake

(where the remaining life has gone to zero, there is no depreciation, and all

costs are expensed). There is a possibility that a simple cycle unit would be

built on the site and this new unit would be built where Unit 4 sits today. The

details behind this proposal were discussed in testimony filed by Company

witnesses in Docket No. E002/CN-12-1240. Building this new unit would

mean that these two units would need to be demolished beginning late in 2015

or early in 2016. Based on this information, we do not recommend a change

in the remaining life at this time.



5. Prairie Island Administration Building and License Renewal Phase II 1

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Q. ARE THERE ANY PLANT CHANGES PLANNED FOR THE PRAIRIE ISLAND

NUCLEAR PLANT?

A. Yes. The Company is constructing a new administration building at the Prairie

Island location. The new building is expected to go into service toward the

end of 2014.

Q. WHAT IS THE PLANNED REMAINING LIFE FOR THIS NEW ADMINISTRATION

BUILDING?

A. The Company intends to assign to the new administration building the same

remaining life as all other structures and improvement assets at the Prairie

Island plant. This will be 20.3 years as of January 1, 2014. However, it may be

determined at some point in the future that the building may be used past the

current shutdown date during decommissioning activities. As

decommissioning plans become more certain, if it is determined that the new

administration building will be needed for a longer period of time, the

Company would recommend extending the life past the current shutdown

date.

Q. PLEASE BRIEFLY DISCUSS THE TREATMENT FOR THE PRAIRIE ISLAND LICENSE

RENEWAL PHASE II.

A. The Prairie Island License Renewal Phase II will be placed in service in

October 2014 at a cost of $14.7 million and amortized over the remaining life

authorized for the Prairie Island plant, currently 20.3 years as of January 1,

2014. Company witness Mr. Timothy J. O’Connor discusses in his Direct

Testimony the license renewal project. Consistent with 18 CFR, Subchapter

C, Part 101 the license costs will be recorded in Account 302 Franchises and



Consents. The Company believes amortization over the remaining life of the

Prairie Island plant is appropriate because the license costs are similar to all

other unrecovered costs of the plant. Thus, the use of the remaining life

depreciation methodology approved by the Commission for the Company’s

production facilities is proposed for these license costs. This treatment is

identical to that approved for the previous license extensions for our nuclear

units.

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C. Multi-Year Rate Plan Remaining Lives Analysis

Q. FOR COMPANIES FILING A MULTI-YEAR RATE PLAN, WHAT ADDITIONAL

DEPRECIATION INFORMATION IS REQUIRED?

A. The Commission’s June 17, 2013 Order Establishing Conditions, and

Procedures for Multiyear Rate Plans, contains the following requirements

related to depreciation.2

• Depreciation lives related to capital additions in each year of the plan.

This requirement applies to capital additions in 2014 and 2015.

• Changes expected in the lives of all depreciable assets for two years

after the plan. This requirement applies to all depreciable assets during

2016 and 2017.

Q. WHAT PRODUCTION ASSETS ARE BEING ADDED DURING 2014 AND 2015, THE

YEARS INCLUDED IN THE COMPANY’S PROPOSED MULTI-YEAR RATE PLAN?

A. There are 33 projects included in 2014 and there are 18 projects included in

2 In the Matter of the Minnesota Office of Attorney General – Antitrust and Utilities Division’s Petition for a Commission Investigation Regarding Criteria and Standards for Multiyear Rate Plans under Minn. Stat. § 216B.16, subd. 19, Docket No. E,G999/M-12-587, June 17, 2013, Order Point 18.



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2015 for production. These projects have been summarized in

Exhibit___(LHP-1), Schedule 8. These include new projects in 2014, and for

2015, it includes both new additions and the annualized effect of certain

additions in 2014. This schedule is responsive to Information Requests DOC-

132 and DOC-133 from our 2013 rate case.

Q. PLEASE DESCRIBE THE PROCESS USED TO IDENTIFY DEPRECIATION CHANGES

THE COMPANY ANTICIPATES FOR 2015 AND FOR THE TWO YEARS FOLLOWING

THE PLAN, 2016 AND 2017.

A. We are required to analyze the effect of new projects added during the multi-

year rate plan on depreciation expense for 2015 through 2017. For this

period, we propose the following:

• no change to the Sherco Units 1 & 2 remaining lives;

• no further change to the Sherco Unit 3 remaining life; and

• a remaining life and net salvage rate for Pleasant Valley and Border, the

two new wind farms expected to be in service in 2015.

Q. WHY DO YOU RECOMMEND NO CHANGES RELATED TO THE THREE SHERCO

UNITS FOR 2016 AND 2017?

A. There is no additional information or construction plans for these three units

that would influence a change in the remaining lives beyond the two year life

extension recommended for Sherco Unit 3 discussed earlier in my testimony.

We do continue to account for the passage of time for these assets, and this

normal passage has been included in the test year adjustment provided for

Sherco Unit 3 and for the budget information reflected in the revenue

requirement for Sherco Units 1 and 2.



Q. WHAT DO YOU RECOMMEND FOR THE REMAINING LIVES OF THE TWO NEW

WIND FARMS?

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A. The Pleasant Valley wind farm is a 200 MW wind farm to be located near

Austin, Minnesota. The Border wind farm is a 150 MW wind farm to be

located in northeastern Rolette County, North Dakota immediately south of

the U.S.-Canadian Border. Both projects are expected to become operational

in late 2015. Please see the Direct Testimony of Company witness Mr. Steven

H. Mills for a detailed discussion of these two projects.

The proposed expected useful life of these facilities is 25 years, which is

consistent with Grand Meadow wind farm and Nobles wind farm. Xcel

Energy proposes the life of these new wind resources be set at 25 years

effective with the in-service date of October 2015 for Pleasant Valley and

November 2015 for Border. While wind farms have become more common

over the last decade, we still have little retirement history to judge whether a

different remaining life may be more accurate. The main components that

would influence the life of a wind turbine are the life of the nacelle and the

blade. We have seen some early failures of these components, but none to a

magnitude that would suggest a different life is more appropriate.

Q. WHAT DO YOU RECOMMEND FOR THE NET SALVAGE RATE FOR THE TWO NEW

WIND FARMS?

A. We are recommending that a net salvage rate of negative 8.5 percent be used

for both Pleasant Valley and Border. This is similar to the negative 8.7

percent net salvage rate that is currently approved for both Grand Meadow

and Nobles. The net salvage rate for Grand Meadow and Nobles was based

on a detailed dismantling cost study completed for Grand Meadow and filed



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and approved as a part of our 2010 Remaining Life filing under Docket No.

E,G002/D-10-173. At this time, no dismantling studies have been completed

for the new wind farms. Since there is no site-specific study on which to base

a net salvage rate for the new wind farms, we are using the previously

approved net salvage rate for the other wind farms as a guideline, and have

rounded the net salvage percentage up to a negative 8.5 percent. The net

salvage rates for these new wind farms will be reconsidered as a part of our

next site-specific dismantling study, which will be filed as a part of our 2015

Review of Remaining Lives.

Q. WHAT IS THE DEPRECIATION EXPENSE FOR 2015 FOR THE TWO NEW WIND

FARMS?

A. The depreciation for 2015 is estimated to be $3.1 million for Pleasant Valley

and $1.4 million for Border. This represents 2.5 months of depreciation based

on Pleasant Valley being in service in mid-October, 2015 and 1.5 months of

depreciation based on Border being in service in mid-November 2015.

This change was not included in the 2015 budget and therefore Ms. Heuer, in

her Direct Testimony, includes an adjustment to reflect this change to the

2015 revenue requirement. A schedule showing the total Company calculation

of the depreciation expense for the two new wind farms is provided as

Exhibit___(LHP-1), Schedule 9.

Q. PLEASE DISCUSS HOW THE NEXT DISMANTLING COST STUDY FOR PRODUCTION

ASSETS FITS INTO THE DEPRECIATION REVIEW FOR THE MULTI-YEAR RATE

PLAN.



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A. Our next dismantling cost study will be completed in 2015. We do not know

the outcome of that study at this time. However, we believe the earlier

discussed removal cost estimates for Minnesota Valley, Minnesota Falls Dam

and Black Dog are appropriate. The Response Action Plan (RAP) for Black

Dog is expected to be approved in mid 2014, which could trigger a

reassessment of the scope of removal to assure it is in compliance with the

approved RAP.

The 2015 dismantling study will include removal costs for below ground

contaminants such as ash, coal, and debris. Based on our experience at Black

Dog, we expect increased dismantling costs and more negative net salvage

rates for plants currently or previously fueled by coal that are yet to be fully

dismantled, such as Sherco and Allen S. King. At this time, we do not have an

estimate of the increase in removal costs for Sherco and King above the 2010

TLG Dismantling Study.

Q. HAVE YOU IDENTIFIED DISCOVERY REQUESTS FROM THE 2013 RATE CASE

THAT ARE RELEVANT TO THIS PORTION OF YOUR TESTIMONY?

A. Yes. We have included updated responses to Information Requests DOC-168

and XLI-206 in Appendix A.



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III. DEPRECIATION FOR TRANSMISSION,

DISTRIBUTION, AND GENERAL ASSETS

A. 2012 TD&G Depreciation Study

Q. PLEASE GENERALLY DESCRIBE THE 2012 TD&G STUDY AND YOUR REQUEST

IN DOCKET NO. E,G002/D-12-858.

A. In aggregate, the study supported longer average service lives to better reflect

the expected useful lives of our assets, and net salvage rates became more

negative to better reflect the expected higher costs of removal. We also

requested a change from using average service lives to using an average

remaining life rate for all electric and common assets. This change in

depreciation method was proposed for the purpose of eliminating the

difference between the accumulated actual reserve and the theoretical reserve

balances over the remaining lives of the assets. This docket is currently

pending before the Commission.

Q. WHAT DECISION DID THE COMMISSION MAKE IN THE 2013 RATE CASE

RELATED TO DEPRECIATION FOR TD&G ASSETS?

A. The Commission required the Company to amortize the reserve surplus over

eight years, effective January 1, 2013. As a result, the proposed depreciation

rates are no longer average remaining life rates, but rather, are average service

life rates. Consequently, we propose to continue using the whole life method

of depreciation for these assets. We anticipate that the next five-year study

will be filed in July 2017.

Q. WHAT WAS THE RESERVE SURPLUS THAT RESULTED FROM THIS STUDY THAT IS

BEING AMORTIZED OVER EIGHT YEARS?



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A. The reserve surplus that resulted from the 2012 Study was $317.0 million for

the electric utility for total company. The common utility theoretical to actual

reserve comparison resulted in a reserve deficit of $5.7 million. The

Minnesota jurisdictional reserve surplus was $265.2 million for the electric

utility offset by a reserve deficit of $4.0 million for common utility.

Q. WHAT WAS THE CHANGE IN DEPRECIATION THAT RESULTED FROM THE EIGHT-

YEAR AMORTIZATION?

A. The amortization of the Minnesota jurisdictional reserve surplus over an eight-

year period results in an annual decrease in depreciation expense of $32.7

million. The amortization will run from 2013 through 2020. The rate base

over this eight-year period will increase by $261.2 million. In the ninth year,

the amortization will be done and depreciation expense will increase by a

minimum of $32.7 million, without factoring in any changes in plant balances.

Q. HAVE YOU INCORPORATED THE CHANGES IN SERVICE LIVES AND NET

SALVAGE FROM THE STUDY IN THE DEPRECIATION RATES USING THE WHOLE

LIFE METHODOLOGY IN THIS CURRENT CASE?

A. Yes. The overall change to depreciation in 2014, based on the changes to lives

and net salvage rates in the study, is an increase of $12,727,398 on a Minnesota

jurisdictional basis. That increase is the amortization of the overall reserve

surplus of $32,654,856 on a Minnesota jurisdictional basis, which is a

continuation of the eight-year amortization approved by the Commission in

the 2013 rate case. The two changes result in a net decrease in depreciation

expense of $19,927,458 for the Minnesota jurisdiction. The rate case impact is

calculated on monthly balances throughout 2014, and the depreciation study is

based on beginning 2013 plant balances. Thus, the depreciation change will be



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different in the study compared to the rate case. Table 1 below shows the

amortization in combination with the change in depreciation rates for the test

year.

Table 1

Proposed 2014 TD&G Depreciation Expense

Depreciation

(Total Company)

Depreciation (MN

Jurisdiction)

Amortization of Surplus (MN Jurisdiction)

Total (MN Jurisdiction)

Electric Utility Intangible - - (45,632) (45,632)Transmission (6,090,710) (4,527,826) (18,699,675) (23,227,501)Distribution 18,578,011 18,578,011 (13,670,294) 4,907,717General Plant (1,334,043) (1,168,873) (736,089) (1,904,962)

Total Electric 11,153,258 12,881,312 (33,151,690) (20,270,378)Common Utility

Intangible - - 123,267 123,267 General Plant (189,739) (153,914) 373,567 219,653

Total Common (189,739) (153,914) 496,834 342,920 Total 10,963,519 12,727,398 (32,654,856) (19,927,458)

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Q. HAVE THESE PROPOSED CHANGES BEEN INCORPORATED INTO THE CURRENT

TEST YEAR?

A. Yes. Using the depreciation rates proposed in our October 1, 2013

supplement in No. E,G002/D-12-858, we incorporated the effect of the

depreciation expense change into the 2014 test year. If the Commission’s

order in that proceeding results in a different 2013 depreciation expense

amount, we will incorporate the approved depreciation expense into the final

revenue requirement in this rate case.



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B. Multi-Year Rate Plan Depreciation Analysis

Q. WHAT TD&G ASSETS ARE BEING ADDED DURING 2014 AND 2015, THE YEARS

INCLUDED IN THE COMPANY’S PROPOSED MULTI-YEAR RATE PLAN?

A. There are 92 TD&G projects included in 2014 and 17 projects in 2015. These

projects are summarized in Exhibit___(LHP-1), Schedule 8. This Schedule

includes new projects in 2014, and for 2015 it includes both new additions in

2015 and the annualized effect of certain additions in 2014. This information

is responsive to Information Request DOC-133 in our 2013 rate case.

Q. PLEASE DESCRIBE THE PROCESS USED TO IDENTIFY DEPRECIATION CHANGES

THE COMPANY ANTICIPATES FOR 2015 AND THE TWO YEARS FOLLOWING THE

PLAN, 2016 AND 2017.

A. We are required to analyze the effect of the multi-year rate plan projects on

depreciation expense for 2015 through 2017. For this period, we propose the

following:

• no further change to the current average service lives and net salvage

rates for transmission and distribution assets;

• a 15-year amortization period for the new general ledger system,

Common Intangible plant; and

• no further change to the current average service lives and net salvage

rates for general assets.

Q. PLEASE GENERALLY DESCRIBE THE NEW GENERAL LEDGER SOFTWARE

SYSTEM.

A. The new general ledger software will go into service in 2015 for $27.7 million

and will be recorded to Common Intangibles. (See Company witness Mr.

David C. Harkness’ testimony for a complete description of the general ledger



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software.) This is a replacement of the current JD Edwards general ledger and

it is part of an overall project called Productivity Through Technology (PTT)

initiative.

Q. PLEASE DISCUSS YOUR PROPOSED AMORTIZATION PERIOD FOR THE NEW

GENERAL LEDGER SYSTEM.

A. The Company currently assigns software systems an amortization period of

three, five, seven, or ten years depending on the system. Currently,

workstation operating systems are assigned the shorter three-year amortization

period while the underlying large base systems, such as the billing system, are

assigned the ten-year amortization period. Supporting systems to the base

systems are assigned a seven-year amortization with all other systems being

assigned a five-year amortization.

The new general ledger is a large base system, which is expected to be used

over a 15-year period rather than the longest period used today of ten years.

This longer amortization period is based on the current system’s useful life.

The current system was originally installed in 2001 and will be replaced in

2015. The current system will continue to be in use for a short time after

replacement to ensure access to historical information for that time.

Therefore, we recommend the use of a 15-year amortization.

Q. IS THIS RECOMMENDATION INCLUDED IN THE 2014 TEST YEAR REVENUE

REQUIREMENT?

A. Yes. This proposed amortization was included in the 2014 budget. However

there was a revision to the estimated in service date, which moved from

December 2015 to June 2015. Therefore, Ms. Heuer, in her Direct Testimony,



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includes an adjustment to reflect this change to the 2015 revenue requirement.

A schedule showing the total Company calculation of the depreciation expense

is provided as Exhibit___(LHP-1), Schedule 10.

C. Reserve Surplus Rate Moderation Proposal

Q. HAS THE COMPANY IDENTIFIED AN ALTERNATIVE METHOD FOR THE

REMAINING TD&G RESERVE SURPLUS?

A. Yes. The Commission approved an eight-year amortization of the $261.2

million reserve surplus beginning in 2013. At the beginning of 2014, there is

$228.5 million remaining to be amortized over the next seven years. We

believe it may be appropriate to amortize the remaining reserve surplus over a

shorter period to moderate the rate increases for our customers over the next

few years. We propose to amortize the remaining reserve surplus over three

years using a declining pattern of 50 percent in 2014, 30 percent in 2015, and

20 percent in 2016.

Q. HOW DOES THE DECLINING PATTERN FIT WITH THE GENERAL USE OF

STRAIGHT-LINE DEPRECIATION?

A. Generally, depreciation allocates an asset’s cost evenly over the useful life of

the asset. This is known as the straight-line method. Minnesota Rules

prescribe use of the straight-line method for depreciation, but also allow for

exceptions, giving the Commission discretion to approve a deviation from this

method if justified:

Part 7825.0800 Methods for Depreciation Certification Studies. The commission prescribes the straight-line method for calculating depreciation, excluding depletion, accruals. Depletion costs should be allocated on the basis of the unit-of-production method. Any



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exceptions to these methods will require specific justification and certification by the commission.

We believe our proposed declining pattern for amortization of the remaining

reserve surplus is allowed under the rule.

Q. HOW DOES THE DEPRECIATION EXPENSE IN 2014 BASED ON THE DECLINING

PATTERN COMPARE WITH THE EIGHT-YEAR AMORTIZATION?

A. Under the declining pattern, the remaining Minnesota jurisdiction surplus

reserve of $228,583,990 is reduced by 50 percent, or $114,291,995, in 2014.

Table 2 below compares this to the straight-line eight-year amortization

approved in the 2013 rate case.

Table 2

Amortization of Theoretical Reserve Surplus Comparison Change in Depreciation Expense for 2014

(Based on Depreciation Expense Approved in 2013 Rate Case)

Approved Eight-Year

Amortization

Proposed Declining Pattern Difference

Electric Utility Intangible (45,632) (159,711) (114,079)Transmission (18,699,675) (65,448,861) (46,749,186)Distribution (13,670,294) (47,846,029) (34,175,735)General Plant (736,089) (2,576,313) (1,840,224)

Total Electric (33,151,690) (116,030,914) (82,879,224)Common Utility

Intangible 123,267 431,434 308,167 General Plant 373,567 1,307,485 933,918

Total Common 496,834 1,738,919 1,242,085 Total (32,654,856) (114,291,995) (81,637,139)

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Q. WHAT IS THE PROPOSED OVERALL CHANGE IN DEPRECIATION EXPENSE FOR

2014?



A. Our proposed change to depreciation expense in 2014 for changes to lives and

net salvage rates is an increase of $10,963,519 on a total Company basis

($12,727,398 for Minnesota electric jurisdiction).

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3 This is offset by the overall

reserve surplus of a negative $114,291,995. The two changes net to a decrease

in expense of $101,564,597 for the Minnesota jurisdiction. Table 3 shows the

declining pattern method in combination with the change in depreciation

rates.

Table 3 Amortization of Theoretical Reserve Surplus

Change in Depreciation Expense for 2014 (Based on Declining Pattern of Amortization and Proposed Depreciation Expense for 2014)

Depreciation

(Total Company)

Depreciation (MN

Jurisdiction)

Amortization of Surplus (MN Jurisdiction)


Electric Utility Intangible - - (159,711) (159,711)Transmission (6,090,710) (4,527,826) (65,448,861) (69,976,687)Distribution 18,578,011 18,578,011 (47,846,029) (29,268,018)General Plant (1,334,043) (1,168,873) (2,576,313) (3,745,186)


Intangible - - 431,434 431,434 General Plant (189,739) (153,914) 1,307,485 1,153,571 Total Common (189,739) (153,914) 1,738,919 1,585,005

Total 10,963,519 12,727,398 (114,291,995) (101,564,597) 9

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Q. IS THIS CHANGE INCLUDED IN THE 2014 TEST YEAR REVENUE REQUIREMENT?



3 The Minnesota jurisdictional cost is higher than the total Company cost because Distribution is directly allocated, and the increase in cost is subject to the lower offset amounts at the jurisdictional level.



to the 2014 revenue requirement. A schedule showing the total Company

calculation of the depreciation expense is provided as Exhibit___(LHP-1),

Schedule 11. This schedule is responsive to Information Requests DOC-137

from our 2013 rate case.

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Q. WHAT IS YOUR PROPOSED OVERALL CHANGE IN DEPRECIATION EXPENSE FOR

2015?

A. Our proposed change to depreciation expense in 2015 for changes to lives and

net salvage rates is an increase of $11,131,975 on a total Company basis

($13,012,549 for Minnesota electric jurisdiction).4 This is offset by the overall

reserve surplus amortization of a negative $68,575,198. The two changes

together total a decrease in expense of $55,562,649 for the Minnesota

jurisdiction. Table 4 shows the declining pattern method in combination with

the change in depreciation rates.

4 The Minnesota jurisdictional cost is higher than the total Company cost because Distribution is directly allocated, and the increase in cost is subject to the lower offset amounts at the jurisdictional level.



1 Table 4

Amortization of Theoretical Reserve Surplus Change in Depreciation Expense for 2015

(Based on Declining Pattern of Amortization and Proposed Depreciation Expense for 2015)

Depreciation

(Total Company)

Depreciation (MN

Jurisdiction)

Amortization of Surplus

(MN Jurisdiction)


Electric Utility Intangible - - (95,827) (95,827)Transmission (6,427,956) (4,756,488) (39,269,317) (44,025,805)Distribution 19,136,802 19,136,802 (28,707,618) (9,570,816)General Plant (1,395,620) (1,220,955) (1,545,788) (2,766,743)


Intangible - - 258,861 258,861General Plant (181,251) (146,810) 784,491 637,681

Total Common (181,251) (146,810) 1,043,352 896,542Total 11,131,975 13,012,549 (68,575,198) (55,562,649)

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IV. NUCLEAR DECOMMISSIONING COSTS

Q. WHAT IS NUCLEAR DECOMMISSIONING?

A. Nuclear decommissioning is the method used to accumulate the final removal

costs for the three nuclear units. The amounts collected through general rates

are funded externally in a trust fund per Nuclear Regulatory Commission

rules. The annual accruals are calculated from a detailed engineering estimate

to removal the plant and to store the fuel until the federal government takes

possession of all the fuel assemblies.



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A. 2011 Triennial Nuclear Decommissioning Study

Q. PLEASE DESCRIBE THE DECOMMISSIONING FUND ACCRUAL APPROVED IN

DOCKET NO. E002/M-11-939 AND THE RESULTING 2014 TEST YEAR

DECOMMISSIONING EXPENSE.

A. On December 4, 2012, the Commission issued its Order approving our 2011

Triennial Nuclear Decommissioning Study in Docket No. E002/M-11-939

with changes to be effective January 1, 2013. The order approved a $14.2

million annual accrual for nuclear decommissioning for 2012, 2013, and 2014.

The Commission also approved funding the 2013 and 2014 accruals using the

DOE settlement payments received in 2012 and 2013 rather than through

additional funds to be collected from customers. Thus, the 2014 test year

funding requirement will be satisfied through the DOE settlement payment

received in 2013 rather than through higher base rates for customers. This is

the same treatment approved in our 2013 rate case.

Q. WHAT IS THE AMOUNT OF THE DOE SETTLEMENT PAYMENT THAT WILL BE

RECEIVED IN 2013 TO OFFSET THE 2014 NUCLEAR DECOMMISSIONING

ACCRUAL?

A. Our current estimate for the DOE settlement payment we expect to receive in

late 2013 for the 2014 accrual is $31.8 million. This estimated payment will be

sufficient to cover the entire accrual amount with an excess of $17.6 million.

Q. WHEN WILL THE COMPANY FILE ITS NEXT TRIENNIAL DECOMMISSIONING

STUDY?

A. Our next triennial decommissioning study is due October 1, 2014. Any

changes proposed would be effective for the period of 2015-2017.



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B. Multi-Year Rate Plan Decommissioning Analysis

Q. HAVE YOU FACTORED INTO THE 2015 TEST YEAR ANY CHANGES YOU EXPECT

TO INCLUDE IN THE 2014 TRIENNIAL STUDY?

A. No. We are in the early stages of preparing the next triennial filing and do not

have information that would support a change from the accrual approved in

our last filing. Therefore, we are not proposing any change in accrual for 2015

as part of our multi-year rate plan.

Q. PLEASE DESCRIBE HOW THE DECOMMISSIONING ACCRUAL WOULD CARRY

FORWARD THROUGH THE MULTI-YEAR RATE PLAN.

A. We propose the decommissioning accrual remain at $14.2 million for 2015.

Our current estimate for the DOE settlement payment that will be received in

late 2014 for the 2015 accrual is $32.4 million. This payment will be sufficient

to cover the entire accrual. Thus, the 2015 funding requirement would be

satisfied through the DOE settlement payment from 2014, rather than

through higher base rates for customers. The estimated DOE payment will be

sufficient to cover the entire accrual amount with an excess of $18.2 million.

Q. PLEASE DESCRIBE HOW THE DECOMMISSIONING ACCRUAL WOULD CARRY

FORWARD THROUGH 2016 AND 2017.

A. As we currently do not have enough information to make a change, we

forecast the nuclear decommissioning accrual continuing at $14.2 million for

2016 and 2017.



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C. DOE Settlement Payment Rate Moderation Proposal

Q. PLEASE DISCUSS THE TREATMENT OF DOE PAYMENTS IN EXCESS OF THE

CURRENT ANNUAL DECOMMISSIONING ACCRUAL.

A. The Commission’s December 12, 2012 Order directed that to the extent the

DOE settlement proceeds in 2012 and 2013 exceed the annual accrual

amounts, the excess must be placed into the decommissioning escrow fund.

Q. IS THE COMPANY PROPOSING AN ALTERNATIVE USE OF THE EXCESS DOE

FUNDS?

A. Yes. On October 22, 2013, we filed a request for a modification of one order

provision in Docket Nos. E002/M-11-939 and E002/M-11-807. In that

filing, we requested that the Commission allow the portion of the 2013 DOE

payment in excess of the annual accrual amount for 2014 to be temporarily

placed into a separate escrow account rather than into the decommissioning

fund. If approved, this would preserve the option for the Commission to

make a determination on the appropriate use of these funds in this case. Our

rate moderation proposal in this case incorporates the use of approximately

$35.7 million in excess DOE settlement payments (approximately $17.5

million in 2013 and $18.2 million in 2014). A discussion of the excess DOE

settlement payments and a comparison of the payments against the annual

accruals is provided in our October 22, 2013 filing. A schedule showing the

calculation is provided as Exhibit___(LHP-1), Schedule 12.

V. COMPLIANCE ITEMS

A. Nuclear Plant Theoretical Reserve

Q. WHAT INFORMATION DO YOU PRESENT IN THIS SECTION?



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A. I provide information in compliance with the Commission’s Order in our

2013 rate case requiring that the Company investigate whether there is a

depreciation reserve surplus for our nuclear production assets. Specifically,

Order Point 12 states:

12. Xcel shall explore with the parties to its next rate case whether there should be any adjustments to depreciation reserves for Xcel’s nuclear production assets.

The question of whether there is a nuclear theoretical reserve surplus stems

from the fact that each of our three nuclear units has received a license

extension. Depreciation rates were previously set to recover costs over the

initial expected lives of the units. Now that the remaining lives of these assets

have been extended, a theoretical reserve analysis would indicate if

depreciation has been over-recovered such that there is a depreciation reserve

surplus at this time. Below we present the results of our analysis for

consideration by the Commission and the parties in this case.

Q. WHAT IS A THEORETICAL RESERVE ANALYSIS?

A. A theoretical reserve analysis measures, at one point in time, the actual

depreciation reserve compared to the theoretical reserve. The theoretical

reserve is the reserve that would exist if all the facts that go into the

depreciation calculation that are currently known were known at the time the

asset was placed into service. For example, if an asset initially had a 10-year

life and the asset has been in service for five years, the depreciation reserve

would be 50 percent of the asset cost. If at this point the life were extended

10 years to a total of 20 years, the theoretical reserve would estimate that 25

percent of asset costs should have been recovered to that point (over five of

the total 20-year life of the asset), even though 50 percent of asset costs would



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actually have been recovered. In this example, there is a reserve surplus equal

to 25 percent of the asset costs.

Q. DOES A RESERVE SURPLUS INDICATE THERE IS AN ISSUE THAT NEEDS TO BE

ADDRESSED?

A. Not necessarily. The Company will recover 100 percent of the asset cost

regardless of the theoretical reserve calculated at any one point in time. For

our nuclear assets, like all of our production assets, we used a remaining life

depreciation methodology, which automatically spreads any reserve surplus or

deficit evenly over the remaining life of the asset. If a reserve surplus or

deficit is significant, such that different treatment would be warranted, the

reserve surplus could be amortized over a period different than the remaining

life of the asset.

Q. HOW IS A THEORETICAL RESERVE CALCULATED?

A. The theoretical reserve calculation estimates what the current reserve balance

should be based on the percentage of the life to date in relation to the whole

life of the asset. The calculation also factors in future interim retirements and

interim net salvage costs along with final removal costs. Interim retirements

account for components of the unit that will be replaced before the unit’s end

of life. These components have a shorter overall life than the entire unit does,

and the theoretical reserve calculation accounts for the retirement of these

components.

Q. HOW DID THE COMPANY CALCULATE A THEORETICAL RESERVE SPECIFICALLY

FOR ITS NUCLEAR PLANTS?



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A. To calculate a nuclear reserve surplus or deficit, the Company reviewed the

future expected interim removal costs and interim retirements to determine if

the current reserve was sufficient to provide for these future transactions. The

current plant and reserve balances also factored into this calculation. We

conducted two separate reviews, one for Monticello and one for Prairie Island.

First, we compare the average age of a group of assets to the average whole

life of that group of assets, by FERC 300-series account. Second, we adjust

that ratio to factor in interim removal and retirement costs. This percentage is

then applied to the current plant balance, or total asset costs, to determine the

theoretical reserve. I note that for other production assets, the interim

removal factor is included with the final removal factor; however, nuclear final

removal costs are accounted for separately through the nuclear

decommissioning accrual and thus do not affect the theoretical reserve

calculation.

Q. WHAT ARE THE RESULTS OF YOUR ANALYSIS?

A. Our analysis indicates that as of December 31, 2012, our nuclear production

plants have a total theoretical reserve balance of $1,260,417,415 and a total

actual reserve balance is $1,357,887,703, resulting in a reserve surplus of

$97,470,288 on a total Company basis. Table 5 below shows the breakdown

by plant.



1 Table 5

Nuclear Plant Theoretical Reserve Balance

Plant Actual Reserve

Theoretical Reserve Difference

Monticello $439,096,433 $515,265,652 $(76,169,219) Prairie Island 918,791,270 745,151,763 173,639,507 Total $1,357,887,703 $1,260,417,415 $97,470,288

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A detailed analysis of the theoretical reserve is provided as

Exhibit___(LHP-1), Schedule 13. This Schedule is responsive to the

following Information Requests from our 2013 rate case: XLI-204 and XLI-

211 through 216.

Q. WHAT ACCOUNTS FOR THE RESERVE SURPLUS FOR THE PRAIRIE ISLAND

PLANT?

A. The primary driver of the reserve surplus for Prairie Island is the fact that

between 1994 and 2003, the remaining life for the plant was kept 6.5 years

shorter than its approved NRC license life. As discussed in our 1993 Review

of Remaining Lives (Docket No. E,G002/D-93-1247), due to a change in

state law, during that period there was significant uncertainty regarding the

Company’s ability to store enough dry spent nuclear fuel on-site to support

operations until the end of its approved license life. As this situation could

have caused early retirement of the Prairie Island plant, the Company

requested, and the Commission approved, that costs be recovered over a

shorter period to minimize potential financial risk to the Company.

Q. WHAT ARE THE EFFECTS OF USING THE SHORTENED REMAINING LIFE FOR

PRAIRIE ISLAND?



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A. Because the asset costs were being recovered over a shorter period, the

accumulated depreciation balance is currently higher than it would otherwise

have been. The higher accumulated depreciation balance leads to a lower rate

base for the Prairie Island plant. With a lower rate base, customers have been

paying a lower return on rate base. In addition, because we use the remaining

life depreciation methodology for our nuclear plants, the reserve surplus is

automatically spread over the remaining life of the plant, which lowers future

depreciation costs.

Q. WHAT IS THE EFFECT OF THE RESERVE DEFICIT FOR MONTICELLO?

A. The remaining life depreciation methodology automatically spreads the reserve

deficit for Monticello over the remaining life of the plant, which increases

future depreciation costs.

Q. COULD THE PRAIRIE ISLAND RESERVE SURPLUS AND MONTICELLO RESERVE

DEFICIT BE NETTED TO CALCULATE AN OVERALL NUCLEAR DEPRECIATION

RESERVE?

A. Yes. Because plants are in the same functional class (nuclear), FERC

accounting rules would allow a transfer of some portion of the Prairie Island

surplus to offset all or a portion of the Monticello deficit. This would

rebalance the theoretical reserves at this point in time, and would decrease

depreciation costs for Monticello and increase depreciation costs for Prairie

Island going forward.

Q. ARE FUTURE EXPECTED ADDITIONS AT THE NUCLEAR PLANTS INCLUDED AS A

PART OF THE THEORETICAL RESERVE ANALYSIS?



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A. No. Future additions do not directly factor into the calculation of the

theoretical reserve. However, the future additions will cause the depreciation

expense to steadily increase as each addition will be depreciated over an ever-

shorter remaining life. In this way, future additions, like interim removal costs,

add to the depreciation collected in the future – additions will add to the plant

balance, and interim removal costs will lower the depreciation reserve balance.

Q. WHAT IS THE EXPECTED TREND FOR NUCLEAR DEPRECIATION COSTS GOING

FORWARD?

A. Due to significant recent and planned investment in nuclear assets, there is a

sizeable expected increase in depreciation over the remaining lives of these

assets. We expect that over the remaining lives of the units, depreciation will

increase by approximately $1.4 billion compared to the current depreciation

expense.

Q. WHAT WOULD BE THE RESULT IF THE CURRENT RESERVE SURPLUS WAS

AMORTIZED OVER A SHORT PERIOD OR REFUNDED TO CUSTOMERS?

A. Any reduction in the current reserve due to use of the theoretical reserve

surplus would cause an increase in the depreciation to be paid by customers in

the future. As an example, Figure 1 below shows the effect over time on

depreciation expense if the approximately $174 million theoretical reserve

surplus for Prairie Island is removed.



1 Figure 1

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Year

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epre

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($s

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SurplusRemoved

SurplusIncluded

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The effect on future depreciation expense is more pronounced for a nuclear

production asset than, for example, a group of transmission, distribution, or

general assets. While the transmission, distribution, and general asset groups

consist of many individual assets, with assets continually coming into service

and being retired, a production plant has a finite life over which it will be

depreciated. If the nuclear reserve surplus is paid to customers over a short

period of time now, that amount will have to be recovered in the future,

increasing depreciation costs over the remaining life of the asset even higher

than it is currently expected to increase. This is the difference between the

two curves shown above.

Q. IN THE LAST RATE CASE YOU TESTIFIED THAT AMORTIZING THE NUCLEAR

SURPLUS COULD BURDEN FUTURE RATEPAYERS WITH PAYING FOR INTERIM

RETIREMENTS AND REMOVAL. IS THAT STILL A CONCERN?

A. Yes. In our analysis, we have factored into our estimate interim retirements

and removals to attempt to address this concern. However, there is still

concern that a refund based on this estimate may cause depreciation to



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increase faster in the future if these estimates are below what is realized.

Although not part of the calculation for theoretical reserve, the impact future

additions have on depreciation is also a concern.

B. AFUDC and CWIP

Q. WHAT INFORMATION DO YOU PRESENT IN THIS SECTION?


2013 rate case regarding CWIP and AFUDC. Specifically, Order Point 52

states:

In the initial filing in its next rate case, Xcel shall provide evidence of FERC’s accounting requirements for CWIP/AFUDC and demonstrate that it has met the FERC requirements. It shall also address whether a minimum dollar level should be set for projects placed in CWIP.

Below, I provide information on the FERC required formula for calculating

the AFUDC rate for accounting purposes and demonstrate that the Company

calculates and applies the AFUDC rate consistent with FERC accounting

requirements. This portion of my testimony is supported by Company

witness Mr. James K. Guest, an expert on FERC accounting practices related

to AFUDC.

I also discuss the appropriate thresholds for projects in CWIP, explaining how

the long-standing Commission practices of including CWIP in rate base with

an AFUDC offset combined with accumulation and capitalization of AFUDC,

reflect an appropriate balance for recovering investment costs during

construction.



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As a basis for this discussion, I first present background information on CWIP

and AFUDC.

1. Background

Q. WHAT IS THE PURPOSE OF CWIP AND AFUDC?

A. CWIP is the accumulation of construction costs that directly relate to putting a

fixed asset into use. AFUDC is used to account for the cost of financing

during construction.

Many projects require planning and construction periods. In general, CWIP

assets are not generating current period revenue regardless of how they are

treated in rate base. Until the assets go into service, the utility must fund the

capital expenditures. The Company’s cost of financing during the

construction period is deferred through the recognition of AFUDC and added

to the cost of construction.

This deferral effectively delays the recovery of such costs to the period when

the asset generates revenue, which begins with its in-service period. When the

project goes into service: a) the investment is moved out of CWIP and into

Plant In Service; b) AFUDC stops; and c) depreciation starts. At that point,

an asset is recovered in revenue requirements through the return on rate base

and depreciation expense.

Q. WHAT GOVERNS RATEMAKING TREATMENT AND CALCULATION OF CWIP AND

AFUDC IN MINNESOTA?

A. CWIP is included in rate base as authorized by Minn. Stat. § 216B.16, subd. 6.

Depending on the nature of the project, CWIP is offset by AFUDC as



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authorized by Minn. Stat. § 216B.16, subd. 6a. The AFUDC calculation is

based on a formula prescribed by FERC in the Uniform System of Accounts,

Plant Instructions Section 3 Components of Construction Costs, (17)

Allowance for Funds Used During Construction. The rate used is based on a

two-step calculation, where short-term debt is used first and, upon exhaustion

of the short-term debt amounts, a weighted blend of long-term debt and

common equity is applied.

Q. PLEASE GENERALLY DESCRIBE HOW COSTS OF FINANCING CONSTRUCTION

AND CWIP ARE TREATED FOR RATEMAKING PURPOSES?

A. Different jurisdictions use different mechanisms to compensate investors

during the construction period. AFUDC accumulates to the CWIP work

order throughout the construction period and is capitalized and recovered

over the life of the asset.

Jurisdictions (like Minnesota) that allow CWIP in rate base also have a revenue

requirement offset of AFUDC incurred in the year, which effectively

eliminates the cost of financing construction from the revenue requirement

during the construction period. This method allows for a small revenue

requirement on the amount of CWIP that does not accrue AFUDC (as I

discuss further below, these are short-term projects lasting less than a month

or small dollar projects). The full return on these exceptions is justified

because the asset will be in-service by the time the rate case ends, and a return

on those assets is included in current rates.

Jurisdictions (like FERC) that generally do not allow CWIP in rate base

without a specific request for that treatment, do not need to offset the cost of



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a current return on CWIP and therefore do not need an AFUDC offset in

their revenue requirement calculation. However, AFUDC accumulates to the

CWIP work order throughout the construction period and is capitalized and

recovered over the life of the asset.

Under either practice, the utility is allowed to include accumulated AFUDC in

the final cost of the asset at the end of construction.

Q. WHAT IS THE PURPOSE OF ACCUMULATING AFUDC WHEN THERE HAS BEEN

AN AFUDC OFFSET?

A. With CWIP in rate base, it earns a return. Without an AFUDC offset, a

current return on CWIP occurs. The purpose of combining the AFUDC

offset with the accumulation and capitalization of AFUDC is to avoid the cost

of the current return on CWIP and at the same time include these financing

costs in the total cost of the project. By offsetting AFUDC combined with

capitalization of these same costs, these costs are deferred and amortized over

the life of the asset after being placed in-service through the recording of book

depreciation expense.

Q. ARE THERE EXCEPTIONS TO THE COMMISSION’S GENERAL PRACTICE FOR

HANDLING CWIP AND AFUDC?

A. Yes. There is no AFUDC offset:

1) where the Commission authorizes a current return for the project (e.g.

transmission and renewable energy projects); and

2) for projects that are low cost (less than $25,000) and short-term (less

than 30 days).



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Q. PLEASE DESCRIBE HOW TRANSMISSION AND RENEWABLE ENERGY PROJECTS

ARE HANDLED.

A. For these types of very large construction projects, Minnesota allows the utility

to include CWIP in rate base without an AFUDC offset. This allows the

utility to earn revenue to compensate it for having to finance these very large

construction projects, thus avoiding a large increase in the cost of financing at

the utility. For these specific projects only, AFUDC is not accumulated and

capitalized because of the allowed current return. The Minnesota TCR

mechanism is an example of such a regulatory process, which was adopted to

facilitate the construction of the CapX2020 and other large transmission

projects needed, among other things, to facilitate the delivery of wind

generation to our customers. Minn. Stat. § 216B.16, Subd. 6a, allows a current

return on CWIP on a case-by-case basis.

Q. OTHER THAN FOR PROJECTS RECOVERED THROUGH THE TCR MECHANISM, IS

THE COMPANY SEEKING A RETURN ON CWIP WITHOUT AN AFUDC OFFSET?

A. No. The Company is not seeking a return on CWIP without an AFUDC

offset. Therefore, the standards articulated in Section 216B.16, subd. 6a, used

to evaluate requests for such ratemaking treatment, are not applicable. I

believe this answer is responsive to Information Requests OAG-73 and OAG-

74 from our 2013 rate case.

2. AFUDC Rate Calculation

Q. WHAT ARE THE FERC REQUIREMENTS FOR CALCULATING THE AFUDC RATE?

A. As also explained by Mr. Guest, the AFUDC rate is based on a formula

prescribed by FERC in the Uniform System of Accounts, Plant Instructions

Section 3 Components of Construction Costs, (17) Allowance for Funds Used



During Construction. That formula was adopted in FERC Order 561 issued

February 2, 1977

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5 and rehearing was denied in FERC Order 561-A issued

August 1, 1977. I provide copies of both Orders in Exhibit___(LHP-1),

Schedule 15.

As required by the FERC formula, the short-term debt rate is applied to the

CWIP balance up to the level of short-term debt outstanding. The remaining

CWIP balance in excess of outstanding short-term debt receives a rate that is

weighted proportionately to the long-term debt, preferred stock (if any), and

common equity in the utility’s capital structure.

This two step process has been explained in a treatise as follows:

A brief analysis of the FERC formula and its instructions reveal several important points. First, the formula assumes that a utility’s short-term debt is the first source of funds used for financing construction. The remainder of the construction is assumed to be financed out of long-term debt, preferred stock, and common stock equity on the basis of these funds as they existed at the end of the prior year. (Emphasis added.)6

As the highlighted language demonstrates, after exhausting short-term debt,

the remainder is assumed to be financed out of long-term debt, preferred

stock, and common stock equity. There is no provision for exhausting these

other financing mechanisms other than ratably.

The Company’s calculation of the AFUDC rate was the subject of a FERC

audit (Docket No. PA11-11-000). FERC, like Minnesota, allows certain large

5 See E002/GR-81-342, FINDINGS OF FACT CONCLUSIONS OF LAW AND ORDER, dated June 25, 1982, at 25; 75 P.U.R. 4th 538 at p. 15, ORDER dated June 2, 1986. 6 Robert L. Hahne & Gregory E. Aliff, Accounting for Public Utilities, vol. 1, § 4.04[5][b], 4-25 (Lexis, Nov. 2012).



transmission CWIP projects in rate base without an AFUDC offset (in other

words FERC allows a current recovery of the cost of capital for such projects).

FERC audited the AFUDC rate to ensure the Company had not received both

a current return on CWIP while also including capitalized AFUDC in rate base

for such projects. As discussed further by Mr. Guest, there was no finding by

FERC that the Company was miscalculating the AFUDC rate or the

application of the rate.

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Q. IS THE METHODOLOGY USED BY THE COMPANY IN THIS CASE THE SAME AS

USED IN PRIOR CASES?

A. Yes. The methodology used in this case to calculate AFUDC is the same as

used in every rate case since 1977, including Docket Nos. E002/GR-81-342

and E002/GR-85-558.7 The Company’s calculation of the AFUDC rate then

and now was calculated “in conformance with FERC Order 561 issued

February 2, 1977.”8

Q. PLEASE PROVIDE THE CALCULATION OF THE FERC AFUDC RATE USED IN

THIS FILING.

A. The calculation of the AFUDC rate is shown in Exhibit___(LHP-1), Schedule

14. This schedule links our calculation directly to the method definition

provided in the FERC plant instructions.

Q. PLEASE EXPLAIN HOW THE FERC AFUDC RATE IS USED TO OFFSET THE COST

IN THE TEST YEAR.

7 G002/GR-92-1186, FINDINGS OF FACT CONCLUSIONS OF LAW, AND ORDER, dated September 1, 1993, at 9 8 E002/GR-81-342, FINDINGS OF FACT CONCLUSIONS OF LAW AND ORDER, dated June 25, 1982, at 25; 75 P.U.R. 4th 538 at p. 15, ORDER dated June 2, 1986; Tr. Vol. 2 at 191 (Perkett).



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A. This is accomplished by adding the amount of AFUDC (AFUDC rate times

the average CWIP balance per month) to net operating income on the income

statement. In this current rate case, the $67.2 million of AFUDC was

calculated for 2014, total electric and common utility. The jurisdictional

portion, $58.1 million, is added to net income in the test year (thus lowering

the revenue requirement). Essentially, the AFUDC offset eliminates the

carrying costs associated with CWIP in the current revenue requirement.

AFUDC is added to construction and eventually the cost of plant. Through

depreciation expense, the cost of the plant asset, including the capital cost of

funding construction (AFUDC), is recovered. This increase to net income is

found in Volume 3, tab 4, Operating Income Schedules, Schedule A-1, line 23.

The combination of CWIP in rate base, adding AFUDC to net operating

income (the AFUDC offset), and combined with the accumulation and

capitalization of AFUDC results in the deferral of construction period

financing costs during the construction period. These deferred investment

costs are recovered over the useful life of the asset through the recording of

book depreciation expense on the total asset investment, including AFUDC

recorded during the construction phase.

Q. WOULD A LOWER AFUDC RATE BE IN RATEPAYER INTEREST IN THE TEST

YEAR?

A. No. The underlying purpose of the AFUDC offset is to allow a utility to

record as income the financing costs associated with CWIP and at the same

time, through the accumulation of AFUDC, to add these financing costs

associated with CWIP to the total cost of the project. Including AFUDC as a

revenue offset effectively eliminates CWIP financing costs from a current

recovery.



As recognized by the Commission in our 1985 rate case, having an AFUDC

rate that approximates the cost of capital benefits ratepayers:

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The Commission further finds that including long-term CWIP in rate base with an AFUDC offset has an overall beneficial impact on ratepayers. In addition, calculating the AFUDC amount with a rate derived from the FERC Order No. 561 method provides an effective offset to the revenue requirement resulting from including long-term CWIP in rate base.9 (Emphasis added.)

Using a lower AFUDC rate would not provide “an effective offset” to CWIP

in rate base. A lower AFUDC rate would increase the revenue requirement

because CWIP would remain in rate base and a lower AFUDC amount would

result in a smaller addition to net income. In this current rate case, net income

was increased by $67.2 million ($35.0 million Minnesota jurisdictional) because

of the AFUDC offset. As the Commission observed, the FERC Order No.

561 rate is beneficial to ratepayers because it provides “an effective offset to

the revenue requirement” from including CWIP in rate base. The Company’s

AFUDC rate is properly based on FERC Order 561, and is beneficial to

customers.

3. Appropriate CWIP and AFUDC Thresholds

Q. HAS THE COMMISSION APPLIED A THRESHOLD FOR CWIP OR FOR APPLYING

AN AFUDC OFFSET?

A. All CWIP is placed in rate base. There has been no exclusion of less-costly,

short-term projects from rate base because such projects are quickly placed

into service and are providing service to customers at the time general rates are

in effect. More specifically, the policy in Minnesota is to include “short-term”

9 75 P.U.R. 4th 538 at 15, Docket No. E002/GR-85-558.



projects in rate base without an AFUDC offset. Because there is no AFUDC

offset, there is also no accumulation and capitalization of AFUDC for “short-

term” projects. “Short-term” projects have been defined by the Commission

as projects that will be completed in less than 30 days, or projects that will cost

less than $10,000. As explained in the Company’s 1985 rate case:

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With respect to short-term CWIP and an AFUDC offset to operating income, the Commission finds that in this proceeding as in past NSP electric rate case proceedings, short-term CWIP is defined as construction projects, which cost less than $10,000 or will be completed in less than 30 days. The Company has not booked any AFUDC on these types of construction projects nor included an AFUDC offset in operating income for these types of projects.

The Commission finds the Company’s practice appropriate and in accordance with the Commission’s prior ratemaking treatment of short-term CWIP. In NSP, Docket No. ER2-1, with respect to short-term CWIP, the Commission stated:

Because of these special characteristics, small and short-term construction projects would be more appropriately considered as a normal rate base item which is includable if used and useful in the provision of service. They satisfy the ‘used and useful’ test if their use is reasonably imminent. The Commission does not require AFUDC to be taken on these small and short-term construction projects because it does not believe that the legislature intended to include them within the term ‘construction work in progress’ under subdivision 6.

Q. DOES THE COMPANY COMPLY WITH THIS COMMISSION POLICY?

A. Yes. The Company complies with this long-standing policy. Under the

Company’s Uniform Policy on AFUDC, the threshold for including

10 E002/GR-85-558, Re Northern States Power, 75 P.U.R. 538, reaffirming a policy dating back to 1975.



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capitalized AFUDC has, with the passage of time, increased from $10,000 to

$25,000. Therefore, projects of less than 30 days duration or costing less than

$25,000 are placed directly into rate base and do not include a capitalized

AFUDC or an AFUDC offset.

Q. PLEASE ADDRESS THE COMMISSION REQUEST FOR A DISCUSSION OF WHETHER

A MINIMUM DOLLAR LEVEL SHOULD BE SET FOR PROJECTS PLACED IN CWIP.

A. The standard in Minnesota has been to include all investment in CWIP in rate

base but to exclude less costly, short duration projects from the AFUDC

offset and, consequently, from accumulating and capitalizing AFUDC. This

practice provides a balanced approach that properly includes all investment in

rate base while eliminating the additional cost of accumulated AFUDC for

projects that should be considered in service almost immediately.

Q. WHY IS THE AFUDC OFFSET COMBINED WITH CAPITALIZING AFUDC

IMPORTANT?

A. In combination, this defers the current financing costs for construction to the

period that the asset is in use by customers and generating revenue.

Accumulating AFUDC until the asset goes into service effectively defers the

costs for recovery to a future period, the period the asset is in use. In the

revenue requirement calculation, financing costs are included by calculating

the weighted cost of capital and multiplying that cost against rate base.

Regardless of the method chosen for CWIP in rate base, it is necessary to

reflect and recover the financing costs incurred during construction. Either

the inclusion of CWIP in rate base with an AFUDC offset and capitalization

of accumulated AFUDC or the exclusion of both CWIP and the AFUDC

offset, while still accumulating and capitalizing the AFUDC achieve the goal of



eliminating the construction financing costs from the current revenue

requirement.

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Q. IF CWIP WERE EXCLUDED FROM RATE BASE, WOULD CAPITALIZATION OF

AFUDC STILL BE NECESSARY?

A. Yes. If CWIP was excluded from rate base and capitalization of AFUDC was

not allowed, utilities would be providing free capital during construction for

those projects and the process would not allow the utility to ever recover these

costs during their useful life. Thus, the method of including CWIP and the

AFUDC offset in the revenue requirement calculation, in combination with

the accumulation and capitalization of AFUDC, accomplishes the following

objectives:

(1) The total cost of construction activities, including financing

costs, is fully recognized. (2) The utility operation is effectively shielded from costs

associated with certain construction activities. (3) The utility by capitalizing the financial costs is afforded an

opportunity to recover the costs when a plant is placed in service.11

Q. HAVE YOU IDENTIFIED DISCOVERY REQUESTS FROM THE PRIOR RATE CASE


A. Yes. I believe my testimony and Schedule 14 are responsive to the following

Information Requests from our 2013 rate cases: OAG-58, 65, 66, 67, 70, 70.1,

11 Robert L. Hahne & Gregory E. Aliff, Accounting for Public Utilities, Vol. 1, § 4.04 [5] (Lexis, Nov. 2012).



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and 71. In addition, I have included an updated response to Information

Request OAG-107 in Appendix A.

C. Capitalization of Transmission Studies

Q. WHAT INFORMATION RELATED TO TRANSMISSION STUDIES DO YOU PROVIDE

IN THIS SECTION OF YOUR TESTIMONY?


2013 rate case requiring that the Company provide details regarding

capitalization of costs associated with transmission studies. Specifically, Order

Points 55 and 56 state:

55. In the initial filing of its next rate case, Xcel shall include a discussion of its internal capitalization policy of cost related to transmission studies conducted for projects under contemplation and how its policy conforms to the prescribed FERC accounting under Account 183, Preliminary Survey and Investigation Charges. 56. In the initial filing of its next rate case, Xcel shall address the transmission studies included in its rate case and the basis for capitalizing or expensing each transmission study.

Below, I discuss how we implement FERC accounting policy. I also discuss

the basis for capitalizing or expensing each transmission study in the 2014 test

year.

Q. WHAT GUIDANCE DOES FERC PROVIDE TO DETERMINE IF STUDY COSTS CAN

BE CAPITALIZED?

A. FERC provides two instructions related to capitalization of study costs. The

first is in the Electric Plant Instructions, Part 3 Components of Construction

Cost:



(20) Studies includes the costs of studies such as nuclear operational, safety, or seismic studies or environmental studies mandated by regulatory bodies relative to facilities in server shall be charged to account 183, Preliminary Survey and Investigation Charges.

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The second is the definition of FERC Account 183: 183 Preliminary Survey and Investigation Charges (Major only) B. This account shall also include costs of studies and analysis mandated by regulatory bodies related to plant in service. If construction results from such studies, this account shall be credited and the appropriate utility plant account charged with an equitable portion of such study costs directly attributable to new construction. The portion of such study costs not attributable to new construction or the entire cost if construction does not result shall be charged to account 182.2 Unrecovered Plant and Regulatory Costs, or the appropriate operating expense account. The costs of such studies relative to plant under construction shall be included directly in account 107, Construction Work in Progress-Electric.

Q. HOW DOES THE COMPANY INITIALLY ACCOUNT FOR COSTS RELATED TO ITS

TRANSMISSION STUDIES?

A. Based on the FERC accounting rules and guidelines above, we first evaluate

the activity to which a study is related. If at inception a study is necessary and

directly required to achieve construction of a specific project, the Company

capitalizes the study costs directly into a CWIP account with the other project

related costs. Studies that clearly have no direct connection to construction

are expensed as incurred. Other studies, where the outcome is uncertain, are

placed in FERC Account 183, Preliminary Survey and Investigation Charges

and are evaluated to determine the probability that the study will result in a

capital addition once the study results are known.



Q. HOW DOES THE COMPANY REVIEW EACH TRANSMISSION STUDY TO

DETERMINE IF THE CHARGES SHOULD BE EXPENSED, CAPITALIZED, OR ARE

APPROPRIATE FOR INCLUSION IN FERC ACCOUNT 183?

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A. The Company reviews each study with Transmission personnel. This

evaluation includes a review of the primary purpose of the study, the triggering

event requiring the study, and the intended outcome of the study. If a study is

expected to result in capital additions, Transmission personnel provide the

reasons for and timing of such capital additions. The Company then evaluates

all available information to determine whether a direct link exists between the

study and the capital additions, while factoring in the timing between study

completion and capital additions. If there is a direct link between the study

and the expected capital additions, the costs are capitalized. If there is the

probability that a study will result in capital additions, the study costs are

placed into FERC Account 183. On a regular basis, we review the progress of

each study with Transmission personnel to determine if the expected outcome

of the study has changed.

Q. ONCE A STUDY HAS BEEN INCLUDED IN FERC ACCOUNT 183, HOW DOES THE

COMPANY THEN DETERMINE WHETHER TO CAPITALIZE OR EXPENSE THE

STUDY COSTS?

A. If upon conclusion of a study that has been accrued to FERC Account 183,

there are no plans for construction, the study is expensed. For other studies,

the Company reviews the study results with Transmission personnel. If the

study concludes a capital project is necessary and the project will begin shortly

after the conclusion of the study – generally within a few months – the study is

capitalized.



Q. WHY IS IT NECESSARY THAT TO CAPITALIZE STUDY COSTS, CONSTRUCTION

MUST BEGIN SHORTLY AFTER THE CONCLUSION OF THE STUDY?

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A. Costs are capitalized if they directly relate to construction being done. If a

study concludes long before construction begins, it is difficult to prove from

an accounting perspective that the study was directly related to construction.

The more time that passes between the conclusion of a study and the start of

construction, the more difficult it is to assign direct linkage between the two.

In addition, a study must identify a specific construction project rather than

present many possibilities under various circumstances. In other words, there

is no direct relationship to later construction if a study only presents potential

options. In order to capitalize a study, construction must begin shortly after

its conclusion and as a direct result of the study.

Q. WHAT ABOUT STUDIES OR ANALYSES TO DETERMINE FUTURE SYSTEM GROWTH

OR OTHER SYSTEM NEEDS, WHERE NECESSARY FACILITIES MAY BE IDENTIFIED

BUT CONSTRUCTION IS NOT LIKELY TO OCCUR UNTIL SOMETIME IN THE

FUTURE?

A. Studies that identify future needs but do not result in actual, specific

construction shortly after the study is completed are expensed. MISO

planning studies are an example of this type of study. Although necessary

future construction may be identified as a result of these studies, there are no

specific projects under which we could account for capital costs.

Q. WHAT REVIEW DID THE COMPANY PERFORM TO EVALUATE THE TRANSMISSION

STUDIES INCLUDED IN THE 2014 TEST YEAR BUDGET?

A. In his Direct Testimony, Company witness Mr. Daniel P. Kline describes two

types of required transmission studies – planning studies and project design



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studies – and provides examples of both types. We reviewed each study

included in the 2014 test year with Transmission personnel to determine the

intent of the study and applied the rules described earlier. We determined that

each study in 2014 is properly categorized as expense.

Q. WHAT IS THE AMOUNT OF O&M IN THE 2014 TEST YEAR FOR TRANSMISSION

STUDIES?

A. Provided as Exhibit___(LHP-1), Schedule 16 is the list of transmission

planning studies the Company plans to undertake in 2014 as provided by Mr.

Kline. In my exhibit, the accounting guidance that supports the expense

determination has been added.

In all, there are 18 studies with a total cost of $1.7 million on a total Company

basis. It was determined that 15 of these studies do not have a probability of

resulting in a specific capital project at the conclusion of the study. Since they

cannot be directly related to individual construction projects, they will be

expensed per FERC regulations. The other three studies (or analyses) are to

be conducted for the purpose of obtaining information on feasibility or need

for an outside entity, for strategic planning, for load analysis, or line loss

analysis. These three studies are properly expensed as strategic and planning

costs.

Q. ALTHOUGH NO PROJECT DESIGN STUDY IS IN THE 2014 TEST YEAR, CAN YOU

DESCRIBE HOW COSTS OF PROJECT DESIGN STUDIES WOULD BE ACCOUNTED

FOR?

A. During the course of construction of capital projects, studies may be necessary

to ensure a particular asset or project is completed successfully and with the



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appropriate scope of work. Mr. Kline’s Direct Testimony provides recent

specific examples of these types of studies. Often, studies are performed for

multiple projects and their costs allocated and capitalized to the individual

projects. As an example, Michigan Technological University performed a

study of “Computer Simulation of Transient and Dynamic Behaviors” for

numerous transmission projects in 2009. These studies included detailed

modeling and analysis of Xcel Energy’s electric power transmission system

and the studies were carried out during transmission system upgrade projects

on substations and transmission lines. The purpose of these analyses was to

define and confirm the validity of project designs and the specification and

ratings of equipment to be installed, such as circuit breaker ratings, reactor

ratings, capacitor bank switching duties, and shunt reactor switching

requirements. The costs of these studies were directly related to placing the

construction into service and they were capitalized to the individual projects.

D. CWIP and RWIP

Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

A. This section provides general information on CWIP and RWIP, both of which

are part or the life cycle of an asset. I provide this information as it underlies

the CWIP and RWIP costs included in the test year for projects that are

supported by other Company witnesses in this case.

Q. PLEASE EXPLAIN THE GENERAL BREAKDOWN BETWEEN CWIP AND RWIP.

A. CWIP is the work order system that tracks the costs to install a new asset or

replace an existing asset. RWIP is the work order system that tracks the

removal of an asset being retired. The two work order systems are related in



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that we are often replacing retiring assets with new assets. Thus, the RWIP

expenditures occur before the CWIP expenditures.

Q. COULD THESE TWO TYPES OF EXPENDITURES BE TRACKED WITHIN CWIP?

A. No. The result of the construction is a new plant asset which begins

depreciating over its useful life. RWIP costs result after the asset’s useful life

is over. Generally, the Company recovers the expectation of these costs as

part of the depreciation rate and accumulates the expected removal and

salvage costs in the accumulated depreciation. Therefore, the RWIP

expenditures are closed to the depreciation reserve instead of plant in service.

Q. IS RWIP INCLUDED IN RATE BASE?

A. Yes. RWIP is part of rate base and it does factor into the calculation of the

return on rate base. The actual costs to retire an asset are made up of two

components: removal and salvage. Removal costs decrease the accumulated

depreciation and, thus, increase rate base. Since the depreciation rate includes

an estimate of removal costs, the accumulated depreciation should be greater

than the original cost of the asset at retirement, or a negative rate base. When

the removal costs are spent, the rate base increases from the negative position

to zero. Salvage costs increase the accumulated depreciation and thus

decrease rate base. With salvage included in the depreciation rate, the

accumulated depreciation at retirement would be less than the original cost, or

the net rate base for the asset would be positive. When salvage costs are

realized, rate base is decreased to zero.

Q. IS AFUDC CALCULATED ON RWIP?



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A. No. The expected removal costs offset by the expected salvage costs are

recovered from customers through the depreciation rate while the asset is in

use. RWIP is a tracking method to spend what has already been recovered,

thus, there is no need to assign a time value of money to this balance.

Q. WHERE CAN THIS CWIP AND RWIP INFORMATION BE FOUND IN THE

COMPANY’S RATE CASE FILING DOCUMENTS?

A. A CWIP roll forward by grandparent project is shown in Workpaper P3A,

pages 1 to 74. RWIP is shown as part of the depreciation reserve roll forward

by functional class in Workpaper P3C, pages 1 to 6. Also included in these

workpapers is a roll forward for plant, Workpaper P3B, pages 1 to 4.

Q. HAVE YOU IDENTIFIED DISCOVERY REQUESTS FROM THE PRIOR RATE CASE


A. Yes. I believe this section responds to Information Request OAG-51 from

our 2013 rate case.

VI. CONCLUSION

Q. PLEASE SUMMARIZE YOUR TESTIMONY.

A. The depreciation expense for the 2014 test year and 2015 step increase is

consistent with our proposals in our pending depreciation proceedings. We

will also submit our 2014 Review of Remaining Lives to the Commission in

2014, and have incorporated changes we expect to include in that filing into

the revenue requirement in this case. If the Commission makes different

decisions in any of those proceedings, we will reflect those changes in final

rates in this current proceeding.



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In this case, we offer two rate moderation proposals: 1) the amortization of

the remaining surplus reserve for transmission, distribution and general assets

over three years, reducing the 2014 rate increase by approximately $81 million,

and the 2015 rate increase by approximately $30 million; and 2) using the

excess DOE settlement payments to reduce the 2015 rate increase by

approximately $31 million on a Minnesota jurisdictional basis.

In compliance with the Commission’s Order in our 2013 rate case, I have

provided information on the FERC required formula for calculating the

AFUDC rate for accounting purposes and have demonstrated that the

Company calculates and applies the AFUDC rate consistent with FERC

accounting requirements. Consistent with long-standing Commission practice,

including CWIP in rate base with an AFUDC offset, combined with

accumulation and capitalization of AFUDC, reflects an appropriate balance

for recovering investment costs during construction.

Also in compliance with the Commission’s Order in our 2013 rate case, I have

provided information on how the Company complies with FERC accounting

requirements for capitalizing transmission study costs.

Finally, I have provided general support information on CWIP and RWIP

costs.

Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

A. Yes, it does.


Northern States Power Company Docket No. E002/GR-13-868

Exhibit___(LHP-1), Schedule 1 Page 1 of 1

Statement of Qualifications Lisa H. Perkett

Education:

Bachelor of Science – Business 1979 University of Minnesota Certified Management Accountant – since 1995 Employment: Xcel Energy Services, Inc. 2000 – Present Director, Capital Asset Accounting Northern States Power Company 1994 – 2000 Director, Capital Asset Accounting 1990 – 1994 Manager, Capital Recovery 1987 – 1990 Principal Capital Recovery Analyst 1985 – 1987 Senior Depreciation Analyst 1982 – 1985 Depreciation Analyst 1981 – 1982 Associate Depreciation Analyst 1980 – 1981 Assistant Operations Analyst

Northern States Power Company Docket No. E002/GR-13-868 Exhibit___(LHP-1), Schedule 2

Page 1 of 2

Commission’s Order Points Addressed in Testimony

Order Point 3: The Company shall move from plant in-service to CWIP: 41.6 percent of the Monticello LCM/EPU costs for 2011 and 2012 additions added to the rate base in this case, 41.6 percent of 2013 May plant addition costs, and 100 percent of NRC fees, as well as the related depreciation reserve, deferred taxes, depreciation expense, AFUDC, and any other applicable costs. The Company may be allowed to recover those costs in future rate cases once the EPU is in service, subject to the plant being used and useful, and subject to a determination that the costs—including cost overruns—were prudent. Order Point 3, Monticello EPU, is addressed in Section II. DEPRECIATION FOR PRODUCTION ASSETS, Subpart A. 2012 and 2013 Review of Remaining Lives and Subpart B. 2014 Review of Remaining Lives. Order Point 7: The Commission approves deferred accounting for Sherco Unit 3’s 2013 depreciation expense. Order Point 7, Sherco Unit 3 deferred accounting for depreciation, is addressed in Section II. DEPRECIATION FOR PRODUCTION ASSETS, Subpart A. 2012 and 2013 Review of Remaining Lives. Order Point 8: The Commission accepts Xcel’s proposed 21-year remaining life of Sherco Unit 3 as a placeholder. Xcel shall have an engineer evaluate Sherco Unit 3 and provide that analysis in its next rate case. Order Point 8, Sherco Unit 3 remaining life, is addressed in Section II. DEPRECIATION FOR PRODUCTION ASSETS, Subpart B. 2014 Review of Remaining Lives. Order Point 11: Xcel shall amortize the difference between its actual and theoretical depreciation reserves for transmission, distribution, and general assets over a period of eight years. Order Point 11, Transmission, Distribution and General (TD&G) reserve surplus, is addressed in Section I. INTRODUCTION, Section III. DEPRECIATION FOR

Northern States Power Company Docket No. E002/GR-13-868 Exhibit___(LHP-1), Schedule 2

Page 2 of 2

TRANSMISSION, DISTRIBUTION, AND GENERAL ASSETS, Subpart A. 2012 TD&G Depreciation Study. Order Point 12: Xcel shall explore with the parties to its next rate case whether there should be any adjustments to depreciation reserves for Xcel’s nuclear production assets. Order Point 12, Nuclear assets reserve margins, is addressed in Section V. COMPLIANCE ITEMS, Subpart A. Nuclear Plant Theoretical Reserve. Order Point 52: In the initial filing in its next rate case, Xcel shall provide evidence of FERC’s accounting requirements for CWIP/AFUDC and demonstrate that it has met the FERC requirements. It shall also address whether a minimum dollar level should be set for projects placed in CWIP. Order Point 52, FERC accounting requirements for CWIP and Allowance for Funds Used During Construction (AFUDC), is addressed in Section V. COMPLIANCE ITEMS, Subpart B. AFUDC and CWIP. Order Point 55: In the initial filing of its next rate case, Xcel shall include a discussion of its internal capitalization policy of cost related to transmission studies conducted for projects under contemplation and how its policy conforms to the prescribed FERC accounting under Account 183, Preliminary Survey and Investigation Charges. Order Point 56: In the initial filing of its next rate case, Xcel shall address the transmission studies included in its rate case and the basis for capitalizing or expensing each transmission study. Order Point 55 and 56, Capitalization or Expense of Transmission Studies, are addressed in Section V. COMPLIANCE ITEMS, Subpart C. Capitalization of Transmission Studies

Black Dog Remediation Costs Roll Forward Schedule

Amortization Remediation

Costs Closure Costs

TotalRemoval

Costs Jurisdictional

Removal Costs

EndingRegulatory

Asset (Liability)

2013 1,649,201$ 2,700,000$ 2,700,000$ 2,014,861$ 365,660$ 2014 1,649,201$ 1,900,000$ 1,900,000$ 1,417,865$ 134,324$ 2015 1,649,201$ 2,500,000$ 2,500,000$ 1,865,612$ 350,735$ 2016 1,649,201$ 400,000$ 400,000$ 298,498$ (999,968)$ 2017 1,649,201$ 400,000$ 2,800,000$ 3,200,000$ 2,387,984$ (261,186)$ 2018 1,649,201$ 400,000$ 5,100,000$ 5,500,000$ 4,104,347$ 2,193,960$ 2019 1,649,201$ 400,000$ 5,100,000$ 5,500,000$ 4,104,347$ 4,649,106$ 2020 1,649,201$ 7,500,000$ 2,300,000$ 9,800,000$ 7,313,201$ 10,313,105$ 2021 1,649,201$ 600,000$ 600,000$ 447,747$ 9,111,651$ 2022 1,649,201$ 600,000$ 600,000$ 447,747$ 7,910,197$ 2023 1,649,201$ 450,000$ 450,000$ 335,810$ 6,596,805$ 2024 1,649,201$ 4,947,604$ 2025 1,649,201$ 3,298,403$ 2026 1,649,201$ 1,649,201$ 2027 1,649,201$ 0$

24,738,020$ 17,850,000$ 15,300,000$ 33,150,000$ 24,738,020$

Minnesota Jurisdictional Percent 74.62%

Total Anticipated Costs

Northern States Power Company

Docket No. E002/GR-13-868 Exhibit___(LHP-1), Schedule 3 Page 1 of 3

Black Dog Remediation Costs Sample Accounting

1 2 3 4 5 6 7 8 9 10 11 122013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec

Expected Total Company Costs 33,150,000 (a)Expected Minnesota Jurisdiction Costs 24,738,020 (b)

Spend Period 2012-2023 (c)Amortization Period 2013-2027 (d)

Annual Total Company Amortization 2,210,000 (e)Annual Minnesota Jurisdiction Amortization 1,649,201 (f)

Regulatory Asset (MN Jurisdiction)Beginning Balance - 365,660 134,324 350,735 (999,968) (261,186) 2,193,960 4,649,106 10,313,105 9,111,651 7,910,197 6,596,805 Regulatory Debit (Account 407.3) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) Cash Expenditures 2,014,861 1,417,865 1,865,612 298,498 2,387,984 4,104,347 4,104,347 7,313,201 447,747 447,747 335,810 - Ending Balance 365,660 134,324 350,735 (999,968) (261,186) 2,193,960 4,649,106 10,313,105 9,111,651 7,910,197 6,596,805 4,947,604

(1) Recognize Cash ExpendituresRegulatory Asset (MN Jurisdiction Only) (Acct 182.3) 2,014,861 1,417,865 1,865,612 298,498 2,387,984 4,104,347 4,104,347 7,313,201 447,747 447,747 335,810 -

Cash (Acct 131) (2,014,861) (1,417,865) (1,865,612) (298,498) (2,387,984) (4,104,347) (4,104,347) (7,313,201) (447,747) (447,747) (335,810) -

(2) Amortize Regulatory AssetRegulatory Debit (Acct 407.3) 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201 1,649,201

Regulatory Asset (MN Jurisdiction Only) (Acct 182.3) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201) (1,649,201)

Journal Entries

Assumptions

Roll Forwards



Black Dog Remediation Costs Sample Accounting

Expected Total Company Costs 33,150,000 (a)Expected Minnesota Jurisdiction Costs 24,738,020 (b)

Spend Period 2012-2023 (c)Amortization Period 2013-2027 (d)

Annual Total Company Amortization 2,210,000 (e)Annual Minnesota Jurisdiction Amortization 1,649,201 (f)

Regulatory Asset (MN Jurisdiction)Beginning BalanceRegulatory Debit (Account 407.3)Cash ExpendituresEnding Balance

(1) Recognize Cash ExpendituresRegulatory Asset (MN Jurisdiction Only) (Acct 182.3)

Cash (Acct 131)

(2) Amortize Regulatory AssetRegulatory Debit (Acct 407.3)

Regulatory Asset (MN Jurisdiction Only) (Acct 182.3)

Journal Entries

Assumptions

Roll Forwards

13 14 152025 2026 2027

Jan - Dec Jan - Dec Jan - Dec

4,947,604 3,298,403 1,649,201 (1,649,201) (1,649,201) (1,649,201)

- - - 3,298,403 1,649,201 0

- - - - - -

1,649,201 1,649,201 1,649,201 (1,649,201) (1,649,201) (1,649,201)



Northern States Power CompanyElectric Utility - State of Minnesota

Docket No. E002/GR-13-868Exhibit___(LHP-1), Schedule 4

Page 1 of 2

Sherco 3 Depreciation Deferral Sample Accounting

1 2 3 4 5 6 7 8 9 10 112013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec

2013 Depreciation (Total Company) 14,124,121 Minnesota Jurisdictional Percent 74.62%

2012 and 2013 Deferrals (MN Jurisdiction) 10,540,055 Amortization Period 21

Regulatory Asset (MN Jurisdiction)Beginning Balance - 10,540,055 10,038,148 9,536,240 9,034,333 8,532,425 8,030,518 7,528,611 7,026,703 6,524,796 6,022,889 Regulatory Debit (Account 407.3) 10,540,055 - - - - - - - - - - Regulatory Credit (Account 407.4) - (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) Ending Balance 10,540,055 10,038,148 9,536,240 9,034,333 8,532,425 8,030,518 7,528,611 7,026,703 6,524,796 6,022,889 5,520,981

(1) Depreciation ExpenseDepreciation Expense (Acct 403) 10,540,055 - - - - - - - - - -

Accumulated Depreciation (Acct 108) (10,540,055) - - - - - - - - - -

(2) Set up Regulatory AssetRegulatory Asset (MN Jurisdiction Only) (Acct 182.3) 10,540,055 - - - - - - - - - -

Regulatory Credit (Acct 407.4) (10,540,055) - - - - - - - - - -

(3) Amortize Regulatory AssetRegulatory Debit (Acct 407.3) - 501,907 501,907 501,907 501,907 501,907 501,907 501,907 501,907 501,907 501,907

Regulatory Asset (MN Jurisdiction Only) (Acct 182.3) - (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907)

Journal Entries

Assumptions

Roll Forwards



Page 2 of 2

Sherco 3 Depreciation Deferral Sample Accounting

2013 Depreciation (Total Company) 14,124,121 Minnesota Jurisdictional Percent 74.62%

2012 and 2013 Deferrals (MN Jurisdiction) 10,540,055 Amortization Period 21

Regulatory Asset (MN Jurisdiction)Beginning BalanceRegulatory Debit (Account 407.3)Regulatory Credit (Account 407.4)Ending Balance

(1) Depreciation ExpenseDepreciation Expense (Acct 403)

Accumulated Depreciation (Acct 108)

(2) Set up Regulatory AssetRegulatory Asset (MN Jurisdiction Only) (Acct 182.3)

Regulatory Credit (Acct 407.4)

(3) Amortize Regulatory AssetRegulatory Debit (Acct 407.3)

Regulatory Asset (MN Jurisdiction Only) (Acct 182.3)

Journal Entries

Assumptions

Roll Forwards

12 13 14 15 16 17 18 19 20 21 222024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034

Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec Jan - Dec

5,520,981 5,019,074 4,517,166 4,015,259 3,513,352 3,011,444 2,509,537 2,007,630 1,505,722 1,003,815 501,907 - - - - - - - - - - -

(501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) 5,019,074 4,517,166 4,015,259 3,513,352 3,011,444 2,509,537 2,007,630 1,505,722 1,003,815 501,907 -

- - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - -

501,907 501,907 501,907 501,907 501,907 501,907 501,907 501,907 501,907 501,907 501,907 (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907) (501,907)



Monticello EPU CWIP Page 1 of 1Overview of CWIP Transfers and AFUDC Calculated

CWIP Transfers Total Amounts1 2011 & 2012 Actuals over 2011 Rate Case 28,514,094$ 2 2013 Rate Case excluding License 102,773,456$ 3 2013 Actuals over 2013 Rate Case 29,715,353$ 4 AFUDC calculated on Transfers 6,449,117$ 5 Incremental Plant added in 2014 167,452,019$ Detail of AFUDC Calculated on CWIP

Beg Bal Transfer In Transfer Out Debt Equity End Bal41,244$ -$ 28,514,094$ -$ -$ -$ 28,514,094$

Detail of CWIP Transfers 41,275$ 28,514,094$ (5,242)$ -$ 49,529$ 112,659$ 28,671,039$ 41,306$ 28,671,039$ (199,256)$ -$ 49,802$ 113,279$ 28,634,864$

Description of Amounts Total Amounts 41,334$ 28,634,864$ 45,021$ -$ 49,739$ 113,136$ 28,842,761$ 2011 Actuals 235,582,434$ 41,365$ 28,842,761$ 9,373,649$ -$ 50,100$ 113,958$ 38,380,467$ 2011 Rate Case 187,908,822$ 41,395$ 38,380,467$ 14,677$ -$ 66,667$ 151,641$ 38,613,452$

47,673,612$ 41,426$ 38,613,452$ 87,775$ -$ 67,072$ 152,562$ 38,920,860$ x .416 41,456$ 38,920,860$ 123,172,186$ -$ 67,606$ 153,776$ 162,314,428$

1a 2011 Actuals over 2011 Rate Case 19,832,223$ 41,487$ 162,314,428$ -$ -$ 281,940$ 641,304$ 163,237,672$ 41,518$ 163,237,672$ -$ -$ 283,544$ 644,952$ 164,166,168$

2012 Actuals 20,869,882$ 41,548$ 164,166,168$ -$ -$ 285,157$ 648,621$ 165,099,945$ x .416 41,579$ 165,099,945$ -$ -$ 286,779$ 652,310$ 166,039,034$

1b 2012 Actuals over 2011 Rate Case 8,681,871$ 41,609$ 166,039,034$ -$ -$ 288,410$ 656,020$ 166,983,464$ 41,640$ 166,983,464$ -$ (167,452,019)$ 140,517$ 328,039$ 0$

1 2011 & 2012 Actuals over 2011 Rate Case 28,514,094$ -$ 161,002,903$ (167,452,019)$ 1,966,859$ 4,482,258$ 0$

2013 Rate Case 247,051,577$ 2013 Debt % 0$ x .416 2013 Equity % 0$

2 2013 Rate Case excluding License 102,773,456$ 2014 Debt % 0$ 2014 Equity % 0$

2013 Actuals 318,482,714$ 2013 Rate Case 247,051,577$ July 2013 Transfer

71,431,137$ 2013 Rate Case exlcuding License 102,773,456$ x .416 2013 Actuals over 2013 Rate Case 20,398,730$

3 2013 Actuals over 2013 Rate Case 29,715,353$ Total July 2013 Transfer 123,172,186$

4 AFUDC calculated on Transfers 6,449,117$

5 Incremental Plant added in 2014 167,452,019

Ms. Lisa Perkett Xcel Energy Services, Inc. 414 Nicollet Mall, 4th Floor Minneapolis, MN 55401 October 78 2013 Dear Lisa, At your request, I have reviewed the technical analysis that Black and Veatch (B&V) conducted for the Sherco Unit 3 engineering and economic life, reviewed detailed information on the plant, had broad-ranging discussions with Sherco Subject Matter Experts and conducted an inspection of the plant. As a result, I can provide an informed opinion on the appropriate depreciable life for the unit.

As you are aware, I have had twenty years’ experience at a Fortune 100 utility in property accounting, depreciation, engineering and valuation and have managed fixed asset accounting for regulated entities and non-regulated entities and an additional 10 years as Managing Partner of Alliance Consulting Group. Alliance provided depreciation analysis for utilities across the US. I have significant experience as an expert witness in depreciation, valuation and rate base areas and have provided testimony and support in many state regulatory commission dockets. In addition to having held a number of national industry roles related to depreciation and property accounting, including twice chairing the Plant Accounting and Valuation Committee of the Edison Electric Institute, I have attended all the classes offered by the Depreciation Programs, Inc. (DPI) and continue to refresh my training by attending (and teaching) various depreciation related seminars across the country. I served as general editor of the industry publication “Introduction to Depreciation and Net Salvage of Public Utility Plant and Plant of Other Industries”, have been contributing editor of other industry publications and I am a frequent speaker at conferences on depreciation related issues. I am a Licensed Professional Engineer in the State of Texas (PE) and a Certified Depreciation Professional (CDP).

1410 Avenue K, Suite 1105B Plano, TX 75074

Phone (214) 473-6771 Fax (214) 279-0535

Northern States Power Company Page 1 of 12

Docket No. E002/GR-13-868 Exhibit___(LHP-1), Schedule 6

The majority of the assets at a generating unit will generally retire at the same time – at its final retirement date. Depreciation of generating units requires an estimate of the final retirement date in order to recover investment over the period of time the property is used to provide service to customers. The most important factor in determining the depreciation rate for a generating unit is the estimate of the final retirement date.

Coal-fired power plants consist of a large number of individual assets (such as pumps, motors and boiler tubes) which have a finite life. These individual assets fail and must be replaced in order for the plant to continue in operation. In addition, throughout a plant’s life, the utility performs capital projects (including projects required to comply with regulatory requirements). However, at some point in time, these expenditures become so costly that the more prudent course is to retire the entire plant and all of its many components.

After reviewing the analysis, I believe the B&V analysis was thorough and comprehensive as it relates to the engineering-related forces that could factor into the life for Sherco Unit 3. From the B&V analysis and my understanding of the unit’s facts and circumstances, I concur with the recommendation that Sherco Unit 3’s life be maintained at its current 21 year remaining life. Given that the boiler equipment is the critical path to retirement for the unit at this point and there were no major boiler capital improvements related to the failure of the turbine-generator, there is no discernible reason to move the life of the unit from its existing end date.

While the turbine-generator set was restored after the incident, many of the components were reused, rebuild or replaced with used “like-kind” equipment. For example, the exciter was replaced with a used exciter of nearly the same vintage from another plant. My understanding (and the discussion from the B&V report) was that there was no intent to bring the turbine-generator set back to “new” condition but to bring it to approximately the same condition as prior to the failure. As such, even without the limiting factor of the boiler equipment, the rebuild would not warrant a change in the life of the unit.

While there are some projected future capital expenditures that may have an impact on the life of the unit at a future point in time (primarily large boiler-related expenditures and the addition of environmental control equipment), the expenditures are still outside of a reasonable time frame to consider in setting depreciable lives and, to some degree, are still speculative as to when or if they will occur. Without the budgeted boiler plant replacements, Xcel Subject Matter Experts believe that it may be possible to continue to operate the unit through the currently projected life (with the appropriate escalating level of Operating and Maintenance available), but that the capital expenditures for the boiler would be required to potentially extend the life of the unit. As is common practice in setting lives for depreciation purposes, only when the expenditures are made that will affect the life of the unit should the life of the unit be reconsidered. That way, the


Phone (214) 473-6771 Fax (214) 279-0535



additional capital to be depreciated and any additional life that the capital additions may promote will be synchronized.

Given the above considerations, it is my opinion that the current 21 year remaining life for Sherco Unit 3 is still appropriate and reasonable for use in setting depreciation rates and expense.

Sincerely, Dane Watson Managing Partner Alliance Consulting Group


Phone (214) 473-6771 Fax (214) 279-0535



REPORT ON LIFE EXPECTANCY OF COAL-FIRED POWER PLANT

Sherburne County Generating Station

Unit 3

B&V PROJECT NO. 181267 B&V FILE NO. 28.0000

PREPARED FOR

Xcel Energy

OCTOBER 14, 2013

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Xcel Energy | Table of Contents

BLACK & VEATCH | Table of Contents i

Table of Contents

1.0 Summary .................................................................................................................................................... 1

1.1 Approach ...................................................................................................................................................... 1

1.2 Findings: ....................................................................................................................................................... 1

2.0 Discussion .................................................................................................................................................. 1

2.1 Turbine Restoration ................................................................................................................................. 1

2.2 Design Life.................................................................................................................................................... 2

2.2.1 Boiler Discussion .................................................................................................................... 2

2.2.2 Turbine Discussion ................................................................................................................ 3

2.3 Engineering Considerations ................................................................................................................. 4

2.3.1 Steam Turbines ....................................................................................................................... 4

2.3.2 Boilers ......................................................................................................................................... 4

3.0 Conclusions................................................................................................................................................ 6



Xcel Energy | Summary

BLACK & VEATCH | Summary 1 | P a g e

1.0 Summary Black & Veatch (B&V) was contacted by representatives of Xcel Energy who requested an assessment or opinion regarding the remaining useful life of the Sherburne County Unit 3 generating plant. Xcel Energy explained that the unit was in the process of returning to service after an incident in which the turbine generator was damaged. The Minnesota Public Utility Commission has ordered that Xcel Energy request an independent assessment of the remaining useful life of the unit as one of the primary inputs to establish a reasonable period over which to depreciate the capital investment in the plant.

1.1 APPROACH In this report Black & Veatch provides a discussion of the remaining life of the Xcel Energy Sherburne County (Sherco) Unit 3 and the primary drivers of the useful life of any generating unit. Black & Veatch based the evaluation on data provided by Xcel Energy regarding the plant’s current condition, typical end of life mechanisms for fossil fired generating plants and our knowledge of depreciation practices typically used by utilities and Public Service Commissions in the U.S. The sections of this report that follow will discuss the design life, a limited condition assessment and recent findings from a survey of typical industry depreciation practices. The depreciation survey includes a recent consideration of life spans of other US coal plants, and engineering and environmental compliance considerations.

The B&V evaluation is focused on the evaluation of the remaining life. Our assessment specifically considered typical end of life drivers for the major components of the generating plant in comparison to the condition of the specific equipment at Sherco Unit 3. This condition evaluation was based on information and reports provided by Xcel Energy and industry information available from the major systems Original Equipment Manufacturers (OEM’s). The condition information provided by Xcel Energy included Outage and Inspection reports, planned capital expenditures, and historical performance/operations information.

1.2 FINDINGS: After review of the available information regarding the condition of the generating unit and industry practice it is the opinion of Black & Veatch that the restoration efforts with respect to the Sherburne County Unit 3 turbine generator should have no significant impact on the overall remaining physical life of the unit.

It is our understanding that the work performed returned the turbine generator to the conditions immediately prior to the event of November 19, 2011. The remaining useful life of the plant as a whole is a function of the condition of the entire plant and not any single component. The life limiting factor or system most likely to define the end of the economic and useful life of the station will be the boiler.

There are two major influences that will in all likelihood lead to a finding that the boiler has reached the end of its useful life. The first is a finding that due to creep1 a major header or other component in the boiler is no longer functional. The second is the need for significant environmental control equipment due to a regulatory compliance driver.

1 Creep is the tendency of a solid material to move slowly or deform permanently under the influence of

mechanical stresses.



XCEL, SHERBURNE COUNTY UNIT 3 LIFE EXPECTANCY OF COAL FIRED POWER PLANT

BLACK & VEATCH | Discussion 1 | P a g e

2.0 Discussion The following sections provide a discussion of the findings from the Black & Veatch study efforts. This includes a summary condition assessment, based on information provided by Xcel Energy, and discussion of the primary drivers of the useful life of a modern power generation facility.

2.1 TURBINE RESTORATION The original steam turbine generator equipment was supplied by General Electric and was placed in operation in 1987. The turbine has operated reliably until the unit restart following the November 2011 planed outage to upgrade the HP/IP turbine sections. During that restart, on November 19, 2011, the entire turbine train suffered major damage when several blades were separated during startup requiring complete turbine disassembly and subsequent restoration. Extensive examinations, engineering evaluations and repairs were completed on the affected components to restore them to pre-event condition.

HP-IP Turbines - HP and IP turbines were replaced with an Alstom design in 2011. Components in the front standard were damaged and repairs completed. During disassembly the HP Inner shell would not separate on site and the entire inner shell and rotor were sent out for inspection and repair. The lower half outer shells were removed to facilitate repairs and regrouting of the turbine base plates. LP Turbines – The LP turbine rotors were removed and inspected. The rotors, and all components were inspected, repairs made and buckets replaced. The lower half outer shells were removed to facilitate repairs and regrouting of the turbine base plates.

Generator - The generator sustained extensive damage to both the rotor and stator/core during

the failure event. The stator laminations were completely removed on site and the stator was

completely restacked vertically. Both turbine end and collector end outer end shields were

extensively damaged, and they were repaired. The inner end shields were also refurbished but only

minor repairs were required. Other components were replaced with new parts, including bearings,

H2 seals, oil deflectors, bushings, current transformers, etc. The generator rotor stub shaft was

broken off from the main generator shaft. A new bolted on stub shaft was designed by the OEM and

extensive rotor repairs were made to all areas of the rotor. Other than the rotor body and copper

windings, all other rotor components were replaced.

Exciter - The LP turbine failure resulted in complete destruction of the exciter stator and rotor.

There was also substantial damage to the rectifier’s banks in the exciter doghouse. A used exciter

from another utility was purchased, inspected and refurbished by the OEM. The U3 voltage

regulator was replaced with a new digital General Electric EX2100E excitation system. The Sherco

3 Fall 2011 overhaul and uprate outage included replacement of the rectifiers with a new GE water

cooled design.

Condenser – Severe damage occurred to the condenser tubes caused by the broken turbine

components. The condenser tubes were replaced. During retubing, two of the tube sheets were





found to be eroded below acceptable thickness and were also replaced. All tube sheets were coated

with a plastic coating to ensure longevity.

2.2 DESIGN LIFE Analysis of steam plant lives is heavily influenced by the engineering design life. When a new plant is initially placed in service, its projected life will generally equal its engineering life. As a unit ages, it is reasonable to reevaluate life span by considering the condition of the plant components, actual plant use and experience, additional capital expenditures for the unit, and potential environmental costs and risks. The following sections discuss design life, the major components of steam plants, and factors that lead to component failure and ultimately influence plant life.

Based on discussions with Original Equipment Manufacturers (OEMs), the expected or design “life” of a major power plant component such as the steam generator (boiler) or the turbine-generator is determined by various factors. The actual age of a piece of equipment is seldom the determining factor; rather a combination of utilization, specific design, maintenance, and environment

determines the expected useful life. The sections that follow will focus on the two major plant systems that may impact the life of the unit (boiler and turbine/generator) and discuss each of those determining factors.

2.2.1 Boiler Discussion

As is the case with turbines, the actual age of a piece of equipment is not the primary determining factor of expected life, rather a combination of hours connected to load, the pattern and practice of use, specific design, fuel quality, water quality and chemistry, and maintenance procedures determine the expected useful life.

Babcock and Wilcox published information that describes the typical expectation for specific equipment replacement. Babcock and Wilcox’s “Steam” states, “high temperature creep rupture and creep fatigue failure are the two main aging mechanisms in the high temperature components of high temperature boilers. All components that operate above 900° F are subject to some degree of creep. As a result, most of the components have a finite design life and can fail after 20 to 40 years of operation.”

A table of typical tube life by general duty is provided below in Table 1. These are general industry recommendations and not based on specific findings or condition assessment of Xcel Energy’s Sherco 3 boiler. Although in kind replacement of worn or damaged tubes is not expected to trigger New Source Review (NSR) requirements, a Legal and Environmental assessment would be recommended to confirm this assumption prior to making major changes to steam generator heat transfer surfaces.





Table 1 Example Component Replacement Schedule for a Typical High Temperature, High Pressure

Boiler2

Typical Life

(Years)

Component

Replaced

Cause for

Replacement

20 Miscellaneous tubing Corrosion, erosion, overheating

25 Superheater (SH) Creep

25 SH outlet header Creep, fatigue

25 Burners and throats Overheating, fatigue

30 Reheater Creep

35 Primary economizer Corrosion

40 Lower furnace Overheating, corrosion

Note: The actual component life is highly variable depending on specific design, operation, maintenance, and fuel.

Based on Black & Veatch’s Phase I review of Xcel Energy’s boiler O&M program, expected major component inspections, maintenance and replacements have been completed or are planned in accordance with accepted boiler OEM recommendations and industry practices. This includes planned replacement of Finishing Superheater Pendant sections and a large waterwall section due to quench cracking in 2017, and planned replacement of the Couton Bottom and Reheater Superheater Pendant due to ash erosion in 2020. These planned maintenance actions demonstrate Xcel Energy’s foresight into boiler life and maintenance. Based on our review, Sherco 3’s boiler appears to be aging as expected for a boiler commissioned in 1987. Given the continued investment noted, continued operation in a manner similar to historical the boiler should maintain but not significantly exceed, the average designed life expectancy of a typical steam generator of this size and type..

2.2.2 Turbine Discussion

Most failure mechanisms for turbine/generators are physical degradation of components due to operational conditions combined with component features like design, materials, temperature, looseness and fretting of generator components, solid particle erosion, steam erosion and water erosion. This is what typically drives end of life for turbine/generator components. Based on the condition assessment information provided and the summary description of the work completed in the restoration project, the Sherco unit 3 turbine is generally in acceptable condition for a unit that was commissioned in 1987. The HP and IP turbines have experienced solid particle erosion. The IP turbine rotor has experienced some bowing. The HP and IP turbine rotors were replaced in 2011 as part of a targeted uprate to improve the operating efficiency of the steam turbine train.

2 Babcock & Wilcox, “Steam, its generation and use,” 40th Edition, 46-4, 1992





Based on Black & Veatch’s Phase I review of Xcel Energy’s turbine/generator O&M program and the restoration efforts initiated following the 2011 event, maintenance and component replacements have been completed in accordance with accepted turbine/generator O&M practices. Based on this summary review and despite the extensive work completed during the restoration project, the current condition of the Sherco 3 turbine/generator does not support a significant extension of the unit life past the original design life expectancy.

2.3 ENGINEERING CONSIDERATIONS Analysis of steam plant lives should include consideration of engineering design life. When a new plant is initially placed in service, its expected life should equal its engineering life. As a unit ages, it is reasonable to reevaluate life span by considering the condition of the plant components, actual plant use and experience, additional capital expenditures, and potential environmental costs and risks. The following sections discuss design life, the major components of steam plants, and factors that lead to component failure and ultimately influence plant life.

2.3.1 Steam Turbines

Based on discussions with the major Original Equipment Manufacturers (OEM) regarding their turbine generator design, it is apparent that expected life and operation is normally specified by the number of starts and shutdowns. These criteria are used by the manufacturer to check design life and to define startup and shutdown procedures today as they were 40 years ago. With proper maintenance, and when operated according to the OEM’s recommendations and expectations, a steam turbine can be expected to operate longer than the 30 to 35 year life that is typically specified.

It is important to look at the steam turbine and its related equipment as a number of distinct pieces. Within the steam turbine housing there are numerous “components” all of which must be designed to meet the expected operating conditions and perform reliably for at least some portion of the economic life of the turbine generator. That said a number of these components should be expected to be replaced during the life of the unit. Maintenance in the form of repairs and replacement of components is considered routine over the life of the unit with the exception of the turbine rotor and shell.

Typical practice in the utility industry is to perform a major overhaul of steam turbines every 6 to 10 years. This frequency is considered reasonable and allows for inspection and repair on a frequency that typically will allow for reliable operation for the life of the plant.

2.3.2 Boilers

As is the case with turbines, Black & Veatch’s experience with boiler manufacturers has demonstrated that the expected or design life of major boiler components is determined by various factors. The actual age of a piece of equipment is not the primary determining factor, rather the condition practice of use, specific design, fuel quality, water quality and chemistry, capital expenditures, and maintenance procedures determine the expected useful life. In their reference manual “Combustion, Fossil Power” ABB-CE states, “The parameters that affect the life of a





component are the local values of stress and temperature, and its material properties. Life does not only depend on these parameters, it is extremely sensitive to them.”3

Babcock and Wilcox’s “Steam” states, “high temperature creep rupture and creep fatigue failure are the two main aging mechanisms in the high temperature components of high temperature boilers. All components that operate above 900° F are subject to some degree of creep. As a result, most of the components have a finite design life and can fail after 20 to 40 years of operation.”

Over the course of the turbine and boiler normal operating life, a utility expects to replace various components of these systems merely in order to maintain the usefulness of the asset. The timing of these replacements is based on failure mechanisms, the original design, the operating regime, fuel (boiler systems), and the maintenance practices.

3 Combustion Engineering, “Combustion Fossil Power,” 4th Edition, 24-9, 1991




BLACK & VEATCH | Conclusions 6 | P a g e

3.0 Conclusions As discussed earlier the end of the useful life of a typical generating plant is a function of the

engineering/physical characteristics of the plant and the economic considerations. That useful life

drives the evaluation of the expected life of the plant. With respect to the engineering/physical life

of the plant the evaluation considers the design, the utilization, maintenance practices and the

continuing investment. This life is also influenced by economics of the utilization. That includes the

maintenance and capital investment from the owner’s perspective but also the costs of operation

and the value derived from the utilization. As compliance with regulatory requirements becomes

more expensive this will tend to reduce the life as alternatives eventually become more attractive.

In the case of Sherco Unit 3, the information provided indicates that Xcel Energy has maintained the

major plant systems in a manner consistent with industry practice and OEM recommendations,

especially with respect to the two major plant systems, the boiler and the turbine/generator. The

recent restoration effort is intended to bring the unit back to the condition immediately before the

accident occurred. There was no specific program to extend the life of the systems beyond the

original design. At the same time the utilization of the turbine generator can only be accomplished

through the use of the boiler. These two major systems comprise the primary (and most expensive)

elements of the generating plant. The information provided indicates the boiler is being maintained

in a prudent manner consistent with industry practice and OEM recommendations. Xcel Energy has

made prudent capital investments in the boiler systems and has plans to continue in order to

maintain the asset. However there is no reason to believe that the asset management program for

either the boiler or the turbine will result in a significant increase in the useful life of the plant

beyond what is currently projected. In fact there are external drivers, the most specific being

potential and already enacted environmental compliance requirements, which will likely reduce or

at least limit the economic life of the generating plant.




Docket No. E002/GR-13-868Exhibit___(HLP-1), Schedule 7

Page 1 of 1

Sherco 3 Life Change

Beginning Plant Balance 733,376,200$ Beginning Reserve Balance 460,794,009$

Net Salvage Rate -4.3%

Current Approved Remaining Life 19Current Depreciation Expense 16,342,242$

Proposed Remaining Life 21Proposed Depreciation Expense 14,785,318$

Difference (1,556,924)$

Beginning Accumulated

Reserve Book DepreciationCost of

Removal/Savlage Retirements

Ending Accumulated

Reserve

2013 January -$ (129,744)$ (129,744)$ 2013 February (129,744)$ (129,744)$ (259,487)$ 2013 March (259,487)$ (129,744)$ (389,231)$ 2013 April (389,231)$ (129,744)$ (518,975)$ 2013 May (518,975)$ (129,744)$ (648,718)$ 2013 June (648,718)$ (129,744)$ (778,462)$ 2013 July (778,462)$ (129,744)$ (908,205)$ 2013 August (908,205)$ (129,744)$ (1,037,949)$ 2013 September (1,037,949)$ (129,744)$ (1,167,693)$ 2013 October (1,167,693)$ (129,744)$ (1,297,436)$ 2013 November (1,297,436)$ (129,744)$ (1,427,180)$ 2013 December (1,427,180)$ (129,744)$ (1,556,924)$

(1,556,924)$ -$ -$ BOY/EOY (778,462)$

Minnesota Jurisdictional Percent risdictional Percent 74.62%

Accumulated Reserve

Energy Supply Capital Plant AdditionsAddition Amounts Represent Total Project Costs Including AFUDC

Est 2015Category Grandparent Parent # Description 2014 2015 ISD Step

NSP-MN Company

Sherco SHC_U1 Environmental 10786214 SHC1C U1 NOx Ctrl-Mill Optimiz - 4,944 10/15/2015 xSherco SHC_U1 Environmental 11488078 SHC1C U1 Mercury Control - 4,709 5/29/2015 xSherco SHC_U1 Environmental 11488079 SHC1C U1 Scrubber Spargers 2,206 - 10/31/2014 xSherco SHC_U1 Environmental 11491104 SHC1C U1 WESP Power Supply Rep 3,183 - 11/28/2014 xSherco SHC_U1 Environmental 11491070 SHC1C U1 WESP Electrode Repl 999 - 10/31/2014 xSherco SHC_U1 Environmental 11631104 SHC1C U1 Wet ESP Scrubber Mod 832 - 10/31/2014 xSherco SHC_U1 Replace boiler couton bottom 10935185 SHC1C U1 Couton Bottom Repl - 12,006 5/29/2015 xSherco SHC_U1 Replace DCS controllers 11350867 SHC1C U1 DCS Controls Repl PH - 7,929 5/6/2015 xSherco SHC_U1 Turbine EHC Controls 11487925 SHC1C Turbine EHC Controls Rep - 5,550 5/27/2015 xSherco SHC_U2 Environmental 11630588 SHC2C Cair U2 NOX cntrl mill o 3,378 797 12/31/2014 xSherco SHC_U2 Environmental 11488076 SHC2C U2 Mercury Control 4,177 - 10/15/2014 xSherco SHC_U2 Environmental 11488080 SHC2C U2 Scrubber Spargers 1,735 - 11/28/2014 xSherco SHC_U2 Environmental 11491110 SHC2C U2 WESP Power Supply Rep 1,456 - 11/28/2014 xSherco SHC_U2 Environmental 11491077 SHC2C U2 WESP Electrode Repl 875 - 11/28/2014 xSherco SHC_U2 Environmental 11631090 SHC2C U2 Wet ESP Scrubber Mod 495 - 11/28/2014 xSherco SHC_Sherco Common Consolidated 11217241 SHCJC Stacker Elec & Contrl Sy 93 - 12/31/2013Sherco SHC_Sherco Common Consolidated 11631416 SHCCC CIP V 5 Comp Improvement 1,090 - 4/3/2014Sherco SHC_Sherco Common Consolidated 11795567 SHCJC 2014 Small Project routi 122 - 11/3/2014Sherco SHC_Sherco Common Consolidated 11795574 SHCJC 55 Conveyor Motor Replacement 8 - 12/9/2013Sherco SHC_Sherco Common to Units 1 & 2 11795591 SHCCC 2014 Emergent work 1,003 - 10/29/2014Sherco SHC_Sherco Common to Units 1 & 2 11797804 SHCCC Air Compressor Replaceme 960 - 5/2/2014Sherco SHC_Sherco Common to Units 1 & 2 11795603 SHCCC Ring Head. Valve Repl 314 - 10/27/2014Sherco SHC_Sherco Common to Units 1 & 2 10637400 SHCCC Medium Voltage Cabling R 209 - 11/3/2014Sherco SHC_Sherco Common to Units 1 & 2 11795605 SHCCC 2014 small project routines 152 - 11/3/2014Sherco SHC_Sherco Common to Units 1 & 2 11488177 SHCCC Pond 3S Bottom Ash Emban 127 - 9/30/2014Sherco SHC_Sherco Common to Units 1 & 2 11795607 SHCCC CEMS Rm Expansion Comnn Stack 40 - 12/6/2014Sherco SHC_Sherco Common to Units 1 & 2 10934289 SHCCC Pond 2 Capping PH III (0) - 10/28/2014Sherco SHC_Sherco Unit 1 10611122 SHC1C U1 Mill Isolation Valves 493 - 3/31/2014Sherco SHC_Sherco Unit 1 11795611 SHC1C Repl #1 Diesel Fire Pmp 399 - 11/17/2014Sherco SHC_Sherco Unit 1 11795613 SHC1C 2014 small project routines 305 - 11/3/2014Sherco SHC_Sherco Unit 1 11795622 SHC1C Level 2 Mill OH 2014 Spring 205 - 11/3/2014Sherco SHC_Sherco Unit 1 11795620 SHC1C Level 2 Mill OH 2014 Fall 204 - 10/15/2014Sherco SHC_Sherco Unit 1 11795616 SHC1C Level 2 Mill OH 2014 summer 204 - 10/9/2014Sherco SHC_Sherco Unit 1 11752775 SHC1C Scrubber Elev Gearbox Re 5 - 11/18/2013Sherco SHC_Sherco Unit 2 11488178 SHC2C U2 Air Htr Hot Int Baske 5 - 12/3/2013Sherco SHC_Sherco Unit 2 11487765 SHC2C Air Heater Baskt Cold En 2 - 11/22/2013Sherco SHC_Sherco Unit 2 11795636 SHC2C 2014 small project routi 305 - 11/3/2014Sherco SHC_Sherco Unit 2 11795644 SHC2C Level 2 Mill OH 2014 Summer 204 - 10/30/2014Sherco SHC_Sherco Unit 2 11795643 SHC2C Level 2 Mill OH 2014 Fall 204 - 10/9/2014Sherco SHC_Sherco Unit 2 11795639 SHC2C Level 2 Mill OH 2014 Spring 203 - 10/9/2014

Addition Amount ($000s)


Docket No. E002/GR-13-868 Exhibit___(LHP-1), Schedule 8 Page 1 of 25PUBLIC DOCUMENT - TRADE SECRET DATA EXCISED




Sherco SHC_Sherco Unit 2 11795646 SHC2C 21 ID Fan Motor Rewind 159 - 5/3/2014Sherco SHC_Sherco Unit 2 11752779 SHC2C Scrubber Elev Gearbox Re 5 - 11/18/2013Sherco SHC_Sherco Unit 3 11487734 SHC3C Motor Control Sys PLC Re 5,758 - 5/28/2014Sherco SHC_Sherco Unit 3 10934186 SHC3C U3 Condenser Ball Cln Re 793 - 4/1/2014Sherco SHC_Sherco Unit 3 10786170 SHC3C U3 Coal Crusher Repl 582 - 2/3/2014Sherco SHC_Sherco Unit 3 11631151 SHC3C Inst Line 3-32-33-34 SDAs 475 - 5/30/2014Sherco SHC_Sherco Unit 3 11635985 SHC3C BFPT Overspeed Ctrl Repl 416 - 4/29/2014Sherco SHC_Sherco Unit 3 11795651 SHC3C 2014 small project routi 299 - 11/3/2014Sherco SHC_Sherco Unit 3 11795657 SHC3C MV Bus Undervoltage Rela 239 - 4/23/2014Sherco SHC_Sherco Unit 3 11795654 SHC3C Feeder Retrofit to Ball Mills 217 - 4/30/2014Sherco SHC_Sherco Unit 3 11630565 SHC3C Inst Lining Recycle Tanks 134 - 4/30/2014Sherco SHC_Sherco Unit 3 11630558 SHC3C Inst Lining 31 Add Tank 114 - 4/30/2014Sherco SHC_Sherco Unit 3 11795663 SHC3C #31 Aux Clg Pmp Replace 108 - 3/8/2014Sherco SHC_Sherco Unit 3 11795662 SHC3C Inst New Pump Drain Line 77 - 4/14/2014Sherco SHC_Sherco Unit 3 11795665 SHC3C Install Polisher HMI 36 - 3/8/2014Sherco SHC_Sherco Unit 3 11217415 SHC3C U3 BFPT Controls Repl 33 - 2/28/2014

Total Sherco 35,638 35,935

Allen S King ASK_King 2014 Overhaul 11485320 ASK1C-Forced Drf Fan SteamCoil 1,256 - 6/10/2014 xAllen S King ASK_King 2014 Overhaul 11629949 ASK1C-HAZOP Dustless Tran A3A- 692 - 4/9/2014 xAllen S King ASK_King 2014 Overhaul 11795274 125VDC Pnl & Batt Chrgr Repl 462 - 5/7/2014 xAllen S King ASK_King 2014 Overhaul 11795205 ID Dischrge Duct to Stack ExpJts 351 - 6/2/2014 xAllen S King ASK_King 2014 Overhaul 11630351 ASK1C-2014 Coal Silo Liners Install 314 - 6/3/2014 xAllen S King ASK_King 2014 Overhaul 11217855 ASK1C-Econ Outlet ExpanJoint R 208 - 6/2/2014 xAllen S King ASK_King 2014 Overhaul 11846389 ASK1C Waterwall Replacements 10,818 - 6/1/2014 xAllen S King ASK_Allen S King 11629953 ASK1C-SCR Catalyst 3rd Layer Replac 2,271 - 4/17/2014Allen S King ASK_Allen S King 11789612 ASK0C-Install Ladder Track 1,300 - 7/14/2014Allen S King ASK_Allen S King 11630374 ASK Cooling Tower Cell Replacement 780 - 7/2/2014Allen S King ASK_Allen S King 11798633 Emergent Work 2014 501 - 10/22/2014Allen S King ASK_Allen S King 11795256 Stack Lighting Replacement 367 - 10/20/2014Allen S King ASK_Allen S King 11795198 Pump Room Lighting Replacement 262 - 10/29/2014Allen S King ASK_Allen S King 11795279 2014 Small Project Routines 20 - 11/3/2014

Total Allen S King 19,603 -

Black Dog BDS_Black Dog 11763519 BDS0C Black Dog Road Improvements 724 - 11/6/2014Black Dog BDS_Black Dog 10524053 BDS0C Freight elevator control 376 - 10/6/2014Black Dog BDS_Black Dog 11760249 BDS0C 2014 Emergent Work 305 - 12/16/2014Black Dog BDS_Black Dog 11760267 BDS0C 2014 Small Capital Projects 103 - 12/9/2014Black Dog BDS_Black Dog 11792944 BDS0C River Temp Monitoring Sy 76 - 8/20/2014Black Dog BDS_Black Dog 11792958 BDS0C BD Road Pole Removal S S 2 - 6/9/2014Black Dog BDS_Black Dog 11485469 BDS5C CEMS Shelter BD5/2 Reloc 291 - 6/5/2014Black Dog BDS_Black Dog 11629956 BDS5C inst Rotor Air Cooling Filter 148 - 12/23/2014






Black Dog BDS_Black Dog 11485477 BDS5C 5 Battery Replacement 59 - 4/14/2014Total Black Dog 2,084 -

Intermediate Plants HBR_High Bridge 11793571 HBC0C Warming Line to Intake 1,142 - 12/8/2014Intermediate Plants HBR_High Bridge 11793589 HBC8C Surge & PT Cubicle 200 - 11/24/2014Intermediate Plants HBR_High Bridge 11793582 HBC7C Surge & PT Cubicle 199 - 10/27/2014Intermediate Plants HBR_High Bridge 11649031 HBC0C ST Crane Controls Replacement 158 - 7/29/2014Intermediate Plants HBR_High Bridge 11629884 HBC7C U7 Voltage Regulator Rep 145 - 11/4/2014Intermediate Plants HBR_High Bridge 11793597 HBC8C 8HRSG Drains Replacement 142 - 9/12/2014Intermediate Plants HBR_High Bridge 11793594 HBC7C 7HRSG Drains Replacement 141 - 9/26/2014Intermediate Plants HBR_High Bridge 11793592 HBC0C Turbine Building Roof Access 115 - 12/11/2014Intermediate Plants HBR_High Bridge 11783915 HBC0C 2014 Emergent Work 102 - 12/26/2014Intermediate Plants HBR_High Bridge 11765543 HBC0C Small Project Routine 20 92 - 12/18/2014Intermediate Plants RIV_Riverside 11630771 RIV0C-Ovation Training Simulat 561 - 3/29/2014Intermediate Plants RIV_Riverside 11630906 RIV0C-Ovation Hardware Replace 367 - 5/29/2014Intermediate Plants RIV_Riverside 11765660 RIV0C Install Disolved Gas Rem 149 - 7/21/2014Intermediate Plants RIV_Riverside 11630785 RIV0C-Marshall St. Fence Repla 139 - 9/15/2014Intermediate Plants RIV_Riverside 11765971 RIV0C Small Projects 2014 102 - 11/26/2014Intermediate Plants RIV_Riverside 11796489 Emergent Work 2014 101 - 11/12/2014Intermediate Plants RIV_Riverside 11765673 RIV0C Adtl Air Comp for Air Bu 68 - 5/29/2014Intermediate Plants RIV_Riverside 11630779 RIV9C-U9 Varnish Filter Skid I 33 - 5/2/2014Intermediate Plants RIV_Riverside 11630780 RIV10C-U10 Varnish Filter Skid 33 - 5/2/2014Intermediate Plants RIV_Riverside 11794474 Rem/Repl BF Pump Spare 14 8 - 11/13/2014Intermediate Plants RIV_Riverside 11630791 RIV7C-U7 Relay Room AC Replace 2 - 7/15/2014

Total Intermediate Plants 3,998 -

Peaking & RDF Plants WLM_Wilmarth 11634471 WLM2C Replace U2 Membrane Wall 2,355 - 2/15/2014Peaking & RDF Plants WLM_Wilmarth 11349816 WLM0C Landfill Cell 10 788 - 11/3/2014Peaking & RDF Plants WLM_Wilmarth 11634141 WLM0C Replace Traveling Water 434 - 1/25/2014Peaking & RDF Plants WLM_Wilmarth 11087592 WLM1C Superheater Bundle Repl 208 - 1/28/2014Peaking & RDF Plants WLM_Wilmarth 11635000 WLM2C Replace U2 Soot Blower 170 - 1/27/2014Peaking & RDF Plants WLM_Wilmarth 11487071 WLM1C C3 and C4 Replacment 161 - 1/31/2014Peaking & RDF Plants WLM_Wilmarth 11487062 WLM1C C7 and C8 Replacment 161 - 1/31/2014Peaking & RDF Plants WLM_Wilmarth 11765619 WLM-0C DCS Software Hardware R 68 - 1/17/2014Peaking & RDF Plants WLM_Wilmarth 11349810 WLM2C U2 Generator Relaying 64 - 1/20/2014Peaking & RDF Plants WLM_Wilmarth 11349804 WLM1C U1 Generator Relaying 64 - 1/22/2014Peaking & RDF Plants WLM_Wilmarth 11634485 WLM2C Replace U2 OFA SS with V 33 - 1/28/2014Peaking & RDF Plants WLM_Wilmarth 11798498 WLM1C U1 Stack Ladder Inspecti 30 - 6/7/2014Peaking & RDF Plants WLM_Wilmarth 11798461 WLM2C U2 Stack Ladder Installa 30 - 6/7/2014Peaking & RDF Plants WLM_Wilmarth 11634490 WLM2C Replace U2 Screw Feeder 30 - 1/28/2014Peaking & RDF Plants WLM_Wilmarth 11634481 WLM1C Retube U1 Turbine Oil Co 14 - 1/14/2014Peaking & RDF Plants WLM_Wilmarth 11634928 WLM2C Retube U2 Turbine Oil Co 14 - 1/28/2014






Peaking & RDF Plants REW_Red Wing 11223356 REW1112-LAND FILL EAST CELL 4A 1,643 - 10/1/2014Peaking & RDF Plants REW_Red Wing 11635500 REW2C REPLACE BAGHOUSE COMP 24 185 - 3/31/2014Peaking & RDF Plants REW_Red Wing 11351343 REW2C U2 SOLID STATE EXCITER 183 - 3/31/2014Peaking & RDF Plants REW_Red Wing 11351340 REW1C U1 SOLID STATE EXCITER 183 - 3/31/2014Peaking & RDF Plants REW_Red Wing 11486746 REW0C RES AUX STATION XFRM FEE 159 - 3/31/2014Peaking & RDF Plants REW_Red Wing 11634325 REW2C REPLACE C3 ASH CONVEYOR 89 - 3/14/2014Peaking & RDF Plants BLL_Blue Lake 11806008 BLL8C - Combustion Inspection #1 1,637 - 11/20/2014Peaking & RDF Plants ANS_Angus Anson 11764407 ANS3C UNIT 3 CEMS Replacement 183 - 4/15/2014Peaking & RDF Plants ANS_Angus Anson 11764384 ANS2C UNIT 2 CEMS Replacement 183 - 4/15/2014Peaking & RDF Plants ANS_Angus Anson 11632397 ANS0-C-Replace Admin Bldg Blr 80 - 9/30/2014Peaking & RDF Plants ANS_Angus Anson 11485536 ANSC0 U2-3 Battery Replacement 77 - 4/23/2014Peaking & RDF Plants ANS_Angus Anson 11764415 ANS4C UNIT 4 CEMS Replacement 75 - 4/15/2014Peaking & RDF Plants IVH_Inver Hills 11632305 IVH5C U5-6 Enclosure Door Repl 142 - 11/4/2014Peaking & RDF Plants IVH_Inver Hills 11764656 IVH3C Feeder to U3 Transformer 16 - 9/22/2014

Total Peaking & Refuse Derived Fuel Plants 9,457 - [TRADESECRETBEGINS

Wind Facilities BRD_Border Wind 11551351 Border Wind ND Sequoia Wind (incl Transmission) - 11/30/2015 xWind Facilities PLV_Pleasant Valley Wind 11869600 Pleasant Valley Wind (incl Transmission) - 10/31/2015 x

TRADESECRETENDS]

Wind Facilities GDM_Grand Meadow Wind 11632423 GDM0C Gearbox Replacements 201 1,725 - 12/17/2014Wind Facilities NBL_Nobles Wind 11348157 NBLC0 Gearbox Replacements 508 - 12/30/2014Wind Facilities NBL_Nobles Wind 11769031 NBL0C T123 Gearbox Replacement 12 - 11/4/2013

Total Wind Facilities 2,244 610,655

Hydro Generation HNI_Hennepin Island 11795329 HNI0C Install Canal isolat Sto 127 - 11/21/2013Hydro Generation HNI_Hennepin Island 11349185 HNIC1 Replace Trash Racks 289 - 1/3/2014

Total Hydro Generation 416 -

Total NSP-MN Company 73,441 646,590

NSP-WI Company

Bay Front BFT_Bay Front 11483443 BFT0C B1 and B2 Baghouse Syste - 18,375 2/28/2015 xTotal Bay Front - 18,375

Total NSP-WI Company - 18,375



Nuclear Capital Additions for Testimony GuidanceAddition Amounts Represent Total Project Costs Including AFUDC

2015Grandparent Parent # Description 2014 2015 Date Step

General Furniture 11502523 PI 2014 Misc Office Furniture 100 12/31/2014Total General Furniture 100 -

General Network 11502642 PI Security Computer Replaceme 1,470 9/30/2014General Network 11502552 PI 2014 I/T Capital Blanket 275 12/31/2014

Total General Network 1,745 -

General Tools and Equipment 11502503 PI 2014 Misc Tools & Equipment 250 12/31/2014Total General Tools and Equipment 250 -

MNGP-Monticello Cyber Security 11468481 MNGP Cyber Security 08-09 8,916 44 12/31/2014 xTotal MNGP-Monticello Cyber Security 8,916 44

MNGP-Monticello Fukushima-related Modifications 11503439 MNGP Fukushima Modifications - 15,287 12/31/2017 xMNGP-Monticello Fukushima-related Modifications 11871736 MNGP Spent Fuel Pool Instr Rep - 2,449 5/31/2015 xMNGP-Monticello Fukushima-related Modifications 11871742 MNGP Flex Storage Building 2,350 - 10/31/2014 xMNGP-Monticello Fukushima-related Modifications 11871745 MNGP Regional Resp Center Build 778 62 12/31/2014 x

Total MNGP-Monticello Fukushima-related Modifications 3,128 17,798

MNGP-Monticello-Facilities 11651486 MNGP Reactor Building Roof 2,051 7/31/2014MNGP-Monticello-Facilities 11099810 MNGP Security Check Point Impr 1,009 12/15/2014MNGP-Monticello-Facilities 11650493 MNGP 2014 Facilities Infrastructure 309 12/31/2014

Total MNGP-Monticello-Facilities 3,369 -

MNGP-Monticello-Power Uprate 10245258 MNGP Extended Power Uprate 225,144 1/31/2014Total MNGP-Monticello-Power Uprate 225,144 -

MNGP-Monticello-Regular 11649833 MNGP 2014 Site Blanket 716 12/31/2014MNGP-Monticello-Regular 11651142 MNGP Filtration Unit (VU-1) 100 2/28/2014MNGP-Monticello-Regular 11649880 MNGP 2014 Plant Computer Blanket 52 12/31/2014

Total MNGP-Monticello-Regular 868 -

MNGP-Monticello-Regulatory 11712454 MNGP NEI 09-05 Security Compli 2,503 9/30/2014MNGP-Monticello-Regulatory 11652672 MNGP 2014 Capital Emergent Wor 1,027 12/31/2014MNGP-Monticello-Regulatory 11646242 MNGP Cyber Security Req Mods 316 12/31/2014







MNGP-Monticello-Regulatory 11043842 MNGP Fire PRA Model Tool 4,298 4/30/2015MNGP-Monticello-Regulatory 11813463 MNGP Sentinel Dose Tracking Sys 458 9/30/2014

Total MNGP-Monticello-Regulatory 8,602 -

MNGP-Monticello-Safety 10799276 MNGP Remote Camera Monitoring 125 11/30/2013MNGP-Monticello-Safety 11624535 MNGP 12.5KV Retail Loop Imp 510 12/31/2014

Total MNGP-Monticello-Safety 634 -

MNGP-Monti-Equipment Reliability 11367661 MNGP Met Tower Lightning Prot 15 12/31/2013MNGP-Monti-Equipment Reliability 11367663 MNGP HAYS 02 Monitor Rplc 961 12/31/2014MNGP-Monti-Equipment Reliability 11647915 MNGP Refuel Bridge Drive Hoist Rplc 345 2/28/2014MNGP-Monti-Equipment Reliability 11763590 MNGP SRV Tailpipe Transmitter 258 12/31/2014MNGP-Monti-Equipment Reliability 11764470 MNGP Simulator Computer Hardware 157 12/31/2014MNGP-Monti-Equipment Reliability 11769875 MNGP 2014 Tools & Equipment 1,000 12/31/2014

Total MNGP-Monti-Equipment Reliability 2,736 -

PI-Pr Island-Equipment Reliability 11230621 PI-HDTP Speed Control Repl 4,841 10/31/2014PI-Pr Island-Equipment Reliability 11502711 PI Foxboro H-Line Prot Ph 2 4,323 11/30/2014PI-Pr Island-Equipment Reliability 11812334 PI U2 RCP Seal Re-Design 60 11/30/2013PI-Pr Island-Equipment Reliability 10801476 PI Turbine Oil Reservoir Filter 106 11/30/2013PI-Pr Island-Equipment Reliability 11655240 PI Capital Emergent Work 1,217 8/31/2018PI-Pr Island-Equipment Reliability 10958468 PI 121 CT Deck, Header, Valves 2,290 3/31/2014PI-Pr Island-Equipment Reliability 11368266 PI RCP Motor Rewind (21) 1,919 10/31/2014PI-Pr Island-Equipment Reliability 11103036 PI Online Xfmr Mon 1GT,2GT,1M, 1,617 6/30/2014PI-Pr Island-Equipment Reliability 11230596 PI- DC Panels 21,22 Replace 1,536 10/31/2014PI-Pr Island-Equipment Reliability 11650827 PI Cooling Wtr Supprt 2-CWH-36 1,314 10/31/2014PI-Pr Island-Equipment Reliability 11502727 PI ERCS Infrastructure Repl 1,141 12/31/2014PI-Pr Island-Equipment Reliability 11102961 PI-D1 Voltage Regulator Repl 1,226 10/31/2014PI-Pr Island-Equipment Reliability 10956929 PI-Safeguards Load Sequencer P 1,018 9/30/2014PI-Pr Island-Equipment Reliability 11502512 PI 2014 Misc Minor Improvement 928 12/31/2014PI-Pr Island-Equipment Reliability 11812631 PI Reactor Coolant Pump Rebuild 715 10/31/2014PI-Pr Island-Equipment Reliability 11233547 PI-12 Circ Water Pump Mtr Rewi 602 11/30/2014PI-Pr Island-Equipment Reliability 11812775 PI Spare RHR Pump Motor 580 9/30/2014PI-Pr Island-Equipment Reliability 11812707 PI Spare Aux FW Pump Mtr Rewind 557 10/31/2014PI-Pr Island-Equipment Reliability 11812728 PI Spare CC Pump Motor Rewind 493 9/30/2014PI-Pr Island-Equipment Reliability 11100522 PI-U1 Przr PORV Air Acumultrs 489 9/30/2014






PI-Pr Island-Equipment Reliability 11812679 PI Spare Horiz CL Pump Motor 480 10/31/2014PI-Pr Island-Equipment Reliability 11230764 PI-12 FW Pump Mtr Rewind 395 10/31/2014PI-Pr Island-Equipment Reliability 11101352 PI-12 RCP Motor Cable Replacem 383 10/31/2014PI-Pr Island-Equipment Reliability 11101331 PI-11 RCP Motor Cable Replacem 383 10/31/2014PI-Pr Island-Equipment Reliability 11812648 PI Boric Acid Transfer Pumps 346 8/31/2014PI-Pr Island-Equipment Reliability 11812477 PI Waste Liquid Logic Contrllr 298 9/30/2014PI-Pr Island-Equipment Reliability 11812803 PI 11 SI Pump Motor Rewind 278 10/31/2014PI-Pr Island-Equipment Reliability 11812791 PI Spare Rod Drive MG Motor 224 7/31/2014PI-Pr Island-Equipment Reliability 11812457 PI Safety-Related Battery Repl 113 9/30/2014PI-Pr Island-Equipment Reliability 11808709 PI RCS pH/Lithium Control Sys 101 9/30/2014PI-Pr Island-Equipment Reliability 11812779 PI 11 Rod Drive MG Mtr Rewind 101 6/30/2014PI-Pr Island-Equipment Reliability 11812488 PI Cathodic Protection System 97 10/31/2014PI-Pr Island-Equipment Reliability 11812796 PI 11Cnt/Aux Bld Chill Mtr Rew 72 6/30/2014

Total PI-Pr Island-Equipment Reliability 30,244 -

PI-Pr Island-Spent Fuel Storage 10798851 PI- Relicense ISFSI 6,455 9/30/2014Total PI-Pr Island-Spent Fuel Storage 6,455 -

PI-Pr Island-SteamGeneratorReplace 10390056 PI-U2 STEAM GENERATOR REPLACE 2,321 11/24/2013Total PI-Pr Island-SteamGeneratorReplace 2,321 -

PI-Prairie Island 122 SFP Hx-CC System Prot 11502583 PI 122 SFP Hx-CC System Prot 12,793 - 10/31/2014 xTotal PI-Prairie Island 122 SFP Hx-CC System Prot 12,793 -

PI-Prairie Island Casks 30-38 11101498 PI-9 TN-40 Casks (30-38) 17,234 - 8/31/2014 xTotal PI-Prairie Island Casks 30-38 17,234 -

PI-Prairie Island Casks 39-47 11101522 PI-9 TN-40 Casks(39-47) - 14,372 7/31/2021 xTotal PI-Prairie Island Casks 39-47 - 14,372

PI-Prairie Island Fukushima-related Improvements 11650737 PI Fukushima Mods - 4,773 8/31/2016 xTotal PI-Prairie Island Fukushima-related Improvements - 4,773

PI-Prairie Island Life Extension - 2015 Step 11808202 PI U2 Generator Replacemnt LCM - 48,578 10/23/2015 xPI-Prairie Island Life Extension - 2015 Step 11648823 PI LR PhII-Nuc Safety Marg Imp 18,419 - 9/30/2014 xPI-Prairie Island Life Extension - 2015 Step 11812440 PI LR Ph II-U2 MRP-227A Implem - 5,815 10/31/2015 x






PI-Prairie Island Life Extension - 2015 Step 10386846 PI-LICENSE RENEWAL PROJECT 14,717 - 10/31/2014 xPI-Prairie Island Life Extension - 2015 Step 11808215 PI U1 GSU Transformer Repl LCM 13,436 650 10/17/2014 xPI-Prairie Island Life Extension - 2015 Step 11808219 PI U2 GSU Transformer Repl LCM - 13,400 10/23/2015 xPI-Prairie Island Life Extension - 2015 Step 11837634 PI LR PH II-U1 MRP-227A Implem 5,769 - 11/30/2014 x

Total PI-Prairie Island Life Extension - 2015 Step 52,340 68,442

PI-Prairie Island Site Administration Bldg 10957555 PI-Site Administration Buildng 22,589 112 12/31/2014 xTotal PI-Prairie Island Site Administration Bldg 22,589 112

PI-Prairie Island U1 RCP Seal Re-Design 11650719 PI U1 RCP Seal Re-Design 6,099 22 10/31/2014 xTotal PI-Prairie Island U1 RCP Seal Re-Design 6,099 22

PI-Prairie Island-Facilities 11507888 PI Facilities Infrastruct Upgr 565 9/30/2014PI-Prairie Island-Facilities 11572234 PI Old Security Facility Remodel 10 11/30/2013PI-Prairie Island-Facilities 11507902 PI Renovate Main Warehouse 309 2/28/2014PI-Prairie Island-Facilities 11502877 PI 2014 Roof Replacements 125 9/30/2014

Total PI-Prairie Island-Facilities 1,009 -

PI-Prairie Island-Power Uprate 11605450 PI Unit 1 LCM Modifications 7,551 4/30/2014Total PI-Prairie Island-Power Uprate 7,551 -

PI-Prairie Island-Regulatory 11679156 PI NFPA805 FA18 Incip Fire Det 1,691 6/30/2014PI-Prairie Island-Regulatory 11679144 PI NFPA 805 FA20 Train A Cable 1,455 10/31/2014PI-Prairie Island-Regulatory 11102948 PI-IST Margin Mods (CL,CC,AF,R 308 9/30/2014PI-Prairie Island-Regulatory 11817138 PI GL08-01 Vent Valves (OBN) 271 9/30/2014PI-Prairie Island-Regulatory 11769305 PI Cyber Security Modifications 470 8/31/2014

Total PI-Prairie Island-Regulatory 4,194 -

PI-Prairie Island-Safety 11502435 PI U2 SI 2-33B Valve GL0801 50 11/30/2013PI-Prairie Island-Safety 11817135 PI HELB/Heat-Up Modifications 690 9/30/2014PI-Prairie Island-Safety 11769314 PI Sentinel Dose Tracking Sys 872 9/30/2014

Total PI-Prairie Island-Safety 1,611 -




Transmission Capital Plant AdditionsAddition Amounts Represent Total Project Costs Including AFUDC


NSP-MN Company

0794:DGC-WSU Rebuild 11806164 Line 0793 69kV DGC-WSU Struct.309, 232 12/29/20140794:DGC-WSU Rebuild 11806696 Douglas County, Sub 25 4/30/2014

Total 0794:DGC-WSU Rebuild 256 -

APT 550 Minnesota 11488201 Mallard - Replace APT-550, Sub 213 1/15/2014Total APT 550 Minnesota 213 -

Big Stone-Brookings 345 kV Line 11683797 BSSB-345kV Line Non-Share,ROW 2,220 6/30/2016Big Stone-Brookings 345 kV Line 11683805 BSSB-Permitting Pre Con,Non Share,L 3,364 6/1/2014

Total Big Stone-Brookings 345 kV Line 5,584 -

Black Dog - Savage 11366605 Line 0844 Black Dog-Savage, Line 6,410 6/30/2014Total Black Dog - Savage 6,410 -

CAPX JDW (joint dev work) 10889139 CapX General CapX Organization 0 12/31/2014Total CAPX JDW (joint dev work) 0 -

Cass County SUB Expansion 11642565 Cass County 3rd Dist TR,Sub 67 12/1/2013Cass County SUB Expansion 11642579 Sheyenne Relays from Cass Cty, Sub 1 12/2/2013Cass County SUB Expansion 11642581 Red River Relays from Cass Cty, Sub 1 12/2/2013

Total Cass County SUB Expansion 68 -

ELR - Breakers - NSPM 11644878 Mn Valley - Rpl Breakers 6XY, Sub 947 9/30/2014ELR - Breakers - NSPM 11644875 Mallard-Rpl Breakers 5T8, 5T9, 5T1, 481 1/30/2014

Total ELR - Breakers - NSPM 1,428 -

ELR - Relay - NSPM 11644931 Coon Creek Relay SHC1,SHC3,TER,DKN, 1,122 4/30/2014Total ELR - Relay - NSPM 1,122 -

Fault Recorders - NSPM 11644859 Black Dog - Install Fault Recorder, 264 3/30/2014Total Fault Recorders - NSPM 264 -

Forbes 500kv Sub Refurbishment 11599992 Forbes Sub SVS Controls, Sub 361 12/30/2013Forbes 500kv Sub Refurbishment 11599981 Forbes Sub Install 500 kV Reactor, 22 12/31/2013

Total Forbes 500kv Sub Refurbishment 383 -







Fort Ridgely Cap 11643467 Fort Ridgely Capacitor Increase, Su 1,351 7/1/2014Total Fort Ridgely Cap 1,351 -

G491 Wind Interconnect 11666980 G491 Intercon-Chanarambie Network,S 2,100 12/1/2014Total G491 Wind Interconnect 2,100 -

GRE Crooked Lake - Enterprise 11086454 GRE Crooked Lk-Enterprize Park 115k 2,890 6/1/2014Total GRE Crooked Lake - Enterprise 2,890 -

Hollydale Dist.115 kV 11712161 Hollydale to Medina, ROW 498 8/1/2014Hollydale Dist.115 kV 11347982 Hollydale to Medina Purchase G, Li 498 4/15/2014Hollydale Dist.115 kV 11348030 Medina 115kV Conversion, Sub 50 11/30/2014

Total Hollydale Dist.115 kV 1,046 -

Hwy 212 conversion 11613468 Line 5556 West Creek Sub to Scott C 8,331 - 9/30/2014 xHwy 212 conversion 11348236 Scot County Sub Term, Sub 3,795 - 6/1/2014 xHwy 212 conversion 11613465 Line 5557 Ave Lake to Augusta 115kV 2,303 - 12/1/2014 xHwy 212 conversion 11613470 Line 5557 Augusta Sub to Victoria T 1,535 - 12/1/2014 xHwy 212 conversion 11347935 0740 Cnvert Augusta-Chaska-SCT, Lin 555 - 2/28/2014 x

Total Hwy 212 conversion 16,520 -

IA Tariff Fund 10615153 IA Tariff Fund NSP 2,628 12/31/2019Total IA Tariff Fund 2,628 -

Kohlman Lake Inductor 11642671 Kohlman Lake 30 MVAR Inductor, Sub 1,079 6/1/2014Total Kohlman Lake Inductor 1,079 -

Kohlman Lake-Goose Lake 2nd ckt 11629131 5560 KOL-GLK(Line 1),Line - 4,806 6/1/2015 xKohlman Lake-Goose Lake 2nd ckt 11490284 Long Lake (LLK) Ring Bus Converson, 3,581 - 6/1/2014 xKohlman Lake-Goose Lake 2nd ckt 11490060 Goose Lake (GLK) Ring Bus Conversio - 2,856 6/1/2015 xKohlman Lake-Goose Lake 2nd ckt 11490282 Kohlman Lake(KOL) - Install Breaker 1,926 - 6/1/2014 xKohlman Lake-Goose Lake 2nd ckt 11628723 Kohlman Lake-Inst Breaker&Dead End, - 1,314 6/1/2015 xKohlman Lake-Goose Lake 2nd ckt 11629128 5519 Double Circuit with Line 5561, - 702 6/1/2015 xKohlman Lake-Goose Lake 2nd ckt 11629133 5561 KOL-GLK (Line 2), Line - 645 6/1/2015 xKohlman Lake-Goose Lake 2nd ckt 11629125 0885 KOL-GLK Removal KOL-LK, Line - 327 6/1/2015 xKohlman Lake-Goose Lake 2nd ckt 11629124 0830 115kV LLK-OAD Rem&Inst LLK,Lin 235 - 6/1/2014 x






Kohlman Lake-Goose Lake 2nd ckt 11629118 0801 115kV LLK-BYT Tap Rem&Inst LLK - 208 6/1/2015 xKohlman Lake-Goose Lake 2nd ckt 11629138 5562 KOL-LLK (line 1), Line 145 - 6/1/2014 xKohlman Lake-Goose Lake 2nd ckt 11629140 5563 KOL-LLK (Line 2), Line 92 - 6/1/2014 xKohlman Lake-Goose Lake 2nd ckt 11490048 0885 KOL - GLK 115kV DBL Ckt. ROW 1 - 1/1/2014 x

Total Kohlman Lake-Goose Lake 2nd ckt 5,980 10,857

Lake Emily DCP 11806040 Lake Emily Dist. Transformer Upgrad 281 6/1/2014Total Lake Emily DCP 281 -

Line 0840 Fiber 11769553 Line 0840 Fiber, Line 497 6/1/2014Total Line 0840 Fiber 497 -

Line ELR - NSPM 11490344 NSPM T-Line ELR 2014, Line 147 12/15/2014Total Line ELR - NSPM 147 -

Mallard Sub 11303974 Mallard Substation 94 3/30/2014Total Mallard Sub 94 -

Maple River Red River 2nd 115kV 11643334 Maple River-Red River, ROW 3,227 6/1/2015Total Maple River Red River 2nd 115kV 3,227 -

Meadow Lake Dist 11353409 Pomerleau Lake to Meadow Lake, ROW 500 1/31/2015Meadow Lake Dist 11348022 Meadowlake to Twin Lakes 115kV,ROW 500 1/31/2016

Total Meadow Lake Dist 1,000 -

Midtown - Hiawatha Relays 11665859 Southtown Relay Rplmnt, Sub 342 6/1/2014Midtown - Hiawatha Relays 11665853 Elliot Park Relay Replmnt, Sub 276 6/1/2014Midtown - Hiawatha 11219377 Midtown 115 kV, Line 20,963 50 12/1/2014 xMidtown - Hiawatha 11619686 Midtown Substation, Sub 7,968 75 12/15/2014 xMidtown - Hiawatha 11083245 Hiawatha Dam Interconnect Sub 7,722 - 6/1/2014 xMidtown - Hiawatha 11177566 Hiawatha Project Transmission, Line 3,309 - 6/1/2014 xMidtown - Hiawatha 11627836 Midtown 115kV Line 2(Line5565),Line 4 - 12/1/2014 x

Total Midtown - Hiawatha 39,966 125

Minn Vly-Kerkhoven Uprate 11490412 Minnesota Valley-Maynard-Kerkhoven, 10,300 323 12/31/2014 xMinn Vly-Kerkhoven Uprate 11735076 MAt-Kerk Tap Strct115kV Rebld, Line 4,733 - 12/31/2014 xMinn Vly-Kerkhoven Uprate 11742120 MNV-GFA Tap69kV,Reconductor, Line 120 2 12/31/2014 x






Minn Vly-Kerkhoven Uprate 11799723 MAT Relaying, Sub 102 13 12/31/2014 xTotal Minn Vly-Kerkhoven Uprate 15,254 338

NE Hereford auto. addition 11806042 Waseca TR3 new 69 kV switch, Sub 348 11/6/2014Total NE Hereford auto. Addition 348 -

NSP Line Capacity 11587133 2012 Line Capacity-MN, Line 3,862 10/30/2014NSP Line Capacity 11614112 Easement for NSpm Line Capacity, RO 2 12/30/2014

Total NSP Line Capacity 3,864 -

NSP Reloc B 11490515 NSPM 2014 Reloc B, Line 1,213 12/31/2014NSP Reloc B 11490531 SD 2014 Reloc B, Line 98 12/31/2014NSP Reloc B 11490443 ND 2014 Reloc B, Line 98 12/15/2014

Total NSP Reloc B 1,409 -

NSPM Group 1 Switch Replacements 11490628 NSM 0715 Lake Emily repl SW 369,370 296 5/31/2014NSPM Group 1 Switch Replacements 11776383 Freeport 4N37 4N38, Line 256 12/31/2014

Total NSPM Group 1 Switch Replacements 552 -

Red Rock 115 kV Inductor Replmnt 11642680 Red Rock Inductor Replacement, Sub 878 6/1/2014Total Red Rock 115 kV Inductor Replmnt 878 -

Riverside - Apache Upgrade 11491589 Riverside - Apache,Line 4,367 12/1/2014Riverside - Apache Upgrade 11491586 Apache Switch 5M179 to 2000A,Sub 1,676 10/1/2014

Total Riverside - Apache Upgrade 6,043 -

S&E - NSP Line 11330060 NSPM 2014 S&E B, Line 1,515 12/31/2014S&E - NSP Line 11491757 SD 2014 S&E B, Line 98 12/31/2014S&E - NSP Line 11491710 ND 2014 S&E B, Line 98 12/15/2014S&E - NSP Line 11348119 NSPM 2013 S&E, Sub 418 3/30/2014S&E - NSP Line 11348123 NSPM 2014 S&E, Sub 608 12/31/2014S&E - NSP Line 11491960 SD 2014 S&E, Sub 118 12/31/2014S&E - NSP Line 11491915 ND 2014 S&E, Sub 118 12/31/2014

Total S&E - NSP Line 2,973 -

Scott Cty 345 kV Expansion 11806389 Scott County 345 kV Expansion,Sub - 23,175 8/1/2015 xScott Cty 345 kV Expansion 11806352 Scott County 345 kV Expansion,Line - 4,183 6/1/2015 x






Scott Cty 345 kV Expansion 11806368 Scott County 345 kV Expansion,ROW 926 - 11/1/2014 xTotal Scott Cty 345 kV Expansion 926 27,359

Sioux Falls Northern 115kV Loop 11492173 Lawrence (LAW) Substation Expansion 5,086 - 4/1/2014 xSioux Falls Northern 115kV Loop 11492143 Falls New Sub ,Sub - 5,071 12/1/2015 xSioux Falls Northern 115kV Loop 11492199 West Sioux Falls (WSF) Sub Expans, - 4,388 8/1/2015 xSioux Falls Northern 115kV Loop 11722008 5559 Falls to W Sious Falls,Line - 3,405 4/27/2015 xSioux Falls Northern 115kV Loop 11722003 0729 Lawrence to Falls, Line - 2,318 7/28/2015 xSioux Falls Northern 115kV Loop 11686730 Split Rock, Sub - 2,099 6/30/2015 xSioux Falls Northern 115kV Loop 11721994 5568 Split Rock to Falls, Line - 544 7/28/2015 xSioux Falls Northern 115kV Loop 11492160 0877 Retermination into LAW Sub,Lin 419 - 6/1/2014 xSioux Falls Northern 115kV Loop 11492152 0848 Retermination into LAW Sub,Lin 356 - 6/1/2014 xSioux Falls Northern 115kV Loop 11492156 0875 Retermination into LAW Sub,Lin 335 - 6/1/2014 xSioux Falls Northern 115kV Loop 11499978 0728 69 to 115kV Conversion,Line - 251 5/30/2015 xSioux Falls Northern 115kV Loop 11492162 5508 Retermination into LAW Sub,Lin 144 - 6/1/2014 xSioux Falls Northern 115kV Loop 11749569 Lawrence Sub Line Exit & Relaying, - 24 6/1/2015 xSioux Falls Northern 115kV Loop 11722007 0730 Morrell to W Sioux Falls Dem,L - 0 2/28/2015 x

Total Sioux Falls Northern 115kV Loop 6,339 18,098

SWTC 11621622 Line 5555 Scott Cty to Excelsior,Li - 4,225 6/30/2015 xSWTC 11621531 Line 5554 Deephaven to Scott Cty, L - 2,919 6/1/2015 xSWTC 11600720 Scott County 115kV Sub 1,433 - 5/30/2014 xSWTC 11600760 Westgate 115kV Sub Termination, Sub 1,068 - 6/1/2014 xSWTC 11600752 Deephaven 115kV Sub Termination,Sub 996 - 12/1/2014 xSWTC 11621526 Line 5553 Westgsate to Deephaven, L - 890 6/1/2015 xSWTC 11621529 Line 0734-Westgate to Scott Cty,Lin 675 - 12/1/2014 xSWTC 11600743 Excelsior 115kV Sub Termination, Su 664 - 7/30/2014 xSWTC 11623792 Line 5555 Excelsior to Scott Cty, R 325 - 3/30/2014 xSWTC 11623788 Line 5554 Deephaven to Excelsior, R 280 - 4/1/2014 xSWTC 11623787 Line 5553 Westgate to Deephaven,ROW 120 - 4/1/2014 x

Total SWTC 5,561 8,035

Unserviceable - Relays - NSPM 11644893 MN 2014 Unserviceable Relay,Sub 505 12/31/2014Total Unserviceable - Relays - NSPM 505 -

Unserviceable Brkr Rplmt Program 11492698 MN 2014 Unserviceable Breaker Rplmn 564 12/31/2014Total Unserviceable Brkr Rplmt Program 564 -






Waseca TR3 11806036 0709 Waseca Tap, Line 90 9/1/2014Total Waseca TR3 90 -

Westgate Fault 11765347 Westgate Fault Current Mitigation 1,046 6/1/2014Total Westgate Fault 1,046 -

GIST-III TLines Computer Software 11465739 GIST-III TLines Computer Software 9,407 11/30/2014 xTotal GIST-III TLines Computer Software 9,407 -


NSP-WI Company

Stinson-Bayfront Rebuild 11083400 Stinson - Bayfront 115kV Line 15,977 10/31/2014 xStinson-Bayfront Rebuild 11610336 W3601-GNG-WBN 34.5kV, Line 963 4/30/2014 x

Total Stinson-Bayfront Rebuild 16,940 -

Osprey- Park Falls Rebuild 11348491 Osprey-Park Falls-W3323, Line 19,834 848 12/31/2014 xTotal Osprey- Park Falls Rebuild 19,834 848

Stone Lk - CDY 161kv 11083379 Stone Lake- Couderay 161kV Sub 1,421 12/31/2014 xStone Lk - CDY 161kv 11450122 Radisson Substation, Sub 7,874 50 12/31/2014 xStone Lk - CDY 161kv 11738970 W3472 SLK-RAD 69kV, Line 2,933 10 12/31/2014 xStone Lk - CDY 161kv 11749111 W3221 SLK-RAD New 161kV, Line 11,261 75 12/31/2014 x

Total Stone Lk - CDY 161kv 23,489 135

Total NSP-WI Company 60,264 983



Distribution Capital Plant AdditionsAddition Amounts Represent Total Project Costs Including AFUDC

2015Category Grandparent Parent # Description 2014 2015 Date StepAsset Health Cable Replacement 10229574 Nspm-Fdr Cable Replacement-Eme 3,694 3,791 Routine xAsset Health Cable Replacement 10333869 NSPM-Accelerated URD Cable Rep 10,463 12,557 Routine xAsset Health Cable Replacement 11811786 Mainline Cable Repl 2nd Tier NSPM 265 600 Routine xAsset Health General Communication Equipment 11715925 NSPM-Dist Sub Communication Equip 436 RoutineAsset Health General Communication Equipment 11733287 ND-Dist Sub Communication Equip 92 RoutineAsset Health General Communication Equipment 11793001 NSPM Feeder Load Monitoring 436 RoutineAsset Health General Communication Equipment 11810476 NSPM Remote Fault Indication 140 RoutineAsset Health General Tools and Equipment 11503264 NSPM Communication Equip-Dist Lines 135 RoutineAsset Health OH Rebuilds 10007086 Mntka-Oh Rebuilds 725 RoutineAsset Health OH Rebuilds 10007416 Edina-Oh Rebuilds 563 RoutineAsset Health OH Rebuilds 10007487 Maple Grv-Oh Rebuilds 581 RoutineAsset Health OH Rebuilds 10008512 Northwest - Overhead Rebuilds 549 RoutineAsset Health OH Rebuilds 10144490 Mpls-Oh Rebuilds 1,012 RoutineAsset Health OH Rebuilds 10144530 White Bear-Oh Rebuilds 496 RoutineAsset Health OH Rebuilds 10144755 Newport-Oh Rebuilds 442 RoutineAsset Health OH Rebuilds 10144778 Southeast-Oh Rebuilds 1,437 RoutineAsset Health OH Rebuilds 10144802 St Paul-Oh Rebuilds 811 RoutineAsset Health OH Rebuilds 10796998 Minnesota inspect/replace pole 4,139 RoutineAsset Health OH Rebuilds 11096984 MN Infratructure Invest -OH Rebuild 188 RoutineAsset Health OH Rebuilds 11325531 NSPM Inspect/Replace Poles 139 RoutineAsset Health OH Rebuilds 11698695 SSI: Conv 4KV btwn Holly & Ashland 88 RoutineAsset Health OH Rebuilds 11817148 SSI: Convt Spicer area 12.5 to 34.5 176 RoutineAsset Health OH Rebuilds 11817149 SSI: Add 3 phase line on east ALB22 154 RoutineAsset Health OH Rebuilds 11817150 SSI Convert Echo 4kV to 23.9kV dist 110 RoutineAsset Health Subs Cap Reinforce 11095139 SPCC NSPM Oil Spill Prevention 571 RoutineAsset Health Subs Equip Replace 10006417 Minnesota- Dist Sub Eq Replace 2,850 RoutineAsset Health Subs Equip Replace 11361768 NSPM Repl Under Frequency Relays 1,890 RoutineAsset Health Subs Equip Replace 11648601 Substation Fence Improvement 286 RoutineAsset Health Subs Equip Replace 11648602 Substation Transformer Replacements 1,229 RoutineAsset Health Subs Equip Replace 11649517 Retire Subs in MN 147 RoutineAsset Health Subs Equip Replace 11817152 SSI: Convert Echo 4kV - retire sub 47 RoutineAsset Health System Reliability 10229647 NSPM-Poor Perf Fdr Replace Blk 1,198 RoutineAsset Health System Reliability 10796852 Intelliteam SG Rollout 170 RoutineAsset Health System Reliability 10948327 Reliability Monitoring Sys REM 908 RoutineAsset Health System Reliability 10953801 Install Auto Source Transfer for MN 44 RoutineAsset Health System Reliability 11100811 Reliability Monitoring System Minn 0 RoutineAsset Health System Reliability 11100848 Reliability Monitoring System Mine 7 RoutineAsset Health System Reliability 11100858 Reliability Monitoring System Edina 3 RoutineAsset Health System Reliability 11100863 Reliability Monitoring System Fari 6 RoutineAsset Health System Reliability 11100869 Reliability Monitoring System Newpo 5 RoutineAsset Health System Reliability 11100898 Reliability Monitoring System WBear 15 RoutineAsset Health System Reliability 11100904 Reliability Monitoring System NW 7 RoutineAsset Health System Reliability 11648597 Distribution Automation 458 RoutineAsset Health System Reliability 11811792 Add Midpoint Reclosers 79 RoutineAsset Health System Reliability 11811795 Install Automated Switches - MN 196 Routine





2015Category Grandparent Parent # Description 2014 2015 Date Step


Asset Health UG ConvrsnsRebuilds 10006957 Mpls-Ug Conversion/Rebuild 1,734 RoutineAsset Health UG ConvrsnsRebuilds 10144503 Mntka-Ug Conversion/Rebuild 579 RoutineAsset Health UG ConvrsnsRebuilds 10144515 Edina-Ug Conversions/Rebuild 746 RoutineAsset Health UG ConvrsnsRebuilds 10144531 White Bear-Ug Conv/Rebuilds 278 RoutineAsset Health UG ConvrsnsRebuilds 10144573 Maple Grv-Ug Conversion/Rebuil 924 RoutineAsset Health UG ConvrsnsRebuilds 10144642 Northwest-Ug Conversion/Rebuil 100 RoutineAsset Health UG ConvrsnsRebuilds 10144756 Newport-Ug Conversions/Rebuild 531 RoutineAsset Health UG ConvrsnsRebuilds 10144779 Southeast-Ug Conv/Rebuilds 470 RoutineAsset Health UG ConvrsnsRebuilds 10144803 St Paul-Ug Conversions/Rebuild 647 RoutineAsset Health UG ConvrsnsRebuilds 11810479 LaSalle Paving Project 1,208 12/31/2014Asset Health UG Extension 10381269 2004 Elec Recon Carryover-NSPM 3,868 RoutineAsset Health UG Network 10522944 Replace 7 CM2 Network Protecto 154 RoutineAsset Health UG Network 10522951 Replace Vault Top 745 RoutineAsset Health UG Services Conversion 10404795 Mpls-OH to UG Service Conv 160 RoutineAsset Health UG Services Conversion 10404807 Mntka-Oh to UG Service Conv 67 RoutineAsset Health UG Services Conversion 10404810 Edina-OH to UG Service Conv 86 RoutineAsset Health UG Services Conversion 10404812 White Bear-OH to UG Service Co 67 RoutineAsset Health UG Services Conversion 10404815 Maple Grv-OH to UG Service Con 25 RoutineAsset Health UG Services Conversion 10404822 Northwest-OH to UG Service Con 23 RoutineAsset Health UG Services Conversion 10404836 Newport-OH to UG Service Conv 23 RoutineAsset Health UG Services Conversion 10404844 Southeast-OH to UG Service Con 18 RoutineAsset Health UG Services Conversion 10404850 St Paul-OH to UG Service Conv 107 RoutineAsset Health VAR Network Sys Project 11328950 VAR - Network System Project 780 Routine

Total Asset Health 50,726 16,949

Capacity Midtown - Hiawatha 10950387 Inst 38.8kV Hiawatha #1 50MVA 5,120 5/31/2014 xCapacity Midtown - Hiawatha 10952711 Inst UG Feeder from Hiawatha #1 - 8,539 5/31/2015 xCapacity Midtown - Hiawatha 10953983 Inst 13.8kv Oakland #1 50mva 8,589 5/31/2014 xCapacity OH Reinforcements 10144492 Mpls-Oh Reinforcements 83 RoutineCapacity OH Reinforcements 10144504 Mntka-Oh Reinforcements 57 RoutineCapacity OH Reinforcements 10144516 Edina-Oh Reinforcements 251 RoutineCapacity OH Reinforcements 10144532 White Bear-Oh Reinforcements 122 RoutineCapacity OH Reinforcements 10144574 Maple Grv-Oh Reinforcements 128 RoutineCapacity OH Reinforcements 10144643 Northwest-Oh Reinforcements 179 RoutineCapacity OH Reinforcements 10144757 Newport-Oh Reinforcements 92 RoutineCapacity OH Reinforcements 10144780 Southeast-Oh Reinforcements 260 RoutineCapacity OH Reinforcements 10144804 St Paul-Oh Reinforcements 245 RoutineCapacity OH Reinforcements 11648963 Install 2 Fdrs from Chemolite Sub 1,129 4/30/2014Capacity OH Reinforcements 11649213 Pipestone new TR feeders & exits 842 RoutineCapacity OH Reinforcements 11649256 Install new feeder at RAM 421 RoutineCapacity OH Reinforcements 11649518 MN Infrastructure Invest- OH Reinf 122 RoutineCapacity OH Reinforcements 11786905 Add WAS331 234 RoutineCapacity OH Reinforcements 11811820 Extend DBL074 and Reconfigure 493 RoutineCapacity OH Reinforcements 11811826 Reinforce 3 miles of SMT082 491 RoutineCapacity OH Reinforcements 11812021 New First Lake feeder FSL311 633 Routine






Capacity Other Capital 11521115 Capitalized-MN-Sales Tax Rfd - Elec (754) RoutineCapacity Right of Way 11812041 Land for new First Lake Sub 600 9/30/2014Capacity Subs Cap Reinforce 10006393 Minnesota-Sub Capac Reinforcem 427 RoutineCapacity Subs Cap Reinforce 10954877 reinf 13.8kv BCR #1 50MVA 3,917 RoutineCapacity Subs Cap Reinforce 11160584 Add fans Lowry TR1, repl regs 148 RoutineCapacity Subs Cap Reinforce 11160613 New First Lake sub 273 RoutineCapacity Subs Cap Reinforce 11426403 Install a 50MVA 115/13.8 kV transfo 197 RoutineCapacity Subs Cap Reinforce 11648951 Convert Chemolite to 13.8kV 3,551 5/31/2014Capacity Subs Cap Reinforce 11649199 Install Pipestone TR 14 MVA 1,686 6/30/2014Capacity Subs Cap Reinforce 11649259 Install new breaker off RAM TR1 347 5/31/2014Capacity Subs Cap Reinforce 11700613 Install Cap Bank at Crystal Foods 240 RoutineCapacity Subs Cap Reinforce 11786903 Add 28MVA WASTR3 and 1 fdr 1,990 RoutineCapacity Subs Cap Reinforce 11799598 Reinforce Lake Emily TR1 to 14MVA 1,645 RoutineCapacity Subs Cap Reinforce 11810473 Rewind 69/12.5 kV 28 MVA 395 5/31/2014Capacity UG Extension 10650009 Dist Sub - Non-Discr Contingen 312 RoutineCapacity UG Network 10144486 Mpls- New Ug Network 267 RoutineCapacity UG Network 10144798 St Paul-Ug Network 295 RoutineCapacity UG Reinforcements 10144493 Mpls-Ug Reinforcement 576 RoutineCapacity UG Reinforcements 10144505 Mntka-Ug Reinforcements 36 RoutineCapacity UG Reinforcements 10144517 Edina-Ug Reinforcements 802 RoutineCapacity UG Reinforcements 10144533 White Bear-Ug Reinforcements 134 RoutineCapacity UG Reinforcements 10144575 Maple Grv-Ug Reinforcements 1 RoutineCapacity UG Reinforcements 10144644 Northwest-Ug Reinforcement 17 RoutineCapacity UG Reinforcements 10144758 Newport-Ug Reinforcements 325 RoutineCapacity UG Reinforcements 10144781 Southeast-Ug Reinforcements 291 RoutineCapacity UG Reinforcements 10144805 St Paul-Ug Reinforcements 55 RoutineCapacity UG Reinforcements 10954865 Inst 2 Fdrs from BCR#1 2,228 RoutineCapacity UG Reinforcements 10954893 Environmental Work NSPM EL 242 RoutineCapacity UG Reinforcements 11420660 New Ductline on 5th btwn Broadway & 651 RoutineCapacity UG Reinforcements 11648598 Install arrestors in load centers 116 RoutineCapacity UG Reinforcements 11810480 New Service for General Office (GO) 492 RoutineCapacity UG Reinforcements 11811811 Extend EDP061 to relieve EDP fdrs 493 RoutineCapacity UG Reinforcements 11811814 Extend VKG fdr 493 RoutineCapacity UG Reinforcements 11811848 Reinforce feeder exit for TWL062 443 RoutineCapacity UG Reinforcements 11811851 Install BCR new feeder at Basset Cr 591 Routine

Total Capacity 43,016 8,539

Mandates OH Relocations 10144494 Mpls-Oh Relocations 299 RoutineMandates OH Relocations 10144506 Mntka-Oh Relocations 391 RoutineMandates OH Relocations 10144518 Edina-Oh Relocations 279 RoutineMandates OH Relocations 10144576 Maple Grv-Oh Relocations 284 RoutineMandates OH Relocations 10144645 Northwest-Oh Relocations 654 RoutineMandates OH Relocations 10144759 Newport-Oh Relocations 411 RoutineMandates OH Relocations 10144782 Southeast-Oh Relocations 1,083 RoutineMandates OH Relocations 10144806 St Paul-Oh Relocations 206 Routine






Mandates OH Relocations 10146153 White Bear Oh Relocations 523 RoutineMandates OH Relocations 11398809 NSPM 3rd Party owned Pole Transfers 62 RoutineMandates OH Relocations 11639197 WCF - Mandates - NSPM 1,565 RoutineMandates UG ConvrsnsRebuilds 11230885 Replace Distribution Cabinets-NSPM 70 RoutineMandates UG Relocations 10144495 Mpls-Ug Relocations 418 RoutineMandates UG Relocations 10144507 Mntka-Ug Relocations 72 RoutineMandates UG Relocations 10144519 Edina-Ug Relocations 277 RoutineMandates UG Relocations 10144535 White Bear-Ug Relocations 84 RoutineMandates UG Relocations 10144578 Maple Grv-Ug Relocations 154 RoutineMandates UG Relocations 10144646 Northwest-Ug Relocations 69 RoutineMandates UG Relocations 10144760 Newport-Ug Relocations 175 RoutineMandates UG Relocations 10144783 Southeast-Ug Relocations 119 RoutineMandates UG Relocations 10144807 St Paul-Ug Relocations 43 Routine

Total Mandates 7,239 -

New Business Meter Purchases 10006968 Minnesota-Electric Meter Blank 4,791 5,147 Routine xNew Business Transformer Purchases 10007463 Minnesota- New Bus Transformer 18,563 19,258 Routine xNew Business CIAC 10144489 Mpls-Elec Non-Refundable Ciac (507) RoutineNew Business CIAC 10144502 Mntka-Elec Non-Refundable CIAC (161) RoutineNew Business CIAC 10144514 Edina-Elec Non-Refundable CIAC (237) RoutineNew Business CIAC 10144529 Wb-Elec Non-Refundable Ciac (277) RoutineNew Business CIAC 10144572 Mplgrv-Elec Non-Refundable Cia (148) RoutineNew Business CIAC 10144641 Nw-Elec Non-Refundable Ciac (234) RoutineNew Business CIAC 10144754 Npt-Elec Non-Refundable Ciac (250) RoutineNew Business CIAC 10144777 Se-Elec Non-Refundable Ciac (305) RoutineNew Business CIAC 10144801 St P-Elec Non-Refundable Ciac (228) RoutineNew Business OH Extension 10144483 Mpls-Oh Extension 446 RoutineNew Business OH Extension 10144497 Mntka-Oh Extension 99 RoutineNew Business OH Extension 10144509 Edina-Oh Extension 83 RoutineNew Business OH Extension 10144521 White Bear-Oh Extension 189 RoutineNew Business OH Extension 10144563 Maple Grv-Oh Extension 91 RoutineNew Business OH Extension 10144636 Northwest-New Oh Extensions 569 RoutineNew Business OH Extension 10144748 Newport-Oh Extension 107 RoutineNew Business OH Extension 10144771 Southeast-Oh Extension 597 RoutineNew Business OH Extension 10144795 St Paul-Oh Extension 213 RoutineNew Business OH Services 10144484 Mpls-Oh Services 390 RoutineNew Business OH Services 10144498 Mntka-Oh Services 44 RoutineNew Business OH Services 10144510 Edina-New Oh Services 90 RoutineNew Business OH Services 10144523 White Bear-Oh Services 101 RoutineNew Business OH Services 10144565 Maple Grv-Oh Services 48 RoutineNew Business OH Services 10144637 Northwest-New Oh Services 115 RoutineNew Business OH Services 10144749 Newport-Oh Services 46 RoutineNew Business OH Services 10144772 Southeast-Oh Services 161 RoutineNew Business OH Services 10144796 St Paul-Oh Services 182 RoutineNew Business OH Street Lights 10144487 Mpls-New Oh Street Lights 224 Routine






New Business OH Street Lights 10144500 Mntka-New Oh Street Lights 19 RoutineNew Business OH Street Lights 10144512 Edina-New Oh Street Lights 36 RoutineNew Business OH Street Lights 10144527 White Bear-Oh Street Lights 56 RoutineNew Business OH Street Lights 10144561 Maple Grv-New Oh Street Lights 53 RoutineNew Business OH Street Lights 10144635 Northwest-New Oh Street Lights 116 RoutineNew Business OH Street Lights 10144752 Newport-Oh Streetlights 126 RoutineNew Business OH Street Lights 10144775 Southeast-Oh Streetlights 211 RoutineNew Business OH Street Lights 10144799 St Paul-Oh Streetlights 89 RoutineNew Business UG Extension 10006954 Mpls-New Ug Extension 1,312 RoutineNew Business UG Extension 10007068 Mntka- New Ug Extension 417 RoutineNew Business UG Extension 10007391 Edina-Ug Extensions 1,123 RoutineNew Business UG Extension 10007457 Maple Grv- Elec Ug Extension 968 RoutineNew Business UG Extension 10008491 Northwest - Ug Extensions 1,093 RoutineNew Business UG Extension 10145065 Newport-Ug Extensions 1,310 RoutineNew Business UG Extension 10145070 Southeast-Ug Extensions 1,217 RoutineNew Business UG Extension 10145179 St Paul-Ug Extensions 806 RoutineNew Business UG Extension 10145833 White Bear Ug Extensions 957 RoutineNew Business UG Reinforcements 10381265 Elec New Bus Carryover-NSP 258 RoutineNew Business UG Services 10144485 Mpls-New Ug Services 272 RoutineNew Business UG Services 10144499 Mntka-New Ug Services 360 RoutineNew Business UG Services 10144511 Edina-Ug Services 287 RoutineNew Business UG Services 10144525 White Bear-Ug Services 929 RoutineNew Business UG Services 10144566 Maple Grv-New Elec Ug Services 359 RoutineNew Business UG Services 10144638 Northwest-New Ug Services 448 RoutineNew Business UG Services 10144750 Newport-Ug Services 711 RoutineNew Business UG Services 10144773 Southeast-Ug Services 579 RoutineNew Business UG Services 10144797 St Paul-Ug Services 61 RoutineNew Business UG Street Lights 10144488 Mpls-New Ug Street Lights 149 RoutineNew Business UG Street Lights 10144501 Mntka-New Ug Street Lights 121 RoutineNew Business UG Street Lights 10144513 Edina-New Ug Street Lights 316 RoutineNew Business UG Street Lights 10144528 White Bear-Ug Street Lts 294 RoutineNew Business UG Street Lights 10144570 Maple Grv-New Ug Street Lights 265 RoutineNew Business UG Street Lights 10144640 Northwest-New Ug Street Lights 66 RoutineNew Business UG Street Lights 10144753 Newport-Ug Streetlights 136 RoutineNew Business UG Street Lights 10144776 Southeast-Ug Streetlights 105 RoutineNew Business UG Street Lights 10144800 St Paul-Ug Streetlights 10 Routine

Total New Business 40,436 24,405

Other General Tools and Equipment 10006666 Tools & Equipment-Transportati 106 RoutineOther General Tools and Equipment 10006686 Spec Cnstr - Sm Tool/Equi 105 RoutineOther General Tools and Equipment 10007058 Mpls-Elec Tool/Equip 121 RoutineOther General Tools and Equipment 10007114 Mntka-Elec Tools/Equip 32 RoutineOther General Tools and Equipment 10007315 South Dakota - Tools & Equip 102 RoutineOther General Tools and Equipment 10007440 Edina-Elect Tool/Equip 30 RoutineOther General Tools and Equipment 10007517 Maple Grv-Elec Tools/Equip 46 Routine






Other General Tools and Equipment 10008596 Northwest - Elec Tools/Equip 66 RoutineOther General Tools and Equipment 10008652 Newport-Elec Tool/Equip 30 RoutineOther General Tools and Equipment 10144491 Minnesota- Dist Sub Tool/Equip 439 RoutineOther General Tools and Equipment 10144536 White Bear-Electric Tools & Eq 30 RoutineOther General Tools and Equipment 10144713 North Dakota -Elec Tools & Eq 37 RoutineOther General Tools and Equipment 10144784 Southeast-Elec Tools & Equip 87 RoutineOther General Tools and Equipment 10144808 St Paul-Elec Tools & Equip 30 RoutineOther General Tools and Equipment 10229363 Nspm Metering Sys-Tools & Equi 61 RoutineOther General Tools and Equipment 10233671 Mn-Construct Dist Sub Tool & E 94 RoutineOther General Tools and Equipment 10790334 Logistics - NSPM - Tools 163 RoutineOther General Tools and Equipment 11201746 Logistics - Fencing - NSPM 31 RoutineOther General Tools and Equipment 11201748 Logistics - Security Equipment-NSPM 43 RoutineOther General Tools and Equipment 11226930 Logistics - NSPM - Tools - ND 13 RoutineOther General Tools and Equipment 11236978 Logistics - Tools - SD 12 RoutineOther General Tools and Equipment 11466030 Hennepin Trng ElecTools&Equip 65 RoutineOther General Tools and Equipment 11774433 NSPM Locating Tools & Equip. 60 RoutineOther General Transportation 10557022 Fleet New Unit Purchase El Ops 3,269 RoutineOther General Transportation 10557030 Fleet New Unit Purchase Common 738 RoutineOther General Transportation 10593255 Transportation Blanket Elec 2 RoutineOther General Transportation 10741615 Fleet New Unit Purchase El Ops 295 RoutineOther General Transportation 10741648 Fleet New Unit Purchase El Ops 504 RoutineOther General Transportation 10741664 Fleet New Unit Purchase Common 15 RoutineOther Other Capital 11586869 Mpls-Electric Trouble Tools & Equip 35 RoutineOther Other Capital 11586871 St Paul-Elec TroubleTools & Equip 26 RoutineOther UG Relocations 10437120 Capitalized Locating Cost-Elec 229 Routine

Total Other 6,917 -




I/T Capital Additions for Testimony GuidanceAddition Amounts Represent Total Project Costs Including AFUDC

2015Category Grandparent Parent # Description Classification 2014 2015 Date StepAging Technology General Ledger System 11765111 General Ledger Repl Ph 1 SW MN Common Intangible Plant - 27,721 12/31/2015 xAging Technology BT_Business Demand 11088759 2013 Planned PC Refresh Common General Plant 114 RoutineAging Technology BT_Business Demand 11088691 2013 Wireless Hardware MN Common General Plant 55 RoutineAging Technology BT_Business Demand 11088743 2013 Server Refresh Common General Plant 18 RoutineAging Technology BT_Business Demand 11620719 BS-Fcst-BD-SW-EL-M Electric Intangible Plant 666 RoutineAging Technology BT_Business Demand 11506687 EPM Ph2 Transmission MN Electric Intangible Plant 768 6/30/2014Aging Technology BT_Business Demand 11735625 Meridium New Version MN Electric Intangible Plant 407 3/15/2014Aging Technology BT_Business Demand 11217809 BS-Fcst-OTI-SW-CM-M Common Intangible Plant 406 RoutineAging Technology BT_Business Demand 11795601 EPM Ph4 Supply Chain MN Common Intangible Plant 561 9/30/2014Aging Technology BT_Critical Sys Upgrades/Rplmt(<5M) 11584375 Purch EMS DEMS Ph2 Hardware MN Electric General Plant 1,521 12/31/2014Aging Technology BT_Critical Sys Upgrades/Rplmt(<5M) 11599358 Service Suite 10 MN Common Intangible Plant 2,784 12/15/2014Aging Technology BT_HW Refreshes 11683109 Purch Prairie Island Radio MN Electric General Plant 4,264 12/31/2014Aging Technology BT_HW Refreshes 11490487 2014 Planned PC Refresh MN Common General Plant 2,482 12/31/2014Aging Technology BT_HW Refreshes 11812504 2014 Planned MDT MN Common General Plant 1,044 12/31/2014Aging Technology BT_HW Refreshes 11102493 2013 Unplanned PC Refresh Common General Plant 88 RoutineAging Technology BT_HW Refreshes 11490622 2014 Unplanned PC Refresh MN Common General Plant 638 12/31/2014Aging Technology BT_HW Refreshes 11490585 2014 Planned Voice Refresh MN Common General Plant 260 12/31/2014Aging Technology BT_HW Refreshes 11102283 2013 Unplanned Server Refresh Common General Plant 39 RoutineAging Technology BT_HW Refreshes 11087493 2013 Unplanned LAN WAN Refresh Common General Plant 3 RoutineAging Technology BT_HW Refreshes 11490633 2014 Unplanned Radio Microwave MN Common General Plant 130 12/31/2014Aging Technology BT_HW Refreshes 11802109 2014 Handheld Mobile MN Common General Plant 81 12/31/2014Aging Technology BT_HW Refreshes 11501718 2014 Unplanned MDT Refresh Common General Plant 67 11/30/2014Aging Technology BT_HW Refreshes 11490539 2014 Planned Radio Microwave M Common General Plant 65 12/31/2014Aging Technology BT_HW Refreshes 11490668 2014 Unplanned Voice Refresh M Common General Plant 52 12/31/2014Aging Technology BT_HW Refreshes 11087479 2012 Unplanned LAN WAN Refresh Common General Plant 0 RoutineAging Technology BT_Other IT Infrastructure 11622348 BS-Fcst-OTI-COMM-EL-M Electric General Plant 291 RoutineAging Technology BT_Other IT Infrastructure 11227014 BS-Fcst-OTI-NW-CM-M Common General Plant 1,700 RoutineAging Technology BT_Other IT Infrastructure 11490556 2014 Planned Server Refresh MN Common General Plant 720 12/31/2014Aging Technology BT_Other IT Infrastructure 11490690 2014 Storage Project MN Common General Plant 1,575 12/31/2014Aging Technology BT_Other IT Infrastructure 11490639 2014 Unplanned Server Refresh MN Common General Plant 480 12/31/2014Aging Technology BT_Other IT Infrastructure 11490461 2014 Planned LAN/WAN Refresh MN Common General Plant 200 12/31/2014Aging Technology BT_Other IT Infrastructure 11227116 BS-Fcst-HardwareR-NW-CM-M Common General Plant 163 RoutineAging Technology BT_Other IT Infrastructure 11490595 2014 Unplanned LAN WAN Refresh MN Common General Plant 104 12/31/2014Aging Technology BT_Other IT Infrastructure 11490571 2014 Planned Telecom Refresh M Common General Plant 78 12/31/2014Aging Technology BT_Other IT Infrastructure 11490648 2014 Unplanned Telecom Refresh MN Common General Plant 52 12/31/2014Aging Technology BT_Other IT Infrastructure 11491835 Windows 7 OS Migration SW MN Common Intangible Plant 2,818 3/31/2014Aging Technology MI_Enterprise Asset Management 11491932 Enterprise Asset Managment SW Common Intangible Plant 2,989 MultipleAging Technology MI_Network Strategy 11802563 Purch NS T&D Network Equip MN Electric General Plant 2,565 RoutineAging Technology MI_Network Strategy 11802573 Purch NS Dist Network Equip MN Electric General Plant 117 Routine

Total Aging Technology 30,364 27,721

Cyber Security BT_IT Security 11727512 Identity and Access Mgmt SW MN Common Intangible Plant 3,247 12/31/2014Cyber Security BT_IT Security 11685113 GRC Compliance SW MN Common Intangible Plant 2,957 11/15/2014Cyber Security BT_IT Security 11382280 BS-Fcst-ITS-SW-CM-M Common Intangible Plant 249 RoutineCyber Security BT_IT Security 11382243 BS-Fcst-ITS-NW-CM-M Common General Plant 1,307 RoutineCyber Security MI_Enhanced Internal Infra 11621474 Enhanced Internal Infra MN Common General Plant 500 12/31/2014

Total Cyber Security 8,260 -




I/T Capital Additions for Testimony GuidanceAddition Amounts Represent Total Project Costs Including AFUDC

2015Category Grandparent Parent # Description Classification 2014 2015 Date Step


Increase Efficiencies Regulatory Process Standard SW - RIS 11438090 Regulatory Process Standard SW Common Intangible Plant - 5,313 2/1/2015 xIncrease Efficiencies BT_Legal/Regulatory Required 11570111 MISO Synchrophaser MN Electric General Plant 811 3/15/2014Increase Efficiencies BT_Legal/Regulatory Required 11556086 GIST Ph3 SW MN Electric Intangible Plant 2,047 8/15/2014Increase Efficiencies BT_Legal/Regulatory Required 11785698 MISO PCI New Module MN Electric Intangible Plant 1,660 3/30/2014Increase Efficiencies BT_Business Demand 11549754 ESC Environmental Compliance S Common Intangible Plant 24 12/30/2013Increase Efficiencies BT_Business Demand 11698547 CMS Phase 4 MN Common Intangible Plant 3,747 10/15/2014Increase Efficiencies BT_Business Demand 11218004 BS-Fcst-MI-SW-CM-M Common Intangible Plant 956 RoutineIncrease Efficiencies BT_Business Demand 11753867 My Account New Module MN Common Intangible Plant 1,906 2/28/2014Increase Efficiencies BT_Business Demand 11560088 SharePoint Wired New Version M Common Intangible Plant 1,078 11/30/2014Increase Efficiencies BT_Business Demand 11679479 ELearning LMS New Version MN Common Intangible Plant 821 6/15/2014

Total Increase Efficiencies 13,049 5,313

Emergent Demand Account BT_Business Demand 11218029 BS-Fcst-BD-SW-CM-M Common Intangible Plant 17,546 RoutineTotal Emergent Demand Account 17,546 -

NSP-MN Company 69,219 33,033



Corporate/Other Capital Additions for Testimony GuidanceAddition Amounts Represent Total Project Costs Including AFUDC

2015Category Parent # Description 2014 2015 Date StepET_Physical Security (CEO Only) 10987155 NSPM E Corp Sec Furn 388 380 RoutineET_Physical Security (CEO Only) 11368301 NSPM E Corp Sec Ntwk 161 160 RoutineET_Physical Security (CEO Only) 10987149 NSPM C Corp Sec Furn 354 350 RoutineForbes Communication 11806289 Forbes Communication Upgrade,Sub 533 - 12/1/2014Franchise Renewals 11453550 Franchise Renewal Elec 77 79 RoutineGeneral Building 11225367 Electrical Capital projects 6 0 12/31/2015General Building 11225112 Building Renovation/Remodel 3,385 7,098 RoutineGeneral Building 11225245 Mechanical 3,204 1,929 RoutineGeneral Building 10950500 Misc Building Projects 712 121 RoutineGeneral Building 11225241 Structural 683 178 RoutineGeneral Building 11225246 Roof Replacement 167 364 RoutineGeneral Building 11225235 Electrical 409 339 RoutineGeneral Building 11225306 Unbudgeted Emergencies 178 270 RoutineGeneral Building 11225220 Roads and Gates 31 2 RoutineGeneral Furniture 11225333 Office Furn & Equipment 6 0 12/31/2015General Furniture 11225275 Office Furniture & equipment 829 174 RoutineGeneral Software 11813718 GIS Model Improvements - NSPM 249 996 12/31/2018General Tools and Equipment 11492336 NSP COM Tool 2014, Sub 962 - 12/31/2014General Tools and Equipment 11227972 SHCCC 2013 Tools & Equipment 11 0 RoutineGeneral Tools and Equipment 11227975 SHCCC 2014 Tools & Equipment 180 - 12/30/2014General Tools and Equipment 11084048 SHCJC UJ Tools and Equipment 11 0 RoutineGeneral Tools and Equipment 11210718 SER-0-C-SMC- 2014 Misc Tools 160 - 11/17/2014General Tools and Equipment 11083273 ASK0C-2013 Tool Blanket 1 - RoutineGeneral Tools and Equipment 11071339 SER-0-C SMC 2013 Misc tools 1 - RoutineGeneral Tools and Equipment 11217858 ASK0C-2014 Tool Blanket 120 - 10/18/2014General Tools and Equipment 11217412 SHCJC 2014 Misc Tools & Equip 104 - 12/30/2014General Tools and Equipment 11631060 SER0CMMR0415 Wear Metals Analy 81 - 5/1/2014General Tools and Equipment 11492296 2014 Tool Blanket MN, Line 50 25 12/31/2014General Tools and Equipment 11492290 2014 Civil Dept Tool B, Line 75 - 12/31/2014General Tools and Equipment 11210774 BDS0C 2014 Tool Blanket 73 - 12/27/2014General Tools and Equipment 11215943 RIV0C-2014 Tool Blanket 60 - 6/20/2014General Tools and Equipment 11228129 SER-0-C CHM0314 Misc Tools 53 - 4/1/2014General Tools and Equipment 11349270 SER0C -RTC 2014 Tools 50 - 7/10/2014General Tools and Equipment 11492292 2014 Survey Group Tool B, Line 50 - 12/31/2014General Tools and Equipment 11358855 SER0C MMR1403 Purch Videoprobe 50 - 7/7/2014





2015Category Parent # Description 2014 2015 Date Step


General Tools and Equipment 11217515 HBC0C HB CC Tool Blank 2014 50 - 12/27/2014General Tools and Equipment 11812716 SERV-CHM-Pour Point Instrument 8 - 12/6/2013General Tools and Equipment 11349251 SER0C -RTC 2013 Tools 0 - RoutineGeneral Tools and Equipment 11358852 SER0C MMR1402 Purch Alloy Anal 35 - 4/4/2014General Tools and Equipment 11812709 SERV-CHM-Auto Digestion Block 5 - 12/6/2013General Tools and Equipment 10785744 SER-0-C PMO0113 Wireless Test 0 - RoutineGeneral Tools and Equipment 11812722 SERV-CHM-Oil Grease Analyzer 31 - 4/1/2014General Tools and Equipment 11358870 SER0C MTR0901 Videoscope IPLE 31 - 12/29/2014General Tools and Equipment 11216049 REW0114 RED WING 2014 CAPITAL 30 - 9/23/2014General Tools and Equipment 11216209 WLM0C 2014 Tools & Equipment B 30 - 12/29/2014General Tools and Equipment 11228250 SER-0-C MMR1401 Equip & Tools 30 - 4/4/2014General Tools and Equipment 11088351 SER-0-C-CHM0313 Misc. Tools 1 - RoutineGeneral Tools and Equipment 11084519 SER0C-MMR1301-Tools and Equip 0 - RoutineGeneral Tools and Equipment 11215926 NBLC0 2014 Misc Tools Equip Bl 20 - 11/28/2014General Tools and Equipment 11482987 SERV-0-C-CSC0113-Air Compresso 16 - 3/10/2014General Tools and Equipment 11217647 HNIC0 2014 Misc Tools Equip Bl 15 - 8/3/2014General Tools and Equipment 11082583 HNIC0 2013 HNI Small Tools Blanket 0 - RoutineGeneral Tools and Equipment 11078894 BLLC0 2013 Misc Tools Blanket 0 - RoutineGeneral Tools and Equipment 11483421 SER0C-MMR-1404-Equip. & Misc T 15 - 7/14/2014General Tools and Equipment 11215836 ANSC0 2014 Misc Tools and Equi 15 - 11/29/2014General Tools and Equipment 11215850 BLLC0 2014 Misc Tools & Equip 15 - 12/30/2014General Tools and Equipment 11215923 IVHC0 2014 Misc Tools Equip Bl 15 - 12/2/2014General Tools and Equipment 11633906 SERV-PMO014 High Temp Thermome 11 - 2/18/2014General Tools and Equipment 11215898 GDMC0 2014 Misc Tools & Equip 10 - 9/24/2014General Tools and Equipment 11633907 SERV-PMO0314Process Laptop Com 5 - 2/4/2014General Tools and Equipment 11482472 SERV-0-C-CHM0114-Calorimeter A 3 - 2/25/2014General Tools and Equipment 10637411 SHCJC Misc Mobile Equipment Re (1) - RoutineGeneral Tools and Equipment 10383535 SS Corporate Communications Au 68 68 RoutineGeneral Tools and Equipment 10937196 CS Cap Tools & Equipment - Com 0 - RoutineGeneral Tools and Equipment 11225252 Tools & Equipment 0 - RoutineGeneral Transportation 11302834 Fleet New Units 2014 El Trans, MN 980 - 12/31/2014General Transportation 11631310 SER-0-C-SMC- 2014 Vehichles 96 - 5/15/2014General Transportation 11644944 ASK0C-Vehicles 2014 35 - 9/26/2014General Transportation 11130541 Transportation Blanket, Trans MN (52) (7) RoutineMI_Energy Management System 10818773 Dynamic EMS Environment Phase 12,105 - 12/31/2014




2015Category Parent # Description 2014 2015 Date Step


Other Capital 11434783 GIST-II Computer Software,NSPM 4,573 - 10/31/2014Strategic Technology (CEO Only) 10812281 Strategic Technology - NSPM 801 1,117 RoutineTool 11631088 SER0CCHM0417 Closed Cup FlashP 25 - 3/28/2014Tools COM Substation 11787149 NSP Ops Engineering Tools 2014 125 - 12/31/2014Tools COM Substation 11787197 NSPM COM Tools 2014 (BU 8640) 120 - 12/31/2014Tools, Training Center 11782739 Tools 2014, Training Center, NSPM 77 - 12/31/2014

NSP-MN Company 32,806 13,643





New Wind Depreciation Page 1 of 1

Remaining Life requested 25Net Salvage Rate -8.50%

Depreciation Expense Formula (Beg Plant * (1 - Net Salvage)) - Beg Reserve)/Remaining Months + ((Additions/2) * (1 - Net Salvage))/Remaining Months

Border Wind

Plant In-service Depreciation Reserve

Beg Bal Additions RetirementsTransfers/

Adjustments End Bal Remaining

months Beg Bal Provision Retirements Transfers/

Adjustments End Bal

2014 December - - 2015 January - - - - - - - - - -

February - - - - - - - - - - March - - - - - - - - - - April - - - - - - - - - - May - - - - - - - - - - June - - - - - - - - - - July - - - - - - - - - -

August - - - - - - - - - - September - - - - - - - - - - October - - - - - - - - - -

[TRADE SECRET BEGINS [TRADE SECRET BEGINSNovember - 300 - 478,229 - - 478,229

2015 December - 299 478,229 958,834 - - 1,437,063 2015 Total - TRADE SECRET ENDS] 1,437,063 - -

TRADE SECRET ENDS2015 Beg/End Avg 132,443,033 718,532

2015 13 Mo Avg 40,718,818 147,330

Pleasant Valley



Adjustments End Bal Remaining

months Beg Bal Provision Retirements Transfers/

Adjustments End Bal


February - - - - - - - - - - March - - - - - - - - - - April - - - - - - - - - - May - - - - - - - - - - June - - - - - - - - - - July - - - - - - - - - -

August - - - - - - - - - - September - - - - - - - - - -

[TRADE SECRET BEGINS [TRADE SECRET BEGINSOctober - 300 - 616,905 - - 616,905

November - 299 616,905 1,236,268 - - 1,853,173 2015 December - 298 1,853,174 1,236,924 - - 3,090,098

2015 Total - TRADE SECRET ENDS 3,090,097 - - TRADE SECRET ENDS

2015 Beg/End Avg 170,752,889 1,545,049 2015 13 Mo Avg 78,770,372 427,706

PUBLIC DOCUMENT - TRADE SECRET DATA EXCISED


Docket No. E002/GR-13-868Exhibit___(LHP-1),Schedule 10

General Ledger Page 1 of 1

Life requested 15Depreciation Expense Formula (Beg Plant/(Life * 12) + (Additions/2)/(Life * 12)

General Ledger



Adjustments End Bal Beg Bal Provision Retirements Transfers/

Adjustments End Bal


February - - - - - - - - - - March - - - - - - - - - - April - - - - - - - - - - May - - - - - - - - - - June -$ 27,720,779$ -$ -$ 27,720,779$ -$ 77,002$ -$ -$ 77,002$ July 27,720,779$ -$ -$ -$ 27,720,779$ 77,002$ 154,004$ -$ -$ 231,006$

August 27,720,779$ -$ -$ -$ 27,720,779$ 231,006$ 154,004$ -$ -$ 385,011$ September 27,720,779$ -$ -$ -$ 27,720,779$ 385,011$ 154,004$ -$ -$ 539,015$ October 27,720,779$ -$ -$ -$ 27,720,779$ 539,015$ 154,004$ -$ -$ 693,019$

November 27,720,779$ -$ -$ -$ 27,720,779$ 693,019$ 154,004$ -$ -$ 847,024$ 2015 December 27,720,779$ -$ -$ -$ 27,720,779$ 847,024$ 154,004$ -$ -$ 1,001,028$

2015 Total 27,720,779$ -$ -$ 1,001,028$ -$ -$ 2015 Beg/End Avg 13,860,390$ 500,514$

2015 13 Mo Avg 14,926,573$ 290,239$

Northern States Power CompanyElectric Utility - State of MinnesotaDepreciation Change Summary


Page 1 of 7

Electric and Common Utilities

Plant Activity Reserve Activity - Original Rates Reserve Activity - New Rates

MonthBeginning Balance Additions Retirements

Transfers In

Transfers Out Adjustments Ending Balance

Beginning Balance

Depreciation Expense Retirements

Cost of Removal Salvage Cash

Reserve Transfer In

Reserve Transfer Out Reserve Adjustment Ending Balance

Beginning Balance

Depreciation Expense

Retirement

Cost of Removal

Salvage Cash

Reserve Transfer In

Reserve Transfer Out

Reserve Adjustment Ending Balance

Common General - BuildingsJanuary-14 139,900,878$ 799,221$ -$ -$ -$ -$ 140,700,099$ 15,634,764$ 263,807$ -$ (55,618)$ 3,872$ -$ -$ -$ 15,846,824$ 15,567,595$ 255,090$ -$ (55,618)$ 3,872$ -$ -$ -$ 15,770,938$

February-14 140,700,099$ 725,031$ -$ -$ -$ -$ 141,425,130$ 15,846,824$ 265,240$ -$ (53,524)$ 3,012$ -$ -$ -$ 16,061,551$ 15,770,938$ 256,475$ -$ (53,524)$ 3,012$ -$ -$ -$ 15,976,901$ March-14 141,425,130$ 679,469$ -$ -$ -$ -$ 142,104,600$ 16,061,551$ 266,560$ -$ (51,688)$ 2,342$ -$ -$ -$ 16,278,765$ 15,976,901$ 257,752$ -$ (51,688)$ 2,342$ -$ -$ -$ 16,185,307$

April-14 142,104,600$ 672,091$ -$ -$ -$ -$ 142,776,691$ 16,278,765$ 267,831$ -$ (59,157)$ 1,822$ -$ -$ -$ 16,489,261$ 16,185,307$ 258,981$ -$ (59,157)$ 1,822$ -$ -$ -$ 16,386,952$ May-14 142,776,691$ 712,159$ -$ -$ -$ -$ 143,488,850$ 16,489,261$ 269,132$ -$ (103,368)$ 1,417$ -$ -$ -$ 16,656,442$ 16,386,952$ 260,239$ -$ (103,368)$ 1,417$ -$ -$ -$ 16,545,240$ June-14 143,488,850$ 718,854$ -$ -$ -$ -$ 144,207,705$ 16,656,442$ 270,478$ -$ (83,787)$ 1,102$ -$ -$ -$ 16,844,235$ 16,545,240$ 261,540$ -$ (83,787)$ 1,102$ -$ -$ -$ 16,724,096$ July-14 144,207,705$ 713,236$ -$ -$ -$ -$ 144,920,941$ 16,844,235$ 271,824$ -$ (67,244)$ 857$ -$ -$ -$ 17,049,672$ 16,724,096$ 262,842$ -$ (67,244)$ 857$ -$ -$ -$ 16,920,551$

August-14 144,920,941$ 649,140$ -$ -$ -$ -$ 145,570,081$ 17,049,672$ 273,105$ -$ (52,968)$ 667$ -$ -$ -$ 17,270,476$ 16,920,551$ 264,081$ -$ (52,968)$ 667$ -$ -$ -$ 17,132,331$ September-14 145,570,081$ 598,763$ -$ -$ -$ -$ 146,168,844$ 17,270,476$ 274,278$ -$ (41,864)$ 519$ -$ -$ -$ 17,503,409$ 17,132,331$ 265,215$ -$ (41,864)$ 519$ -$ -$ -$ 17,356,201$

October-14 146,168,844$ 734,547$ -$ -$ -$ -$ 146,903,392$ 17,503,409$ 275,532$ -$ (64,116)$ 403$ -$ -$ -$ 17,715,228$ 17,356,201$ 266,427$ -$ (64,116)$ 403$ -$ -$ -$ 17,558,915$ November-14 146,903,392$ 856,699$ -$ -$ -$ -$ 147,760,091$ 17,715,228$ 277,028$ -$ (73,868)$ 314$ -$ -$ -$ 17,918,701$ 17,558,915$ 267,874$ -$ (73,868)$ 314$ -$ -$ -$ 17,753,235$ December-14 147,760,091$ 947,193$ -$ -$ -$ -$ 148,707,284$ 17,918,701$ 278,723$ -$ (81,231)$ 244$ -$ -$ -$ 18,116,438$ 17,753,235$ 269,514$ -$ (81,231)$ 244$ -$ -$ -$ 17,941,762$

Common General - Buildings-LeasedJanuary-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 922,141$ 13,775$ -$ -$ -$ -$ -$ -$ 935,915$

February-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 935,915$ 13,775$ -$ -$ -$ -$ -$ -$ 949,690$ March-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 949,690$ 13,775$ -$ -$ -$ -$ -$ -$ 963,464$

April-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 963,464$ 13,775$ -$ -$ -$ -$ -$ -$ 977,239$ May-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 977,239$ 13,775$ -$ -$ -$ -$ -$ -$ 991,013$ June-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 991,013$ 13,775$ -$ -$ -$ -$ -$ -$ 1,004,788$ July-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 1,004,788$ 13,775$ -$ -$ -$ -$ -$ -$ 1,018,562$

August-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 1,018,562$ 13,775$ -$ -$ -$ -$ -$ -$ 1,032,337$ September-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 1,032,337$ 13,775$ -$ -$ -$ -$ -$ -$ 1,046,111$

October-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 1,046,111$ 13,775$ -$ -$ -$ -$ -$ -$ 1,059,886$ November-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 1,059,886$ 13,775$ -$ -$ -$ -$ -$ -$ 1,073,661$ December-14 1,652,945$ -$ -$ -$ -$ -$ 1,652,945$ 825,719$ -$ -$ -$ -$ -$ -$ -$ 825,719$ 1,073,661$ 13,775$ -$ -$ -$ -$ -$ -$ 1,087,435$

Common General - Furniture and Equipment -$ January-14 28,205,359$ 20,218$ -$ -$ -$ -$ 28,225,577$ 17,630,613$ 106,674$ -$ (260)$ -$ -$ -$ -$ 17,737,026$ 17,545,909$ 96,006$ -$ (260)$ -$ -$ -$ -$ 17,641,654$

February-14 28,225,577$ 12,596$ -$ -$ -$ -$ 28,238,174$ 17,737,026$ 106,732$ -$ (87)$ -$ -$ -$ -$ 17,843,672$ 17,641,654$ 96,058$ -$ (87)$ -$ -$ -$ -$ 17,737,626$ March-14 28,238,174$ 153,072$ -$ -$ -$ -$ 28,391,245$ 17,843,672$ 107,441$ -$ (6,696)$ -$ -$ -$ -$ 17,944,417$ 17,737,626$ 96,696$ -$ (6,696)$ -$ -$ -$ -$ 17,827,626$

April-14 28,391,245$ 215,589$ -$ -$ -$ -$ 28,606,834$ 17,944,417$ 108,439$ -$ (3,899)$ -$ -$ -$ -$ 18,048,957$ 17,827,626$ 97,594$ -$ (3,899)$ -$ -$ -$ -$ 17,921,322$ May-14 28,606,834$ 233,274$ -$ -$ -$ -$ 28,840,108$ 18,048,957$ 109,519$ -$ (3,300)$ -$ -$ -$ -$ 18,155,176$ 17,921,322$ 98,566$ -$ (3,300)$ -$ -$ -$ -$ 18,016,588$ June-14 28,840,108$ 123,482$ -$ -$ -$ -$ 28,963,590$ 18,155,176$ 110,090$ -$ (1,100)$ -$ -$ -$ -$ 18,264,167$ 18,016,588$ 99,081$ -$ (1,100)$ -$ -$ -$ -$ 18,114,569$ July-14 28,963,590$ 93,246$ -$ -$ -$ -$ 29,056,836$ 18,264,167$ 101,602$ -$ (367)$ -$ -$ -$ -$ 18,365,402$ 18,114,569$ 99,469$ -$ (367)$ -$ -$ -$ -$ 18,213,671$

August-14 29,056,836$ 83,151$ -$ -$ -$ -$ 29,139,987$ 18,365,402$ 100,309$ -$ (122)$ -$ -$ -$ -$ 18,465,589$ 18,213,671$ 97,255$ -$ (122)$ -$ -$ -$ -$ 18,310,804$ September-14 29,139,987$ 84,512$ -$ -$ -$ -$ 29,224,499$ 18,465,589$ 100,701$ -$ (41)$ -$ -$ -$ -$ 18,566,249$ 18,310,804$ 90,630$ -$ (41)$ -$ -$ -$ -$ 18,401,393$

October-14 29,224,499$ 78,613$ -$ -$ -$ -$ 29,303,112$ 18,566,249$ 101,065$ -$ (2,014)$ -$ -$ -$ -$ 18,665,300$ 18,401,393$ 90,957$ -$ (2,014)$ -$ -$ -$ -$ 18,490,337$ November-14 29,303,112$ 70,544$ -$ -$ -$ -$ 29,373,656$ 18,665,300$ 101,391$ -$ (3,338)$ -$ -$ -$ -$ 18,763,353$ 18,490,337$ 91,251$ -$ (3,338)$ -$ -$ -$ -$ 18,578,251$ December-14 29,373,656$ 67,760$ -$ -$ -$ -$ 29,441,416$ 18,763,353$ 101,705$ -$ (1,113)$ -$ -$ -$ -$ 18,863,946$ 18,578,251$ 91,534$ -$ (1,113)$ -$ -$ -$ -$ 18,668,672$

Common General - Transporation EquipmentJanuary-14 13,053,916$ 156,417$ -$ -$ -$ -$ 13,210,333$ 7,356,558$ 83,278$ -$ 496$ 1,552$ -$ -$ -$ 7,441,883$ 7,270,869$ 72,083$ -$ 496$ 1,552$ -$ -$ -$ 7,344,999$

February-14 13,210,333$ 136,890$ -$ -$ -$ -$ 13,347,223$ 7,441,883$ 84,302$ -$ 297$ 931$ -$ -$ -$ 7,527,414$ 7,344,999$ 72,969$ -$ 297$ 931$ -$ -$ -$ 7,419,197$ March-14 13,347,223$ 114,414$ -$ -$ -$ -$ 13,461,637$ 7,527,414$ 84,989$ -$ 178$ 559$ -$ -$ -$ 7,613,140$ 7,419,197$ 73,710$ -$ 178$ 559$ -$ -$ -$ 7,493,644$

April-14 13,461,637$ 118,848$ -$ -$ -$ -$ 13,580,486$ 7,613,140$ 85,687$ -$ 107$ 335$ -$ -$ -$ 7,699,269$ 7,493,644$ 74,479$ -$ 107$ 335$ -$ -$ -$ 7,568,565$ May-14 13,580,486$ 92,869$ -$ -$ -$ -$ 13,673,355$ 7,699,269$ 86,381$ -$ 64$ 201$ -$ -$ -$ 7,785,915$ 7,568,565$ 74,821$ -$ 64$ 201$ -$ -$ -$ 7,643,651$ June-14 13,673,355$ 73,681$ -$ -$ -$ -$ 13,747,036$ 7,785,915$ 86,933$ -$ 39$ 121$ -$ -$ -$ 7,873,007$ 7,643,651$ 75,246$ -$ 39$ 121$ -$ -$ -$ 7,719,057$ July-14 13,747,036$ 54,969$ -$ -$ -$ -$ 13,802,005$ 7,873,007$ 87,344$ -$ 23$ 72$ -$ -$ -$ 7,960,446$ 7,719,057$ 75,602$ -$ 23$ 72$ -$ -$ -$ 7,794,754$

August-14 13,802,005$ 54,541$ -$ -$ -$ -$ 13,856,547$ 7,960,446$ 87,533$ -$ 14$ 43$ -$ -$ -$ 8,048,036$ 7,794,754$ 75,955$ -$ 14$ 43$ -$ -$ -$ 7,870,766$ September-14 13,856,547$ 57,845$ -$ -$ -$ -$ 13,914,391$ 8,048,036$ 87,840$ -$ 8$ 26$ -$ -$ -$ 8,135,910$ 7,870,766$ 76,329$ -$ 8$ 26$ -$ -$ -$ 7,947,130$

October-14 13,914,391$ 38,307$ -$ -$ -$ -$ 13,952,698$ 8,135,910$ 87,577$ -$ 5$ 16$ -$ -$ -$ 8,223,508$ 7,947,130$ 76,489$ -$ 5$ 16$ -$ -$ -$ 8,023,640$ November-14 13,952,698$ 37,304$ -$ -$ -$ -$ 13,990,002$ 8,223,508$ 87,783$ -$ 3$ 9$ -$ -$ -$ 8,311,303$ 8,023,640$ 76,534$ -$ 3$ 9$ -$ -$ -$ 8,100,187$ December-14 13,990,002$ 61,862$ -$ -$ -$ -$ 14,051,865$ 8,311,303$ 88,246$ -$ 2$ 6$ -$ -$ -$ 8,399,557$ 8,100,187$ 76,717$ -$ 2$ 6$ -$ -$ -$ 8,176,911$

Northern States Power Company Docket No. E002/GR-13-868Electric Utility - State of MinnesotaDepreciation Change Summary


Exhibit___(LHP-1), Schedule 11Page 2 of 7

Approved Eight-Year Theoretical Reserve Amortization

Depreciation Rate Changes

(Total Company)


(MN Jurisdiction)

Theoretical Reserve

Amortization (MN Jurisdiction)

Total Change (MN

Jurisdiction)

Electric Intangible -$ -$ (45,632)$ (45,632)$ Electric Transmission (6,090,710)$ (4,527,826)$ (18,699,675)$ (23,227,501)$ Electric Distribution 18,578,011$ 18,578,011$ (13,670,294)$ 4,907,717$ Electric General (1,334,043)$ (1,168,873)$ (736,089)$ (1,904,962)$ Electric Total 11,153,259$ 12,881,312$ (33,151,690)$ (20,270,378)$

Common Intangible -$ -$ 123,267$ 123,267$ Common General (189,739)$ (153,914)$ 373,567$ 219,653$ Common Total (189,739)$ (153,914)$ 496,834$ 342,920$

Total - All Utilities 10,963,520$ 12,727,398$ (32,654,856)$ (19,927,458)$

Proposed Decline Pattern Theoretical Reserve Amortization


(Total Company)


(MN Jurisdiction)

Theoretical Reserve

Amortization (MN Jurisdiction)

Total Change (MN

Jurisdiction)

Electric Intangible -$ -$ (159,711)$ (159,711)$ Electric Transmission (6,090,710)$ (4,527,826)$ (65,448,861)$ (69,976,687)$ Electric Distribution 18,578,011$ 18,578,011$ (47,846,029)$ (29,268,019)$ Electric General (1,334,043)$ (1,168,873)$ (2,576,313)$ (3,745,186)$ Electric Total 11,153,259$ 12,881,312$ (116,030,915)$ (103,149,603)$

Common Intangible -$ -$ 431,435$ 431,435$ Common General (189,739)$ (153,914)$ 1,307,485$ 1,153,571$ Common Total (189,739)$ (153,914)$ 1,738,920$ 1,585,006$

Total - All Utilities 10,963,520$ 12,727,398$ (114,291,995)$ (101,564,597)$





Account 2014 Average Plant

Balance Original

Rate Used

Original Depreciation

(Total Company) New Rate

Used

New Depreciation

(Total Company)

Change in Depreciation

(Total Company)

Jurisdictional Allocator

Change in Depreciation

(MN Jurisdiction)

Electric Transmission - Lines 1,337,065,002$ 0$ 26,768,468$ 0$ 27,987,113$ 1,218,644$ Electric Transmission - Lines-Production 6,623,587$ 0$ 168,258$ 0$ 131,352$ (36,906)$ Electric Transmission - Substations-Prod 65,105,891$ 0$ 1,670,283$ 0$ 1,227,376$ (442,907)$ Electric Transmission - Substations 1,016,879,591$ 0$ 26,554,310$ 0$ 19,724,769$ (6,829,541)$ Electric Transmission Total 2,425,674,071$ 55,161,320$ 49,070,610$ (6,090,710)$ 74.3399% (4,527,826)

Electric Distribution - Lines 1,738,448,844$ 0$ 32,713,282$ 0$ 48,311,891$ 15,598,609$ Electric Distribution - Other 693,634,269$ 0$ 18,846,293$ 0$ 25,651,289$ 6,804,996$ Electric Distribution - Plant Leased to Others 1,908,570$ 0$ 55,237$ 0$ 41,632$ (13,606)$ Electric Distribution - Street Lighting 54,363,817$ 0$ 2,606,163$ 0$ 2,527,544$ (78,619)$ Electric Distribution - Substations 516,421,472$ 0$ 15,046,425$ 0$ 11,338,292$ (3,708,133)$ Electric Distribution - Substations-Prod 3,530,619$ 0$ 102,140$ 0$ 76,904$ (25,236)$ Electric Distribution Total 3,008,307,591$ 69,369,540$ 87,947,551$ 18,578,011$ 100.0000% 18,578,011

Electric General - Buildings 60,208,573$ 0$ 1,338,104$ 0$ 1,267,598$ (70,506)$ Electric General - Furniture and Equipment 25,127,149$ 0$ 1,391,303$ 0$ 1,252,597$ (138,706)$ Electric General - Transportation Equipment 128,457,941$ 0$ 10,940,526$ 0$ 9,815,695$ (1,124,831)$ Electric General Total 213,793,663$ 13,669,933$ 12,335,891$ (1,334,043)$ 87.6189% (1,168,873)

Electric Utility Total 5,647,775,325$ 138,200,793$ 149,354,052$ 11,153,259$ 12,881,312

Common General - Buildings 144,304,081$ 0$ 3,253,536$ 0$ 3,146,029$ (107,507)$ Common General - Buildings-Leased 1,652,945$ -$ -$ 0$ 165,294$ 165,294$ Common General - Furniture and Equipment 28,823,388$ 0$ 1,255,667$ 0$ 1,145,097$ (110,570)$ Common General - Transportation Equipment 13,552,890$ 0$ 1,037,892$ 0$ 900,935$ (136,957)$ Common General Total 188,333,304$ 5,547,095$ 5,357,355$ (189,739)$ 81.1188% (153,914)

Total - Electric and Common Utilities 5,836,108,629$ 143,747,888$ 154,711,407$ 10,963,520$ 12,727,398




Approved 2014 Proposed Reserve Surplus Eight-Year Remaining Declining

(MN Jursidiction) Amortization Surplus Balance

Electric Intangible 365,054$ (45,632)$ 319,422$ (159,711)$ Electric Transmission 149,597,398$ (18,699,675)$ 130,897,723$ (65,448,861)$ Electric Distribution 109,362,353$ (13,670,294)$ 95,692,059$ (47,846,029)$ Electric General 5,888,716$ (736,089)$ 5,152,626$ (2,576,313)$ Electric Total 265,213,520$ (33,151,690)$ 232,061,830$ (116,030,915)$

Common Intangible (986,137)$ 123,267$ (862,870)$ 431,435$ Common General (2,988,538)$ 373,567$ (2,614,970)$ 1,307,485$ Common Total (3,974,675)$ 496,834$ (3,477,841)$ 1,738,920$

Total - All Utilities 261,238,845$ (32,654,856)$ 228,583,989$ (114,291,995)$

Note: Proposed Declining Balance Amortization is 50% for 2014



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Electric Transmission - LinesJanuary-14 1,151,288,736$ 423,138$ (493,999)$ -$ -$ -$ 1,151,217,875$ 389,752,980$ 1,928,160$ (493,999)$ (101,225)$ 26,213$ -$ -$ -$ 391,112,129$ 390,446,212$ 2,015,940$ (493,999)$ (101,225)$ 26,213$ -$ -$ -$ 391,893,142$

February-14 1,151,217,875$ 11,032,736$ (493,999)$ -$ -$ -$ 1,161,756,612$ 391,112,129$ 1,936,926$ (493,999)$ (51,009)$ 22,180$ -$ -$ -$ 392,526,228$ 391,893,142$ 2,025,106$ (493,999)$ (51,009)$ 22,180$ -$ -$ -$ 393,395,419$ March-14 1,161,756,612$ 561,707$ (493,999)$ -$ -$ -$ 1,161,824,320$ 392,526,228$ 1,945,808$ (493,999)$ (202,728)$ 18,768$ -$ -$ -$ 393,794,077$ 393,395,419$ 2,034,392$ (493,999)$ (202,728)$ 18,768$ -$ -$ -$ 394,751,852$

April-14 1,161,824,320$ 83,523,857$ (493,999)$ -$ -$ -$ 1,244,854,178$ 393,794,077$ 2,015,396$ (493,999)$ (133,956)$ 15,880$ -$ -$ -$ 395,197,398$ 394,751,852$ 2,107,147$ (493,999)$ (133,956)$ 15,880$ -$ -$ -$ 396,246,925$ May-1 1,244,854,178$ 100,296,279$ (493,999)$ -$ -$ -$ 1,344,656,457$ 395,197,398$ 2,168,503$ (493,999)$ (83,874)$ 13,437$ -$ -$ -$ 396,801,465$ 396,246,925$ 2,267,224$ (493,999)$ (83,874)$ 13,437$ -$ -$ -$ 397,949,714$ June-14 1,344,656,457$ 26,920,989$ (493,999)$ -$ -$ -$ 1,371,083,448$ 396,801,465$ 2,274,209$ (493,999)$ (30,480)$ 11,370$ -$ -$ -$ 398,562,565$ 397,949,714$ 2,377,743$ (493,999)$ (30,480)$ 11,370$ -$ -$ -$ 399,814,348$ July-14 1,371,083,448$ 66,366,034$ (493,999)$ -$ -$ -$ 1,436,955,482$ 398,562,565$ 2,351,502$ (493,999)$ (27,007)$ 9,621$ -$ -$ -$ 400,402,682$ 399,814,348$ 2,458,555$ (493,999)$ (27,007)$ 9,621$ -$ -$ -$ 401,761,518$

August-14 1,436,955,482$ 392,355$ (493,999)$ -$ -$ -$ 1,436,853,839$ 400,402,682$ 2,406,579$ (493,999)$ (28,872)$ 8,140$ -$ -$ -$ 402,294,531$ 401,761,518$ 2,516,140$ (493,999)$ (28,872)$ 8,140$ -$ -$ -$ 403,762,927$ September-14 1,436,853,839$ 8,751,787$ (493,999)$ -$ -$ -$ 1,445,111,627$ 402,294,531$ 2,413,410$ (493,999)$ (237,027)$ 10,442$ -$ -$ -$ 403,987,357$ 403,762,927$ 2,523,281$ (493,999)$ (237,027)$ 10,442$ -$ -$ -$ 405,565,625$

October-14 1,445,111,627$ 1,280,589$ (493,999)$ -$ -$ -$ 1,445,898,217$ 403,987,357$ 2,420,983$ (493,999)$ (12,860)$ 5,828$ -$ -$ -$ 405,907,310$ 405,565,625$ 2,531,200$ (493,999)$ (12,860)$ 5,828$ -$ -$ -$ 407,595,794$ November-14 1,445,898,217$ 60,392$ (493,999)$ -$ -$ -$ 1,445,464,610$ 405,907,310$ 2,421,279$ (493,999)$ (10,929)$ 4,932$ -$ -$ -$ 407,828,592$ 407,595,794$ 2,531,509$ (493,999)$ (10,929)$ 4,932$ -$ -$ -$ 409,627,306$ December-14 1,445,464,610$ 77,870,658$ (493,999)$ -$ -$ -$ 1,522,841,269$ 407,828,592$ 2,485,713$ (493,999)$ (192,941)$ 4,173$ -$ -$ -$ 409,631,537$ 409,627,306$ 2,598,875$ (493,999)$ (192,941)$ 4,173$ -$ -$ -$ 411,543,414$

Electric Transmission - Lines-ProductionJanuary-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 398,782$ 14,022$ -$ -$ -$ -$ -$ -$ 412,803$ 374,178$ 10,946$ -$ -$ -$ -$ -$ -$ 385,124$

February-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 412,803$ 14,022$ -$ -$ -$ -$ -$ -$ 426,825$ 385,124$ 10,946$ -$ -$ -$ -$ -$ -$ 396,070$ March-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 426,825$ 14,022$ -$ -$ -$ -$ -$ -$ 440,846$ 396,070$ 10,946$ -$ -$ -$ -$ -$ -$ 407,016$

April-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 440,846$ 14,022$ -$ -$ -$ -$ -$ -$ 454,868$ 407,016$ 10,946$ -$ -$ -$ -$ -$ -$ 417,962$ May-1 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 454,868$ 14,022$ -$ -$ -$ -$ -$ -$ 468,889$ 417,962$ 10,946$ -$ -$ -$ -$ -$ -$ 428,908$ June-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 468,889$ 14,022$ -$ -$ -$ -$ -$ -$ 482,911$ 428,908$ 10,946$ -$ -$ -$ -$ -$ -$ 439,854$ July-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 482,911$ 14,022$ -$ -$ -$ -$ -$ -$ 496,933$ 439,854$ 10,946$ -$ -$ -$ -$ -$ -$ 450,800$

August-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 496,933$ 14,022$ -$ -$ -$ -$ -$ -$ 510,954$ 450,800$ 10,946$ -$ -$ -$ -$ -$ -$ 461,746$ September-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 510,954$ 14,022$ -$ -$ -$ -$ -$ -$ 524,976$ 461,746$ 10,946$ -$ -$ -$ -$ -$ -$ 472,692$

October-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 524,976$ 14,022$ -$ -$ -$ -$ -$ -$ 538,997$ 472,692$ 10,946$ -$ -$ -$ -$ -$ -$ 483,638$ November-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 538,997$ 14,022$ -$ -$ -$ -$ -$ -$ 553,019$ 483,638$ 10,946$ -$ -$ -$ -$ -$ -$ 494,584$ December-14 6,623,587$ -$ -$ -$ -$ -$ 6,623,587$ 553,019$ 14,022$ -$ -$ -$ -$ -$ -$ 567,040$ 494,584$ 10,946$ -$ -$ -$ -$ -$ -$ 505,530$

Electric Transmission - Substations-ProdJanuary-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 32,620,368$ 139,190$ -$ -$ -$ -$ -$ -$ 32,759,558$ 32,325,097$ 102,281$ -$ -$ -$ -$ -$ -$ 32,427,378$

February-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 32,759,558$ 139,190$ -$ -$ -$ -$ -$ -$ 32,898,749$ 32,427,378$ 102,281$ -$ -$ -$ -$ -$ -$ 32,529,660$ March-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 32,898,749$ 139,190$ -$ -$ -$ -$ -$ -$ 33,037,939$ 32,529,660$ 102,281$ -$ -$ -$ -$ -$ -$ 32,631,941$

April-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 33,037,939$ 139,190$ -$ -$ -$ -$ -$ -$ 33,177,129$ 32,631,941$ 102,281$ -$ -$ -$ -$ -$ -$ 32,734,222$ May-1 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 33,177,129$ 139,190$ -$ -$ -$ -$ -$ -$ 33,316,320$ 32,734,222$ 102,281$ -$ -$ -$ -$ -$ -$ 32,836,504$ June-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 33,316,320$ 139,190$ -$ -$ -$ -$ -$ -$ 33,455,510$ 32,836,504$ 102,281$ -$ -$ -$ -$ -$ -$ 32,938,785$ July-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 33,455,510$ 139,190$ -$ -$ -$ -$ -$ -$ 33,594,700$ 32,938,785$ 102,281$ -$ -$ -$ -$ -$ -$ 33,041,067$

August-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 33,594,700$ 139,190$ -$ -$ -$ -$ -$ -$ 33,733,890$ 33,041,067$ 102,281$ -$ -$ -$ -$ -$ -$ 33,143,348$ September-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 33,733,890$ 139,190$ -$ -$ -$ -$ -$ -$ 33,873,081$ 33,143,348$ 102,281$ -$ -$ -$ -$ -$ -$ 33,245,629$

October-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 33,873,081$ 139,190$ -$ -$ -$ -$ -$ -$ 34,012,271$ 33,245,629$ 102,281$ -$ -$ -$ -$ -$ -$ 33,347,911$ November-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 34,012,271$ 139,190$ -$ -$ -$ -$ -$ -$ 34,151,461$ 33,347,911$ 102,281$ -$ -$ -$ -$ -$ -$ 33,450,192$ December-14 65,105,891$ -$ -$ -$ -$ -$ 65,105,891$ 34,151,461$ 139,190$ -$ -$ -$ -$ -$ -$ 34,290,651$ 33,450,192$ 102,281$ -$ -$ -$ -$ -$ -$ 33,552,473$

Electric Transmission - SubstationsJanuary-14 956,333,077$ 1,223,064$ (349,938)$ -$ -$ -$ 957,206,203$ 275,671,358$ 2,082,122$ (349,938)$ (10,091)$ -$ -$ -$ -$ 277,393,451$ 271,572,278$ 1,546,618$ (349,938)$ (10,091)$ -$ -$ -$ -$ 272,758,867$

February-14 957,206,203$ 428,028$ (349,938)$ -$ -$ -$ 957,284,293$ 277,393,451$ 2,083,157$ (349,938)$ (13,196)$ -$ -$ -$ -$ 279,113,474$ 272,758,867$ 1,547,387$ (349,938)$ (13,196)$ -$ -$ -$ -$ 273,943,120$ March-14 957,284,293$ 29,284,368$ (349,938)$ -$ -$ -$ 986,218,723$ 279,113,474$ 2,114,726$ (349,938)$ (265,127)$ -$ -$ -$ -$ 280,613,135$ 273,943,120$ 1,570,836$ (349,938)$ (265,127)$ -$ -$ -$ -$ 274,898,892$

April-14 986,218,723$ 10,442,324$ (349,938)$ -$ -$ -$ 996,311,108$ 280,613,135$ 2,157,191$ (349,938)$ (11,201)$ -$ -$ -$ -$ 282,409,186$ 274,898,892$ 1,602,380$ (349,938)$ (11,201)$ -$ -$ -$ -$ 276,140,132$ May-1 996,311,108$ 17,369,109$ (349,938)$ -$ -$ -$ 1,013,330,279$ 282,409,186$ 2,186,691$ (349,938)$ (37,717)$ -$ -$ -$ -$ 284,208,222$ 276,140,132$ 1,624,293$ (349,938)$ (37,717)$ -$ -$ -$ -$ 277,376,769$ June-14 1,013,330,279$ 28,482,494$ (349,938)$ -$ -$ -$ 1,041,462,834$ 284,208,222$ 2,235,820$ (349,938)$ (12,242)$ -$ -$ -$ -$ 286,081,862$ 277,376,769$ 1,660,787$ (349,938)$ (12,242)$ -$ -$ -$ -$ 278,675,376$ July-14 1,041,462,834$ 3,390,290$ (349,938)$ -$ -$ -$ 1,044,503,187$ 286,081,862$ 2,269,740$ (349,938)$ (25,665)$ -$ -$ -$ -$ 287,975,998$ 278,675,376$ 1,685,982$ (349,938)$ (25,665)$ -$ -$ -$ -$ 279,985,755$

August-14 1,044,503,187$ 906,169$ (349,938)$ -$ -$ -$ 1,045,059,418$ 287,975,998$ 2,273,653$ (349,938)$ (171,508)$ -$ -$ -$ -$ 289,728,205$ 279,985,755$ 1,688,889$ (349,938)$ (171,508)$ -$ -$ -$ -$ 281,153,198$ September-14 1,045,059,418$ 2,025,767$ (349,938)$ -$ -$ -$ 1,046,735,246$ 289,728,205$ 2,276,082$ (349,938)$ (109,622)$ -$ -$ -$ -$ 291,544,727$ 281,153,198$ 1,690,693$ (349,938)$ (109,622)$ -$ -$ -$ -$ 282,384,330$

October-14 1,046,735,246$ 2,002,031$ (349,938)$ -$ -$ -$ 1,048,387,339$ 291,544,727$ 2,279,703$ (349,938)$ (16,199)$ -$ -$ -$ -$ 293,458,293$ 282,384,330$ 1,693,383$ (349,938)$ (16,199)$ -$ -$ -$ -$ 283,711,576$ November-14 1,048,387,339$ 730,404$ (349,938)$ -$ -$ -$ 1,048,767,805$ 293,458,293$ 2,281,915$ (349,938)$ (2,959)$ -$ -$ -$ -$ 295,387,310$ 283,711,576$ 1,695,026$ (349,938)$ (2,959)$ -$ -$ -$ -$ 285,053,704$ December-14 1,048,767,805$ 29,008,238$ (349,938)$ -$ -$ -$ 1,077,426,105$ 295,387,310$ 2,313,512$ (349,938)$ (141,145)$ -$ -$ -$ -$ 297,209,738$ 285,053,704$ 1,718,496$ (349,938)$ (141,145)$ -$ -$ -$ -$ 286,281,117$



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Electric Distribution - LinesJanuary-14 1,694,397,254 6,673,474 (994,046) - - - 1,700,076,682 652,023,587 2,662,034 (994,046)$ (429,211)$ 4,318$ -$ -$ -$ 653,266,682$ 662,014,659$ 3,931,367$ (994,046)$ (429,211)$ 4,318$ -$ -$ -$ 664,527,087$

February-14 1,700,076,682 6,624,062 (994,046) - - - 1,705,706,697 653,266,682 2,670,903 (994,046)$ (417,719)$ 3,391$ -$ -$ -$ 654,529,212$ 664,527,087$ 3,944,465$ (994,046)$ (417,719)$ 3,391$ -$ -$ -$ 667,063,178$ March-14 1,705,706,697 7,908,218 (994,046) - - - 1,712,620,869 654,529,212 2,680,741 (994,046)$ (441,603)$ 2,000,590$ -$ -$ -$ 657,774,893$ 667,063,178$ 3,958,993$ (994,046)$ (441,603)$ 2,000,590$ -$ -$ -$ 671,587,111$

April-14 1,712,620,869 9,548,401 (994,046) - - - 1,721,175,223 657,774,893 2,692,872 (994,046)$ (460,828)$ 2,150$ -$ -$ -$ 659,015,040$ 671,587,111$ 3,976,908$ (994,046)$ (460,828)$ 2,150$ -$ -$ -$ 674,111,295$ May-14 1,721,175,223 12,116,542 (994,046) - - - 1,732,297,719 659,015,040 2,708,303 (994,046)$ (512,623)$ 1,723$ -$ -$ -$ 660,218,397$ 674,111,295$ 3,999,697$ (994,046)$ (512,623)$ 1,723$ -$ -$ -$ 676,606,046$ June-14 1,732,297,719 8,869,578 (994,046) - - - 1,740,173,250 660,218,397 2,723,201 (994,046)$ (538,759)$ 1,384$ -$ -$ -$ 661,410,176$ 676,606,046$ 4,021,700$ (994,046)$ (538,759)$ 1,384$ -$ -$ -$ 679,096,324$ July-14 1,740,173,250 7,510,371 (994,046) - - - 1,746,689,575 661,410,176 2,734,488 (994,046)$ (584,052)$ 1,112$ -$ -$ -$ 662,567,678$ 679,096,324$ 4,038,368$ (994,046)$ (584,052)$ 1,112$ -$ -$ -$ 681,557,706$

August-14 1,746,689,575 8,851,687 (994,046) - - - 1,754,547,216 662,567,678 2,745,760 (994,046)$ (579,678)$ 895$ -$ -$ -$ 663,740,609$ 681,557,706$ 4,055,016$ (994,046)$ (579,678)$ 895$ -$ -$ -$ 684,039,893$ September-14 1,754,547,216 7,949,484 (994,046) - - - 1,761,502,653 663,740,609 2,757,377 (994,046)$ (491,269)$ 718$ -$ -$ -$ 665,013,389$ 684,039,893$ 4,072,172$ (994,046)$ (491,269)$ 718$ -$ -$ -$ 686,627,467$

October-14 1,761,502,653 8,263,899 (994,046) - - - 1,768,772,506 665,013,389 2,768,533 (994,046)$ (466,088)$ 577$ -$ -$ -$ 666,322,365$ 686,627,467$ 4,088,647$ (994,046)$ (466,088)$ 577$ -$ -$ -$ 689,256,557$ November-14 1,768,772,506 7,264,842 (994,046) - - - 1,775,043,302 666,322,365 2,779,152 (994,046)$ (410,440)$ 464$ -$ -$ -$ 667,697,494$ 689,256,557$ 4,104,329$ (994,046)$ (410,440)$ 464$ -$ -$ -$ 691,956,864$ December-14 1,775,043,302 8,451,178 (994,046) - - - 1,782,500,433 667,697,494 2,789,918 (994,046)$ (384,459)$ 373$ -$ -$ -$ 669,109,279$ 691,956,864$ 4,120,229$ (994,046)$ (384,459)$ 373$ -$ -$ -$ 694,698,960$

Electric Distribution - OtherJanuary-14 699,545,781 - (985,252) - - - 698,560,529 278,485,064 1,582,794 (985,252)$ (91)$ -$ -$ -$ -$ 279,082,515$ 283,094,539$ 2,154,307$ (985,252)$ (91)$ -$ -$ -$ -$ 284,263,503$

February-14 698,560,529 - (985,252) - - - 697,575,277 279,082,515 1,580,563 (985,252)$ (82)$ -$ -$ -$ -$ 279,677,744$ 284,263,503$ 2,151,271$ (985,252)$ (82)$ -$ -$ -$ -$ 285,429,440$ March-14 697,575,277 - (985,252) - - - 696,590,025 279,677,744 1,578,332 (985,252)$ (74)$ -$ -$ -$ -$ 280,270,750$ 285,429,440$ 2,148,234$ (985,252)$ (74)$ -$ -$ -$ -$ 286,592,348$

April-14 696,590,025 - (985,252) - - - 695,604,773 280,270,750 1,576,101 (985,252)$ (67)$ -$ -$ -$ -$ 280,861,533$ 286,592,348$ 2,145,198$ (985,252)$ (67)$ -$ -$ -$ -$ 287,752,228$ May-14 695,604,773 - (985,252) - - - 694,619,521 280,861,533 1,573,871 (985,252)$ (60)$ -$ -$ -$ -$ 281,450,092$ 287,752,228$ 2,142,162$ (985,252)$ (60)$ -$ -$ -$ -$ 288,909,078$ June-14 694,619,521 - (985,252) - - - 693,634,269 281,450,092 1,571,640 (985,252)$ (54)$ -$ -$ -$ -$ 282,036,426$ 288,909,078$ 2,139,126$ (985,252)$ (54)$ -$ -$ -$ -$ 290,062,897$ July-14 693,634,269 - (985,252) - - - 692,649,018 282,036,426 1,569,409 (985,252)$ (49)$ -$ -$ -$ -$ 282,620,534$ 290,062,897$ 2,136,089$ (985,252)$ (49)$ -$ -$ -$ -$ 291,213,686$

August-14 692,649,018 - (985,252) - - - 691,663,766 282,620,534 1,567,178 (985,252)$ (44)$ -$ -$ -$ -$ 283,202,417$ 291,213,686$ 2,133,053$ (985,252)$ (44)$ -$ -$ -$ -$ 292,361,443$ September-14 691,663,766 - (985,252) - - - 690,678,514 283,202,417 1,564,947 (985,252)$ (39)$ -$ -$ -$ -$ 283,782,073$ 292,361,443$ 2,130,017$ (985,252)$ (39)$ -$ -$ -$ -$ 293,506,169$

October-14 690,678,514 - (985,252) - - - 689,693,262 283,782,073 1,562,717 (985,252)$ (35)$ -$ -$ -$ -$ 284,359,502$ 293,506,169$ 2,126,980$ (985,252)$ (35)$ -$ -$ -$ -$ 294,647,862$ November-14 689,693,262 - (985,252) - - - 688,708,010 284,359,502 1,560,486 (985,252)$ (32)$ -$ -$ -$ -$ 284,934,704$ 294,647,862$ 2,123,944$ (985,252)$ (32)$ -$ -$ -$ -$ 295,786,522$ December-14 688,708,010 - (985,252) - - - 687,722,758 284,934,704 1,558,255 (985,252)$ (29)$ -$ -$ -$ -$ 285,507,678$ 295,786,522$ 2,120,908$ (985,252)$ (29)$ -$ -$ -$ -$ 296,922,149$

Electric Distribution - Plant Leased to OthersJanuary-14 1,908,570 - - - - - 1,908,570 1,590,142 4,603 -$ -$ -$ -$ -$ -$ 1,594,746$ 1,581,072$ 3,469$ -$ -$ -$ -$ -$ -$ 1,584,541$

February-14 1,908,570 - - - - - 1,908,570 1,594,746 4,603 -$ -$ -$ -$ -$ -$ 1,599,349$ 1,584,541$ 3,469$ -$ -$ -$ -$ -$ -$ 1,588,011$ March-14 1,908,570 - - - - - 1,908,570 1,599,349 4,603 -$ -$ -$ -$ -$ -$ 1,603,952$ 1,588,011$ 3,469$ -$ -$ -$ -$ -$ -$ 1,591,480$

April-14 1,908,570 - - - - - 1,908,570 1,603,952 4,603 -$ -$ -$ -$ -$ -$ 1,608,555$ 1,591,480$ 3,469$ -$ -$ -$ -$ -$ -$ 1,594,949$ May-14 1,908,570 - - - - - 1,908,570 1,608,555 4,603 -$ -$ -$ -$ -$ -$ 1,613,158$ 1,594,949$ 3,469$ -$ -$ -$ -$ -$ -$ 1,598,419$ June-14 1,908,570 - - - - - 1,908,570 1,613,158 4,603 -$ -$ -$ -$ -$ -$ 1,617,761$ 1,598,419$ 3,469$ -$ -$ -$ -$ -$ -$ 1,601,888$ July-14 1,908,570 - - - - - 1,908,570 1,617,761 4,603 -$ -$ -$ -$ -$ -$ 1,622,364$ 1,601,888$ 3,469$ -$ -$ -$ -$ -$ -$ 1,605,357$

August-14 1,908,570 - - - - - 1,908,570 1,622,364 4,603 -$ -$ -$ -$ -$ -$ 1,626,967$ 1,605,357$ 3,469$ -$ -$ -$ -$ -$ -$ 1,608,827$ September-14 1,908,570 - - - - - 1,908,570 1,626,967 4,603 -$ -$ -$ -$ -$ -$ 1,631,570$ 1,608,827$ 3,469$ -$ -$ -$ -$ -$ -$ 1,612,296$

October-14 1,908,570 - - - - - 1,908,570 1,631,570 4,603 -$ -$ -$ -$ -$ -$ 1,636,174$ 1,612,296$ 3,469$ -$ -$ -$ -$ -$ -$ 1,615,765$ November-14 1,908,570 - - - - - 1,908,570 1,636,174 4,603 -$ -$ -$ -$ -$ -$ 1,640,777$ 1,615,765$ 3,469$ -$ -$ -$ -$ -$ -$ 1,619,234$ December-14 1,908,570 - - - - - 1,908,570 1,640,777 4,603 -$ -$ -$ -$ -$ -$ 1,645,380$ 1,619,234$ 3,469$ -$ -$ -$ -$ -$ -$ 1,622,704$

Electric Distribution - Street LightingJanuary-14 53,410,446 204,988 (40,561) - - - 53,574,874 43,892,423 213,971 (40,561)$ (38,582)$ 5,476$ -$ -$ -$ 44,032,727$ 43,841,379$ 207,516$ (40,561)$ (38,582)$ 5,476$ -$ -$ -$ 43,975,228$

February-14 53,574,874 176,642 (40,561) - - - 53,710,955 44,032,727 214,572 (40,561)$ (35,874)$ 3,832$ -$ -$ -$ 44,174,696$ 43,975,228$ 208,099$ (40,561)$ (35,874)$ 3,832$ -$ -$ -$ 44,110,725$ March-14 53,710,955 165,578 (40,561) - - - 53,835,972 44,174,696 215,094 (40,561)$ (34,540)$ 2,682$ -$ -$ -$ 44,317,372$ 44,110,725$ 208,605$ (40,561)$ (34,540)$ 2,682$ -$ -$ -$ 44,246,912$

April-14 53,835,972 157,910 (40,561) - - - 53,953,321 44,317,372 215,579 (40,561)$ (33,658)$ 1,878$ -$ -$ -$ 44,460,610$ 44,246,912$ 209,075$ (40,561)$ (33,658)$ 1,878$ -$ -$ -$ 44,383,646$ May-14 53,953,321 173,643 (40,561) - - - 54,086,403 44,460,610 216,079 (40,561)$ (34,074)$ 1,314$ -$ -$ -$ 44,603,368$ 44,383,646$ 209,561$ (40,561)$ (34,074)$ 1,314$ -$ -$ -$ 44,519,886$ June-14 54,086,403 197,460 (40,561) - - - 54,243,303 44,603,368 216,659 (40,561)$ (34,984)$ 920$ -$ -$ -$ 44,745,403$ 44,519,886$ 210,124$ (40,561)$ (34,984)$ 920$ -$ -$ -$ 44,655,385$ July-14 54,243,303 199,426 (40,561) - - - 54,402,169 44,745,403 217,291 (40,561)$ (32,597)$ 644$ -$ -$ -$ 44,890,180$ 44,655,385$ 210,736$ (40,561)$ (32,597)$ 644$ -$ -$ -$ 44,793,607$

August-14 54,402,169 217,819 (40,561) - - - 54,579,426 44,890,180 217,963 (40,561)$ (34,870)$ 451$ -$ -$ -$ 45,033,164$ 44,793,607$ 211,388$ (40,561)$ (34,870)$ 451$ -$ -$ -$ 44,930,016$ September-14 54,579,426 218,615 (40,561) - - - 54,757,481 45,033,164 218,674 (40,561)$ (37,649)$ 316$ -$ -$ -$ 45,173,944$ 44,930,016$ 212,077$ (40,561)$ (37,649)$ 316$ -$ -$ -$ 45,064,199$

October-14 54,757,481 203,741 (40,561) - - - 54,920,661 45,173,944 219,356 (40,561)$ (42,527)$ 221$ -$ -$ -$ 45,310,433$ 45,064,199$ 212,739$ (40,561)$ (42,527)$ 221$ -$ -$ -$ 45,194,071$ November-14 54,920,661 232,222 (40,561) - - - 55,112,322 45,310,433 220,066 (40,561)$ (52,801)$ 155$ -$ -$ -$ 45,437,292$ 45,194,071$ 213,427$ (40,561)$ (52,801)$ 155$ -$ -$ -$ 45,314,291$ December-14 55,112,322 245,428 (40,561) - - - 55,317,189 45,437,292 220,859 (40,561)$ (54,206)$ 108$ -$ -$ -$ 45,563,492$ 45,314,291$ 214,196$ (40,561)$ (54,206)$ 108$ -$ -$ -$ 45,433,829$

Electric Distribution - SubstationsJanuary-14 500,064,591 1,108,020 (324,167) - - - 500,848,444 200,564,686 1,206,943 (324,167)$ (52,911)$ 201$ -$ -$ -$ 201,394,752$ 198,255,866$ 909,496$ (324,167)$ (52,911)$ 201$ -$ -$ -$ 198,788,486$

February-14 500,848,444 1,271,434 (324,167) - - - 501,795,711 201,394,752 1,209,030 (324,167)$ (43,784)$ 180$ -$ -$ -$ 202,236,011$ 198,788,486$ 911,069$ (324,167)$ (43,784)$ 180$ -$ -$ -$ 199,331,784$ March-14 501,795,711 1,428,782 (324,167) - - - 502,900,327 202,236,011 1,211,504 (324,167)$ (91,152)$ 945$ -$ -$ -$ 203,033,142$ 199,331,784$ 912,934$ (324,167)$ (91,152)$ 945$ -$ -$ -$ 199,830,345$

April-14 502,900,327 1,500,728 (324,167) - - - 504,076,888 203,033,142 1,214,255 (324,167)$ (42,843)$ 66$ -$ -$ -$ 203,880,453$ 199,830,345$ 915,007$ (324,167)$ (42,843)$ 66$ -$ -$ -$ 200,378,407$ May-14 504,076,888 23,748,704 (324,167) - - - 527,501,425 203,880,453 1,243,920 (324,167)$ (41,335)$ 58$ -$ -$ -$ 204,758,930$ 200,378,407$ 937,361$ (324,167)$ (41,335)$ 58$ -$ -$ -$ 200,950,325$ June-14 527,501,425 2,480,145 (324,167) - - - 529,657,403 204,758,930 1,274,766 (324,167)$ (42,986)$ 52$ -$ -$ -$ 205,666,596$ 200,950,325$ 960,605$ (324,167)$ (42,986)$ 52$ -$ -$ -$ 201,543,830$ July-14 529,657,403 766,339 (324,167) - - - 530,099,575 205,666,596 1,277,899 (324,167)$ (41,323)$ 47$ -$ -$ -$ 206,579,051$ 201,543,830$ 962,966$ (324,167)$ (41,323)$ 47$ -$ -$ -$ 202,141,352$

August-14 530,099,575 882,867 (324,167) - - - 530,658,275 206,579,051 1,279,106 (324,167)$ (292,153)$ 42$ -$ -$ -$ 207,241,879$ 202,141,352$ 963,875$ (324,167)$ (292,153)$ 42$ -$ -$ -$ 202,488,949$ September-14 530,658,275 820,709 (324,167) - - - 531,154,818 207,241,879 1,280,378 (324,167)$ (61,106)$ 37$ -$ -$ -$ 208,137,022$ 202,488,949$ 964,834$ (324,167)$ (61,106)$ 37$ -$ -$ -$ 203,068,547$

October-14 531,154,818 860,892 (324,167) - - - 531,691,543 208,137,022 1,281,624 (324,167)$ (41,545)$ 33$ -$ -$ -$ 209,052,968$ 203,068,547$ 965,773$ (324,167)$ (41,545)$ 33$ -$ -$ -$ 203,668,642$ November-14 531,691,543 798,988 (324,167) - - - 532,166,365 209,052,968 1,282,844 (324,167)$ (39,658)$ 30$ -$ -$ -$ 209,972,017$ 203,668,642$ 966,692$ (324,167)$ (39,658)$ 30$ -$ -$ -$ 204,271,539$ December-14 532,166,365 936,155 (324,167) - - - 532,778,353 209,972,017 1,284,155 (324,167)$ (40,039)$ 27$ -$ -$ -$ 210,891,993$ 204,271,539$ 967,680$ (324,167)$ (40,039)$ 27$ -$ -$ -$ 204,875,040$

Electric Distribution - Substations-ProdJanuary-14 3,530,619 - - - - - 3,530,619 1,843,451 8,512 -$ -$ -$ -$ -$ -$ 1,851,963$ 1,826,627$ 6,409$ -$ -$ -$ -$ -$ -$ 1,833,036$

February-14 3,530,619 - - - - - 3,530,619 1,851,963 8,512 -$ -$ -$ -$ -$ -$ 1,860,474$ 1,833,036$ 6,409$ -$ -$ -$ -$ -$ -$ 1,839,444$ March-14 3,530,619 - - - - - 3,530,619 1,860,474 8,512 -$ -$ -$ -$ -$ -$ 1,868,986$ 1,839,444$ 6,409$ -$ -$ -$ -$ -$ -$ 1,845,853$

April-14 3,530,619 - - - - - 3,530,619 1,868,986 8,512 -$ -$ -$ -$ -$ -$ 1,877,498$ 1,845,853$ 6,409$ -$ -$ -$ -$ -$ -$ 1,852,262$ May-14 3,530,619 - - - - - 3,530,619 1,877,498 8,512 -$ -$ -$ -$ -$ -$ 1,886,009$ 1,852,262$ 6,409$ -$ -$ -$ -$ -$ -$ 1,858,670$ June-14 3,530,619 - - - - - 3,530,619 1,886,009 8,512 -$ -$ -$ -$ -$ -$ 1,894,521$ 1,858,670$ 6,409$ -$ -$ -$ -$ -$ -$ 1,865,079$ July-14 3,530,619 - - - - - 3,530,619 1,894,521 8,512 -$ -$ -$ -$ -$ -$ 1,903,033$ 1,865,079$ 6,409$ -$ -$ -$ -$ -$ -$ 1,871,488$

August-14 3,530,619 - - - - - 3,530,619 1,903,033 8,512 -$ -$ -$ -$ -$ -$ 1,911,544$ 1,871,488$ 6,409$ -$ -$ -$ -$ -$ -$ 1,877,896$ September-14 3,530,619 - - - - - 3,530,619 1,911,544 8,512 -$ -$ -$ -$ -$ -$ 1,920,056$ 1,877,896$ 6,409$ -$ -$ -$ -$ -$ -$ 1,884,305$

October-14 3,530,619 - - - - - 3,530,619 1,920,056 8,512 -$ -$ -$ -$ -$ -$ 1,928,568$ 1,884,305$ 6,409$ -$ -$ -$ -$ -$ -$ 1,890,714$ November-14 3,530,619 - - - - - 3,530,619 1,928,568 8,512 -$ -$ -$ -$ -$ -$ 1,937,079$ 1,890,714$ 6,409$ -$ -$ -$ -$ -$ -$ 1,897,122$ December-14 3,530,619 - - - - - 3,530,619 1,937,079 8,512 -$ -$ -$ -$ -$ -$ 1,945,591$ 1,897,122$ 6,409$ -$ -$ -$ -$ -$ -$ 1,903,531$



Page 7 of 7




Transfers In


Beginning Balance



Reserve Transfer In


Beginning Balance

Depreciation Expense

Retirement

Cost of Removal

Salvage Cash

Reserve Transfer In



Electric General - BuildingsJanuary-14 60,205,559$ 1,389$ -$ -$ -$ -$ 60,206,947$ 26,589,301$ 111,502$ -$ -$ -$ -$ -$ -$ 26,700,803$ 26,542,313$ 105,627$ -$ -$ -$ -$ -$ -$ 26,647,939$

February-14 60,206,947$ 1,085$ -$ -$ -$ -$ 60,208,033$ 26,700,803$ 111,504$ -$ -$ -$ -$ -$ -$ 26,812,307$ 26,647,939$ 105,629$ -$ -$ -$ -$ -$ -$ 26,753,568$ March-14 60,208,033$ 848$ -$ -$ -$ -$ 60,208,881$ 26,812,307$ 111,506$ -$ -$ -$ -$ -$ -$ 26,923,814$ 26,753,568$ 105,631$ -$ -$ -$ -$ -$ -$ 26,859,199$

April-14 60,208,881$ 663$ -$ -$ -$ -$ 60,209,544$ 26,923,814$ 111,507$ -$ -$ -$ -$ -$ -$ 27,035,321$ 26,859,199$ 105,632$ -$ -$ -$ -$ -$ -$ 26,964,831$ May-14 60,209,544$ 518$ -$ -$ -$ -$ 60,210,062$ 27,035,321$ 111,509$ -$ -$ -$ -$ -$ -$ 27,146,830$ 26,964,831$ 105,633$ -$ -$ -$ -$ -$ -$ 27,070,464$ June-14 60,210,062$ 405$ -$ -$ -$ -$ 60,210,468$ 27,146,830$ 111,509$ -$ -$ -$ -$ -$ -$ 27,258,339$ 27,070,464$ 105,634$ -$ -$ -$ -$ -$ -$ 27,176,098$ July-14 60,210,468$ 317$ -$ -$ -$ -$ 60,210,784$ 27,258,339$ 111,510$ -$ -$ -$ -$ -$ -$ 27,369,849$ 27,176,098$ 105,635$ -$ -$ -$ -$ -$ -$ 27,281,733$

August-14 60,210,784$ 248$ -$ -$ -$ -$ 60,211,032$ 27,369,849$ 111,511$ -$ -$ -$ -$ -$ -$ 27,481,360$ 27,281,733$ 105,635$ -$ -$ -$ -$ -$ -$ 27,387,368$ September-14 60,211,032$ 194$ -$ -$ -$ -$ 60,211,225$ 27,481,360$ 111,511$ -$ -$ -$ -$ -$ -$ 27,592,871$ 27,387,368$ 105,635$ -$ -$ -$ -$ -$ -$ 27,493,003$

October-14 60,211,225$ 151$ -$ -$ -$ -$ 60,211,377$ 27,592,871$ 111,511$ -$ -$ -$ -$ -$ -$ 27,704,382$ 27,493,003$ 105,636$ -$ -$ -$ -$ -$ -$ 27,598,639$ November-14 60,211,377$ 118$ -$ -$ -$ -$ 60,211,495$ 27,704,382$ 111,512$ -$ -$ -$ -$ -$ -$ 27,815,894$ 27,598,639$ 105,636$ -$ -$ -$ -$ -$ -$ 27,704,275$ December-14 60,211,495$ 92$ -$ -$ -$ -$ 60,211,587$ 27,815,894$ 111,512$ -$ -$ -$ -$ -$ -$ 27,927,405$ 27,704,275$ 105,636$ -$ -$ -$ -$ -$ -$ 27,809,911$

Electric General - Furniture and EquipmentJanuary-14 24,879,971$ 12,126$ -$ -$ -$ -$ 24,892,097$ 13,290,872$ 115,242$ -$ (30)$ -$ -$ -$ -$ 13,406,085$ 13,199,679$ 103,717$ -$ (30)$ -$ -$ -$ -$ 13,303,367$

February-14 24,892,097$ 6,448$ -$ -$ -$ -$ 24,898,545$ 13,406,085$ 115,272$ -$ (23)$ -$ -$ -$ -$ 13,521,333$ 13,303,367$ 103,744$ -$ (23)$ -$ -$ -$ -$ 13,407,088$ March-14 24,898,545$ 3,523$ -$ -$ -$ -$ 24,902,068$ 13,521,333$ 115,288$ -$ (18)$ -$ -$ -$ -$ 13,636,604$ 13,407,088$ 103,759$ -$ (18)$ -$ -$ -$ -$ 13,510,828$

April-14 24,902,068$ 1,994$ -$ -$ -$ -$ 24,904,062$ 13,636,604$ 115,298$ -$ (14)$ -$ -$ -$ -$ 13,751,887$ 13,510,828$ 103,767$ -$ (14)$ -$ -$ -$ -$ 13,614,581$ May-14 24,904,062$ 1,178$ -$ -$ -$ -$ 24,905,240$ 13,751,887$ 115,303$ -$ (11)$ -$ -$ -$ -$ 13,867,180$ 13,614,581$ 103,772$ -$ (11)$ -$ -$ -$ -$ 13,718,342$ June-14 24,905,240$ 45,730$ -$ -$ -$ -$ 24,950,970$ 13,867,180$ 115,515$ -$ (8)$ -$ -$ -$ -$ 13,982,686$ 13,718,342$ 103,962$ -$ (8)$ -$ -$ -$ -$ 13,822,296$ July-14 24,950,970$ 67,974$ -$ -$ -$ -$ 25,018,944$ 13,982,686$ 115,829$ -$ (7)$ -$ -$ -$ -$ 14,098,509$ 13,822,296$ 104,246$ -$ (7)$ -$ -$ -$ -$ 13,926,536$

August-14 25,018,944$ 79,072$ -$ -$ -$ -$ 25,098,016$ 14,098,509$ 116,196$ -$ (5)$ -$ -$ -$ -$ 14,214,699$ 13,926,536$ 104,575$ -$ (5)$ -$ -$ -$ -$ 14,031,106$ September-14 25,098,016$ 84,602$ -$ -$ -$ -$ 25,182,618$ 14,214,699$ 116,587$ -$ (4)$ -$ -$ -$ -$ 14,331,282$ 14,031,106$ 104,928$ -$ (4)$ -$ -$ -$ -$ 14,136,029$

October-14 25,182,618$ 52,353$ -$ -$ -$ -$ 25,234,971$ 14,331,282$ 116,830$ -$ (3)$ -$ -$ -$ -$ 14,448,109$ 14,136,029$ 105,146$ -$ (3)$ -$ -$ -$ -$ 14,241,172$ November-14 25,234,971$ 26,216$ -$ -$ -$ -$ 25,261,188$ 14,448,109$ 116,831$ -$ (2)$ -$ -$ -$ -$ 14,564,938$ 14,241,172$ 105,255$ -$ (2)$ -$ -$ -$ -$ 14,346,425$ December-14 25,261,188$ 113,139$ -$ -$ -$ -$ 25,374,327$ 14,564,938$ 117,111$ -$ (2)$ -$ -$ -$ -$ 14,682,048$ 14,346,425$ 105,726$ -$ (2)$ -$ -$ -$ -$ 14,452,149$

Electric General - Transporation EquipmentJanuary-14 125,603,626$ 522,564$ -$ -$ -$ -$ 126,126,190$ 39,480,203$ 894,837$ -$ (17,024)$ -$ -$ -$ -$ 40,358,016$ 38,779,542$ 802,690$ -$ (17,024)$ -$ -$ -$ -$ 39,565,208$

February-14 126,126,190$ 465,549$ -$ -$ -$ -$ 126,591,739$ 40,358,016$ 898,153$ -$ (14,468)$ -$ -$ -$ -$ 41,241,701$ 39,565,208$ 805,665$ -$ (14,468)$ -$ -$ -$ -$ 40,356,405$ March-14 126,591,739$ 452,277$ -$ -$ -$ -$ 127,044,016$ 41,241,701$ 901,080$ -$ (12,323)$ -$ -$ -$ -$ 42,130,457$ 40,356,405$ 808,556$ -$ (12,323)$ -$ -$ -$ -$ 41,152,638$

April-14 127,044,016$ 441,965$ -$ -$ -$ -$ 127,485,981$ 42,130,457$ 903,557$ -$ (10,523)$ -$ -$ -$ -$ 43,023,491$ 41,152,638$ 811,214$ -$ (10,523)$ -$ -$ -$ -$ 41,953,328$ May-14 127,485,981$ 471,512$ -$ -$ -$ -$ 127,957,493$ 43,023,491$ 906,626$ -$ (9,165)$ -$ -$ -$ -$ 43,920,952$ 41,953,328$ 813,721$ -$ (9,165)$ -$ -$ -$ -$ 42,757,884$ June-14 127,957,493$ 498,793$ -$ -$ -$ -$ 128,456,286$ 43,920,952$ 910,180$ -$ (8,334)$ -$ -$ -$ -$ 44,822,798$ 42,757,884$ 816,453$ -$ (8,334)$ -$ -$ -$ -$ 43,566,004$ July-14 128,456,286$ 459,915$ -$ -$ -$ -$ 128,916,201$ 44,822,798$ 913,456$ -$ (7,329)$ -$ -$ -$ -$ 45,728,925$ 43,566,004$ 819,392$ -$ (7,329)$ -$ -$ -$ -$ 44,378,067$

August-14 128,916,201$ 449,911$ -$ -$ -$ -$ 129,366,112$ 45,728,925$ 916,578$ -$ (6,486)$ -$ -$ -$ -$ 46,639,017$ 44,378,067$ 822,267$ -$ (6,486)$ -$ -$ -$ -$ 45,193,848$ September-14 129,366,112$ 420,602$ -$ -$ -$ -$ 129,786,714$ 46,639,017$ 919,437$ -$ (5,623)$ -$ -$ -$ -$ 47,552,831$ 45,193,848$ 824,955$ -$ (5,623)$ -$ -$ -$ -$ 46,013,181$

October-14 129,786,714$ 352,820$ -$ -$ -$ -$ 130,139,534$ 47,552,831$ 921,950$ -$ (4,896)$ -$ -$ -$ -$ 48,469,885$ 46,013,181$ 827,094$ -$ (4,896)$ -$ -$ -$ -$ 46,835,379$ November-14 130,139,534$ 339,460$ -$ -$ -$ -$ 130,478,994$ 48,469,885$ 924,368$ -$ (4,439)$ -$ -$ -$ -$ 49,389,815$ 46,835,379$ 829,181$ -$ (4,439)$ -$ -$ -$ -$ 47,660,121$ December-14 130,478,994$ 833,263$ -$ -$ -$ -$ 131,312,257$ 49,389,815$ 930,304$ -$ (4,054)$ -$ -$ -$ -$ 50,316,066$ 47,660,121$ 834,506$ -$ (4,054)$ -$ -$ -$ -$ 48,490,573$



Summary of Excess Funding by Year Page 1 of 1

Received 2013 for 2014 DCM

Received 2014 for 2015 DCM

DOE Refund - MN Retail 31,810,998$ 32,404,749$

Decommissioning Accrual 14,189,132$ 14,189,132$

Excess Funding 17,621,866$ 18,215,617$

Total Excess Funding 35,837,483$

Northern States Power CompanyElectric Utility - State of MinnesotaNuclear Theoretical Reserve AnalysisReserve Comparison


Page 1 of 14

Account Plant Total Reserve TheoreticalNumber Description Unit Balance Balance Reserve Difference

321 Structures & Improvements Prairie Island 244,439,079$ 182,883,776$ 143,758,872$ 39,124,904$ 322 Nuclear Reactor Equipment Prairie Island 612,422,382 385,295,647 343,264,239 42,031,408 323 Turbogenerator Equipment Prairie Island 183,243,814 131,152,634 97,590,962 33,561,672 324 Accessory Electrical Equipment Prairie Island 202,259,192 159,668,358 103,739,123 55,929,234 325 Miscellaneous Equipoment Prairie Island 82,163,980 59,790,855 56,798,567 2,992,288

Total 1,324,528,446$ 918,791,270$ 745,151,764$ 173,639,506$

321 Structures & Improvements Monticello 187,861,790$ 103,810,195$ 102,455,105$ 1,355,090$ 322 Nuclear Reactor Equipment Monticello 392,065,711 235,089,265 242,411,385 (7,322,121) 323 Turbogenerator Equipment Monticello 261,385,409 29,346,850 90,018,412 (60,671,562) 324 Accessory Electrical Equipment Monticello 82,612,412 28,816,514 43,600,229 (14,783,715) 325 Miscellaneous Equipoment Monticello 60,713,782 42,033,609 36,780,521 5,253,089

Total 984,639,104 439,096,433 515,265,652 (76,169,218)

Total - All Units 2,309,167,550$ 1,357,887,703$ 1,260,417,415$ 97,470,288$

As of 12/31/2012



Page 2 of 14

All UnitsTotal

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12]INTERIM INTERIM TERMINAL TERMINAL INTERIM ENDING AVERAGE DEPREC. ENDING 2013 CHANGE OVER

YEAR RETMTS NET SALV. RETMTS. NET SALV. ADDITIONS BALANCE BALANCE AMOUNT RESERVE EXPENSE 2013 EXPENSE

2012 2,309,167,550$ 1,357,887,703$ 2013 44,818,294$ (16,491,442)$ -$ -$ 224,091,472$ 2,488,440,728 2,398,804,139$ 117,390,545$ 1,413,968,511 117,390,545$ -$ 2014 15,649,041 (4,739,247) - - 78,245,207 2,551,036,894 2,519,738,811 124,683,206 1,518,263,429 117,390,545 7,292,661 2015 68,391,391 (25,745,565) - - 341,956,954 2,824,602,457 2,687,819,675 134,455,847 1,558,582,320 117,390,545 17,065,302 2016 69,408,502 (26,055,203) - - 347,042,511 3,102,236,466 2,963,419,462 149,457,293 1,612,575,907 117,390,545 32,066,748 2017 19,307,728 (5,910,608) - - 96,538,639 3,179,467,378 3,140,851,922 159,592,202 1,746,949,773 117,390,545 42,201,657 2018 20,220,275 (6,163,733) - - 101,101,373 3,260,348,476 3,219,907,927 165,171,183 1,885,736,949 117,390,545 47,780,638 2019 21,189,352 (6,431,291) - - 105,946,759 3,345,105,884 3,302,727,180 171,064,724 2,029,181,029 117,390,545 53,674,179 2020 22,218,833 (6,714,221) - - 111,094,167 3,433,981,217 3,389,543,551 177,293,683 2,177,541,658 117,390,545 59,903,138 2021 23,312,868 (7,013,522) - - 116,564,341 3,527,232,690 3,480,606,954 183,880,379 2,331,095,647 117,390,545 66,489,834 2022 24,475,900 (7,330,263) - - 122,379,500 3,625,136,290 3,576,184,490 190,848,696 2,490,138,180 117,390,545 73,458,151 2023 25,712,689 (7,665,588) - - 128,563,447 3,727,987,048 3,676,561,669 198,224,195 2,654,984,097 117,390,545 80,833,650 2024 27,028,335 (8,020,715) - - 135,141,677 3,836,100,390 3,782,043,719 206,034,233 2,825,969,280 117,390,545 88,643,688 2025 28,428,301 (8,396,949) - - 142,141,504 3,949,813,594 3,892,956,992 214,308,092 3,003,452,122 117,390,545 96,917,547 2026 29,918,438 (8,795,685) - - 149,592,190 4,069,487,346 4,009,650,470 223,077,119 3,187,815,118 117,390,545 105,686,574 2027 31,505,017 (9,218,410) - - 157,525,085 4,195,507,414 4,132,497,380 232,374,870 3,379,466,562 117,390,545 114,984,325 2028 11,441,327 (2,696,387) - - 57,206,634 4,241,272,721 4,218,390,067 238,531,474 3,603,860,322 117,390,545 121,140,929 2029 11,927,162 (2,757,631) - - 59,635,811 4,288,981,370 4,265,127,045 241,343,908 3,830,519,436 117,390,545 123,953,363 2030 12,443,563 (2,820,935) 1,838,887,510 - 62,217,815 2,499,868,112 3,394,424,741 178,940,467 2,155,307,895 86,378,947 92,561,519 2031 12,992,745 (2,886,404) - - 64,963,723 2,551,839,091 2,525,853,602 116,691,641 2,256,120,388 55,367,350 61,324,292 2032 - - - - - 2,551,839,091 2,551,839,091 118,287,481 2,374,407,869 55,367,350 62,920,132 2033 - - - - - 2,551,839,091 2,551,839,091 118,287,481 2,492,695,351 55,367,350 62,920,132 2034 - - 2,551,839,091 - - - 1,275,919,546 59,143,741 0 27,683,675 31,460,066

TOTALS 520,389,763$ (165,853,799)$ 4,390,726,601$ -$ 2,601,948,813$ 70,956,707,524$ 1,443,278,524$



Page 3 of 14

Prairie IslandTotal



2012 1,324,528,446$ 918,791,270$ 2013 35,373,852$ (13,435,462)$ -$ -$ 176,869,259$ 1,466,023,853 1,395,276,149$ 55,367,350$ 925,349,306 55,367,350$ -$ 2014 5,693,776 (1,519,116) - - 28,468,881 1,488,798,958 1,477,411,405 59,612,487 977,748,901 55,367,350 4,245,137 2015 57,892,901 (22,351,096) - - 289,464,503 1,720,370,560 1,604,584,759 66,150,755 963,655,660 55,367,350 10,783,405 2016 58,332,188 (22,475,531) - - 291,660,939 1,953,699,311 1,837,034,936 77,718,482 960,566,422 55,367,350 22,351,132 2017 7,616,641 (2,134,145) - - 38,083,207 1,984,165,877 1,968,932,594 84,206,964 1,035,022,600 55,367,350 28,839,614 2018 7,874,956 (2,178,118) - - 39,374,778 2,015,665,699 1,999,915,788 85,912,522 1,110,882,049 55,367,350 30,545,173 2019 8,147,652 (2,223,336) - - 40,738,259 2,048,256,306 2,031,961,003 87,690,369 1,188,201,431 55,367,350 32,323,019 2020 8,435,729 (2,269,853) - - 42,178,644 2,081,999,222 2,065,127,764 89,545,024 1,267,040,873 55,367,350 34,177,675 2021 8,740,260 (2,317,727) - - 43,701,299 2,116,960,261 2,099,479,741 91,481,337 1,347,464,224 55,367,350 36,113,988 2022 9,062,398 (2,367,017) - - 45,311,991 2,153,209,854 2,135,085,057 93,504,508 1,429,539,316 55,367,350 38,137,158 2023 9,403,384 (2,417,787) - - 47,016,918 2,190,823,388 2,172,016,621 95,620,113 1,513,338,259 55,367,350 40,252,763 2024 9,764,549 (2,470,106) - - 48,822,744 2,229,881,583 2,210,352,486 97,834,139 1,598,937,742 55,367,350 42,466,789 2025 10,147,326 (2,524,046) - - 50,736,632 2,270,470,889 2,250,176,236 100,153,007 1,686,419,377 55,367,350 44,785,658 2026 10,553,257 (2,579,684) - - 52,766,285 2,312,683,917 2,291,577,403 102,583,612 1,775,870,047 55,367,350 47,216,262 2027 10,983,997 (2,637,102) - - 54,919,984 2,356,619,904 2,334,651,911 105,133,352 1,867,382,301 55,367,350 49,766,003 2028 11,441,327 (2,696,387) - - 57,206,634 2,402,385,211 2,379,502,558 107,810,174 1,961,054,762 55,367,350 52,442,825 2029 11,927,162 (2,757,631) - - 59,635,811 2,450,093,860 2,426,239,536 110,622,608 2,056,992,576 55,367,350 55,255,259 2030 12,443,563 (2,820,935) - - 62,217,815 2,499,868,112 2,474,980,986 113,579,817 2,155,307,895 55,367,350 58,212,467 2031 12,992,745 (2,886,404) - - 64,963,723 2,551,839,091 2,525,853,602 116,691,641 2,256,120,388 55,367,350 61,324,292 2032 - - - - - 2,551,839,091 2,551,839,091 118,287,481 2,374,407,869 55,367,350 62,920,132 2033 - - - - - 2,551,839,091 2,551,839,091 118,287,481 2,492,695,351 55,367,350 62,920,132 2034 - - 2,551,839,091 - - - 1,275,919,546 59,143,741 0 27,683,675 31,460,066

TOTALS 306,827,661$ (97,061,483)$ 2,551,839,091$ -$ 1,534,138,306$ 46,059,758,262$ 846,538,948$



Page 4 of 14

MonticelloTotal



2012 984,639,104$ 439,096,433$ 2013 9,444,443$ (3,055,981)$ -$ -$ 47,222,214$ 1,022,416,876 1,003,527,990$ 62,023,195$ 488,619,205 62,023,195$ -$ 2014 9,955,265 (3,220,131) - - 49,776,326 1,062,237,936 1,042,327,406 65,070,719 540,514,528 62,023,195 3,047,524 2015 10,498,490 (3,394,469) - - 52,492,451 1,104,231,897 1,083,234,917 68,305,092 594,926,660 62,023,195 6,281,897 2016 11,076,314 (3,579,672) - - 55,381,572 1,148,537,155 1,126,384,526 71,738,811 652,009,485 62,023,195 9,715,615 2017 11,691,086 (3,776,463) - - 58,455,432 1,195,301,501 1,171,919,328 75,385,238 711,927,173 62,023,195 13,362,043 2018 12,345,319 (3,985,615) - - 61,726,596 1,244,682,777 1,219,992,139 79,258,660 774,854,899 62,023,195 17,235,465 2019 13,041,700 (4,207,956) - - 65,208,500 1,296,849,577 1,270,766,177 83,374,355 840,979,599 62,023,195 21,351,160 2020 13,783,105 (4,444,368) - - 68,915,523 1,351,981,996 1,324,415,787 87,748,659 910,500,785 62,023,195 25,725,463 2021 14,572,608 (4,695,795) - - 72,863,042 1,410,272,429 1,381,127,212 92,399,042 983,631,423 62,023,195 30,375,847 2022 15,413,502 (4,963,247) - - 77,067,510 1,471,926,437 1,441,099,433 97,344,189 1,060,598,863 62,023,195 35,320,993 2023 16,309,306 (5,247,800) - - 81,546,529 1,537,163,660 1,504,545,048 102,604,082 1,141,645,839 62,023,195 40,580,887 2024 17,263,787 (5,550,608) - - 86,318,934 1,606,218,807 1,571,691,234 108,200,094 1,227,031,537 62,023,195 46,176,899 2025 18,280,974 (5,872,903) - - 91,404,872 1,679,342,705 1,642,780,756 114,155,085 1,317,032,745 62,023,195 52,131,890 2026 19,365,181 (6,216,000) - - 96,825,905 1,756,803,429 1,718,073,067 120,493,507 1,411,945,071 62,023,195 58,470,312 2027 20,521,020 (6,581,308) - - 102,605,101 1,838,887,510 1,797,845,469 127,241,518 1,512,084,261 62,023,195 65,218,322 2028 - - - - - 1,838,887,510 1,838,887,510 130,721,300 1,642,805,560 62,023,195 68,698,104 2029 - - - - - 1,838,887,510 1,838,887,510 130,721,300 1,773,526,860 62,023,195 68,698,104 2030 - - 1,838,887,510 - - - 919,443,755 65,360,650 0 31,011,598 34,349,052

TOTALS 213,562,101$ (68,792,316)$ 1,838,887,510$ -$ 1,067,810,506$ 24,896,949,261$ 596,739,576$



Page 5 of 14

Prairie IslandAccount 321 - Structures and Improvements

Interim Net Salvage -15.0%Terminal Net Salvage 0.0%Average Net Salvage -0.2%Average Age Survivors 29.35 Average Remaining Life 20.66 Average Service Life 50.02 Book Reserve Ratio 74.8%Theoretical Reserve 143,758,872$ Interim Retmt. Ratio 0.08%Interim Addition Factor - Depreciation Rate 1.4822%COR Rate 0.0042%

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10]INTERIM INTERIM TERMINAL TERMINAL INTERIM ENDING AVERAGE DEPREC. ENDING

YEAR RETMTS NET SALV. RETMTS. NET SALV. ADDITIONS BALANCE BALANCE AMOUNT RESERVE

2012 244,439,079$ 182,883,776$ 2013 188,218$ (28,233)$ 941,090$ 245,191,952 244,815,516$ 3,628,652$ 186,295,977 2014 188,798 (28,320) 943,989 245,947,143 245,569,547 3,639,828 189,718,688 2015 189,379 (28,407) 946,897 246,704,660 246,325,902 3,651,039 193,151,941 2016 189,963 (28,494) 949,813 247,464,510 247,084,585 3,662,284 196,595,768 2017 190,548 (28,582) 952,738 248,226,701 247,845,606 3,673,564 200,050,202 2018 191,135 (28,670) 955,673 248,991,239 248,608,970 3,684,879 203,515,276 2019 191,723 (28,758) 958,616 249,758,132 249,374,686 3,696,228 206,991,023 2020 192,314 (28,847) 961,569 250,527,387 250,142,760 3,707,612 210,477,474 2021 192,906 (28,936) 964,530 251,299,012 250,913,200 3,719,032 213,974,664 2022 193,500 (29,025) 967,501 252,073,013 251,686,012 3,730,486 217,482,625 2023 194,096 (29,114) 970,481 252,849,398 252,461,205 3,741,976 221,001,391 2024 194,694 (29,204) 973,470 253,628,174 253,238,786 3,753,502 224,530,994 2025 195,294 (29,294) 976,468 254,409,349 254,018,761 3,765,062 228,071,469 2026 195,895 (29,384) 979,476 255,192,929 254,801,139 3,776,659 231,622,848 2027 196,499 (29,475) 982,493 255,978,924 255,585,927 3,788,291 235,185,166 2028 197,104 (29,566) 985,519 256,767,339 256,373,131 3,799,959 238,758,456 2029 197,711 (29,657) 988,554 257,558,182 257,162,760 3,811,663 242,342,751 2030 198,320 (29,748) 991,599 258,351,461 257,954,822 3,823,403 245,938,086 2031 198,931 (29,840) 994,653 259,147,184 258,749,323 3,835,179 249,544,494 2032 - - 259,147,184 259,147,184 3,841,076 253,385,570 2033 - - 259,147,184 259,147,184 3,841,076 257,226,646 2034 - 259,147,184 - - - 129,573,592 1,920,538 -

TOTALS 3,677,026$ (551,554)$ 259,147,184$ -$ 18,385,131$ 5,430,580,597$



Page 6 of 14

Prairie IslandAccount 322 - Reactor Plant Equipment




2012 612,422,382$ 385,295,647$ 2013 3,123,354$ (1,249,342)$ 15,616,771$ 624,915,798 618,669,090$ 29,446,000$ 410,368,951 2014 3,187,071 (1,274,828) 15,935,353 637,664,081 631,289,940 30,046,699 435,953,751 2015 3,252,087 (1,300,835) 16,260,434 650,672,428 644,168,254 30,659,651 462,060,481 2016 55,318,429 (22,127,372) 276,592,147 871,946,146 761,309,287 36,235,063 420,849,742 2017 4,446,925 (1,778,770) 22,234,627 889,733,847 880,839,996 41,924,213 456,548,260 2018 4,537,643 (1,815,057) 22,688,213 907,884,417 898,809,132 42,779,467 492,975,027 2019 4,630,211 (1,852,084) 23,151,053 926,405,260 917,144,838 43,652,168 530,144,900 2020 4,724,667 (1,889,867) 23,623,334 945,303,927 935,854,593 44,542,672 568,073,039 2021 4,821,050 (1,928,420) 24,105,250 964,588,127 954,946,027 45,451,343 606,774,912 2022 4,919,399 (1,967,760) 24,596,997 984,265,725 974,426,926 46,378,550 646,266,303 2023 5,019,755 (2,007,902) 25,098,776 1,004,344,745 994,305,235 47,324,673 686,563,318 2024 5,122,158 (2,048,863) 25,610,791 1,024,833,378 1,014,589,062 48,290,096 727,682,392 2025 5,226,650 (2,090,660) - 26,133,251 1,045,739,979 1,035,286,679 49,275,214 769,640,296 2026 5,333,274 (2,133,310) 26,666,369 1,067,073,075 1,056,406,527 50,280,428 812,454,141 2027 5,442,073 (2,176,829) 27,210,363 1,088,841,366 1,077,957,220 51,306,149 856,141,388 2028 5,553,091 (2,221,236) 27,765,455 1,111,053,729 1,099,947,547 52,352,794 900,719,855 2029 5,666,374 (2,266,550) 28,331,870 1,133,719,225 1,122,386,477 53,420,791 946,207,722 2030 5,781,968 (2,312,787) 28,909,840 1,156,847,098 1,145,283,162 54,510,576 992,623,543 2031 5,899,920 (2,359,968) 29,499,601 1,180,446,778 1,168,646,938 55,622,591 1,039,986,246 2032 - - 1,180,446,778 1,180,446,778 56,184,213 1,096,170,459 2033 - - 1,180,446,778 1,180,446,778 56,184,213 1,152,354,672 2034 - 1,180,446,778 - - - 590,223,389 28,092,107 0

TOTALS 142,006,099$ (56,802,440)$ 1,180,446,778$ -$ 710,030,496$ 20,883,383,877$



Page 7 of 14

Prairie IslandAccount 323 - Turbogenerator Equipment




2012 183,243,814$ 131,152,634$ 2013 30,201,568$ (12,080,627)$ 151,007,841$ 304,050,086 243,646,950$ 12,330,926$ 101,201,365 2014 334,455 (133,782) 1,672,275 305,387,907 304,718,996 15,421,771 116,154,898 2015 52,335,927 (20,934,371) 261,679,633 514,731,613 410,059,760 20,753,047 63,637,648 2016 566,205 (226,482) 2,831,024 516,996,433 515,864,023 26,107,781 88,952,742 2017 568,696 (227,478) 2,843,480 519,271,217 518,133,825 26,222,655 114,379,222 2018 571,198 (228,479) 2,855,992 521,556,010 520,413,614 26,338,035 139,917,579 2019 573,712 (229,485) 2,868,558 523,850,857 522,703,433 26,453,922 165,568,305 2020 576,236 (230,494) 2,881,180 526,155,800 525,003,329 26,570,319 191,331,893 2021 578,771 (231,509) 2,893,857 528,470,886 527,313,343 26,687,229 217,208,842 2022 581,318 (232,527) 2,906,590 530,796,158 529,633,522 26,804,652 243,199,649 2023 583,876 (233,550) 2,919,379 533,131,661 531,963,909 26,922,593 269,304,816 2024 586,445 (234,578) 2,932,224 535,477,440 534,304,551 27,041,052 295,524,846 2025 589,025 (235,610) 2,945,126 537,833,541 536,655,491 27,160,033 321,860,243 2026 591,617 (236,647) 2,958,084 540,200,009 539,016,775 27,279,537 348,311,517 2027 594,220 (237,688) 2,971,100 542,576,889 541,388,449 27,399,567 374,879,176 2028 596,835 (238,734) 2,984,173 544,964,227 543,770,558 27,520,125 401,563,732 2029 599,461 (239,784) 2,997,303 547,362,070 546,163,148 27,641,214 428,365,701 2030 602,098 (240,839) 3,010,491 549,770,463 548,566,266 27,762,835 455,285,598 2031 604,748 (241,899) 3,023,738 552,189,453 550,979,958 27,884,991 482,323,943 2032 - - 552,189,453 552,189,453 27,946,204 510,270,147 2033 - - 552,189,453 552,189,453 27,946,204 538,216,351 2034 - 552,189,453 - - - 276,094,726 13,973,102 -

TOTALS 92,236,410$ (36,894,564)$ 552,189,453$ -$ 461,182,049$ 10,870,773,530$



Page 8 of 14

Prairie IslandAccount 324 - Accessory Electrical Equipment




2012 202,259,192$ 159,668,358$ 2013 283,163$ (14,158)$ 1,415,814$ 203,391,843 202,825,517$ 3,127,053$ 162,498,089 2014 284,749 (14,237) 1,423,743 204,530,837 203,961,340 3,144,564 165,343,668 2015 286,343 (14,317) 1,431,716 205,676,210 205,103,524 3,162,174 168,205,181 2016 287,947 (14,397) 1,439,733 206,827,997 206,252,103 3,179,882 171,082,719 2017 289,559 (14,478) 1,447,796 207,986,234 207,407,115 3,197,689 173,976,371 2018 291,181 (14,559) 1,455,904 209,150,956 208,568,595 3,215,596 176,886,228 2019 292,811 (14,641) 1,464,057 210,322,202 209,736,579 3,233,604 179,812,380 2020 294,451 (14,723) 1,472,255 211,500,006 210,911,104 3,251,712 182,754,918 2021 296,100 (14,805) 1,480,500 212,684,406 212,092,206 3,269,921 185,713,934 2022 297,758 (14,888) 1,488,791 213,875,439 213,279,923 3,288,233 188,689,521 2023 299,426 (14,971) 1,497,128 215,073,141 214,474,290 3,306,647 191,681,772 2024 301,102 (15,055) 1,505,512 216,277,551 215,675,346 3,325,164 194,690,778 2025 302,789 (15,139) 1,513,943 217,488,705 216,883,128 3,343,785 197,716,636 2026 304,484 (15,224) 1,522,421 218,706,642 218,097,674 3,362,510 200,759,438 2027 306,189 (15,309) 1,530,946 219,931,399 219,319,021 3,381,341 203,819,280 2028 307,904 (15,395) 1,539,520 221,163,015 220,547,207 3,400,276 206,896,256 2029 309,628 (15,481) 1,548,141 222,401,528 221,782,271 3,419,318 209,990,464 2030 311,362 (15,568) 1,556,811 223,646,976 223,024,252 3,438,466 213,102,000 2031 313,106 (15,655) 1,565,529 224,899,400 224,273,188 3,457,721 216,230,960 2032 - - 224,899,400 224,899,400 3,467,376 219,698,336 2033 - - 224,899,400 224,899,400 3,467,376 223,165,712 2034 - 224,899,400 - - - 112,449,700 1,733,688 0

TOTALS 5,660,052$ (283,003)$ 224,899,400$ -$ 28,300,260$ 4,616,462,883$



Page 9 of 14

Prairie IslandAccount 325 - Miscellaneous Equipment




2012 82,163,980$ 59,790,855$ 2013 1,577,548$ (63,102)$ 7,887,742$ 88,474,173 85,319,076$ 6,834,719$ 64,984,923 2014 1,698,704 (67,948) 8,493,521 95,268,990 91,871,582 7,359,625 70,577,896 2015 1,829,165 (73,167) 9,145,823 102,585,648 98,927,319 7,924,844 76,600,409 2016 1,969,644 (78,786) 9,848,222 110,464,226 106,524,937 8,533,472 83,085,451 2017 2,120,913 (84,837) 10,604,566 118,947,879 114,706,052 9,188,843 90,068,544 2018 2,283,799 (91,352) 11,418,996 128,083,076 123,515,477 9,894,546 97,587,939 2019 2,459,195 (98,368) 12,295,975 137,919,856 133,001,466 10,654,447 105,684,823 2020 2,648,061 (105,922) 13,240,306 148,512,101 143,215,978 11,472,709 114,403,549 2021 2,851,432 (114,057) 14,257,162 159,917,830 154,214,965 12,353,813 123,791,872 2022 3,070,422 (122,817) 15,352,112 172,199,519 166,058,675 13,302,586 133,901,218 2023 3,306,231 (132,249) 16,531,154 185,424,443 178,811,981 14,324,224 144,786,962 2024 3,560,149 (142,406) 17,800,746 199,665,040 192,544,741 15,424,325 156,508,732 2025 3,833,569 (153,343) 19,167,844 214,999,315 207,332,177 16,608,913 169,130,733 2026 4,127,987 (165,119) 20,639,934 231,511,262 223,255,289 17,884,477 182,722,104 2027 4,445,016 (177,801) 22,225,081 249,291,327 240,401,295 19,258,005 197,357,292 2028 4,786,393 (191,456) 23,931,967 268,436,901 258,864,114 20,737,020 213,116,463 2029 5,153,989 (206,160) 25,769,943 289,052,855 278,744,878 22,329,623 230,085,938 2030 5,549,815 (221,993) 27,749,074 311,252,114 300,152,485 24,044,538 248,358,668 2031 5,976,041 (239,042) 29,880,203 335,156,277 323,204,196 25,891,159 268,034,745 2032 - - 335,156,277 335,156,277 26,848,613 294,883,357 2033 - - 335,156,277 335,156,277 26,848,613 321,731,970 2034 - 335,156,277 - - - 167,578,138 13,424,306 (0)

TOTALS 63,248,074$ (2,529,923)$ 335,156,277$ -$ 316,240,371$ 4,258,557,375$



Page 10 of 14

MonticelloAccount 321 - Structures and Improvements




2012 187,861,790$ 103,810,195$ 2013 394,510$ (51,286)$ 1,972,549$ 189,439,829 188,650,809$ 6,204,782$ 109,569,181 2014 397,824 (51,717) 1,989,118.20 191,031,123 190,235,476 6,256,902 115,376,542 2015 401,165 (52,151) 2,005,826.80 192,635,785 191,833,454 6,309,460 121,232,685 2016 404,535 (52,590) 2,022,675.74 194,253,925 193,444,855 6,362,459 127,138,020 2017 407,933 (53,031) 2,039,666.22 195,885,658 195,069,792 6,415,904 133,092,959 2018 411,360 (53,477) 2,056,799.41 197,531,098 196,708,378 6,469,798 139,097,920 2019 414,815 (53,926) 2,074,076.53 199,190,359 198,360,728 6,524,144 145,153,322 2020 418,300 (54,379) 2,091,498.77 200,863,558 200,026,959 6,578,947 151,259,590 2021 421,813 (54,836) 2,109,067.36 202,550,812 201,707,185 6,634,210 157,417,151 2022 425,357 (55,296) 2,126,783.53 204,252,239 203,401,525 6,689,937 163,626,435 2023 428,930 (55,761) 2,144,648.51 205,967,958 205,110,098 6,746,133 169,887,877 2024 432,533 (56,229) 2,162,663.56 207,698,088 206,833,023 6,802,800 176,201,916 2025 436,166 (56,702) 2,180,829.93 209,442,752 208,570,420 6,859,944 182,568,992 2026 439,830 (57,178) 2,199,148.90 211,202,072 210,322,412 6,917,567 188,989,551 2027 443,524 (57,658) 2,217,621.75 212,976,169 212,089,120 6,975,675 195,464,044 2028 - 212,976,169 212,976,169 7,004,850 202,468,894 2029 - 212,976,169 212,976,169 7,004,850 209,473,744 2030 212,976,169 - - - 106,488,084 3,502,425 0

TOTALS 6,278,595$ (816,217)$ 212,976,169$ -$ 31,392,974$ 3,534,804,658$



Page 11 of 14

MonticelloAccount 322 - Reactor Plant Equipment




2012 392,065,711$ 235,089,265$ 2013 2,666,047$ (1,066,419)$ 13,330,234$ 402,729,899 397,397,805$ 19,137,181$ 250,493,980 2014 2,738,563 (1,095,425) 13,692,816.56 413,684,152 408,207,025 19,657,712 266,317,703 2015 2,813,052 (1,125,221) 14,065,261.17 424,936,361 419,310,256 20,192,402 282,571,832 2016 2,889,567 (1,155,827) 14,447,836.27 436,494,630 430,715,495 20,741,635 299,268,072 2017 2,968,163 (1,187,265) 14,840,817.42 448,367,284 442,430,957 21,305,807 316,418,451 2018 3,048,898 (1,219,559) 15,244,487.65 460,562,874 454,465,079 21,885,325 334,035,320 2019 3,131,828 (1,252,731) 15,659,137.71 473,090,184 466,826,529 22,480,606 352,131,368 2020 3,217,013 (1,286,805) 16,085,066.26 485,958,237 479,524,211 23,092,079 370,719,628 2021 3,304,516 (1,321,806) 16,522,580.06 499,176,301 492,567,269 23,720,183 389,813,489 2022 3,394,399 (1,357,760) 16,971,994.24 512,753,897 505,965,099 24,365,372 409,426,703 2023 3,486,726 (1,394,691) 17,433,632.48 526,700,803 519,727,350 25,028,110 429,573,396 2024 3,581,565 (1,432,626) 17,907,827.29 541,027,064 533,863,933 25,708,875 450,268,079 2025 3,678,984 (1,471,594) - 18,394,920.19 555,743,001 548,385,032 26,408,156 471,525,658 2026 3,779,052 (1,511,621) 18,895,262.02 570,859,210 563,301,105 27,126,458 493,361,443 2027 3,881,843 (1,552,737) 19,409,213.15 586,386,581 578,622,895 27,864,298 515,791,161 2028 - 586,386,581 586,386,581 28,238,168 544,029,329 2029 - 586,386,581 586,386,581 28,238,168 572,267,497 2030 586,386,581 - - - 293,193,290 14,119,084 -

TOTALS 48,580,217$ (19,432,087)$ 586,386,581$ -$ 242,901,087$ 8,707,276,493$



Page 12 of 14

MonticelloAccount 323 - Turbogenerator Equipment




2012 261,385,409$ 29,346,850$ 2013 4,548,106$ (1,819,242)$ 22,740,531$ 279,577,834 270,481,621$ 26,745,631$ 49,725,133 2014 4,864,654 (1,945,862) 24,323,271.53 299,036,451 289,307,142 28,607,127 71,521,744 2015 5,203,234 (2,081,294) 26,016,171.23 319,849,388 309,442,919 30,598,183 94,835,399 2016 5,565,379 (2,226,152) 27,826,896.75 342,110,905 330,980,147 32,727,817 119,771,684 2017 5,952,730 (2,381,092) 29,763,648.77 365,921,824 354,016,365 35,005,673 146,443,535 2018 6,367,040 (2,546,816) 31,835,198.72 391,389,983 378,655,904 37,442,067 174,971,747 2019 6,810,186 (2,724,074) 34,050,928.55 418,630,726 405,010,355 40,048,035 205,485,522 2020 7,284,175 (2,913,670) 36,420,873.18 447,767,425 433,199,075 42,835,379 238,123,056 2021 7,791,153 (3,116,461) 38,955,765.95 478,932,037 463,349,731 45,816,721 273,032,162 2022 8,333,417 (3,333,367) 41,667,087.26 512,265,707 495,598,872 49,005,565 310,370,943 2023 8,913,423 (3,565,369) 44,567,116.53 547,919,401 530,092,554 52,416,352 350,308,502 2024 9,533,798 (3,813,519) 47,668,987.84 586,054,591 566,986,996 56,064,530 393,025,715 2025 10,197,350 (4,078,940) 50,986,749.40 626,843,990 606,449,291 59,966,621 438,716,047 2026 10,907,085 (4,362,834) 54,535,427.16 670,472,332 648,658,161 64,140,298 487,586,426 2027 11,666,219 (4,666,487) 58,331,092.89 717,137,206 693,804,769 68,604,463 539,858,182 2028 - 717,137,206 717,137,206 70,911,610 610,769,792 2029 - 717,137,206 717,137,206 70,911,610 681,681,402 2030 717,137,206 - - - 358,568,603 35,455,805 -

TOTALS 113,937,949$ (45,575,180)$ 717,137,206$ -$ 569,689,746$ 8,568,876,919$



Page 13 of 14

MonticelloAccount 324 - Accessory Electrical Equipment




2012 82,612,412$ 28,816,514$ 2013 1,520,068$ (106,405)$ 7,600,342$ 88,692,685 85,652,548$ 7,702,953$ 34,892,994 2014 1,631,945 (114,236) 8,159,727.04 95,220,467 91,956,576 8,269,890 41,416,702 2015 1,752,057 (122,644) 8,760,282.95 102,228,693 98,724,580 8,878,554 48,420,556 2016 1,881,008 (131,671) 9,405,039.78 109,752,725 105,990,709 9,532,015 55,939,893 2017 2,019,450 (141,362) 10,097,250.70 117,830,526 113,791,625 10,233,572 64,012,653 2018 2,168,082 (151,766) 10,840,408.36 126,502,852 122,166,689 10,986,763 72,679,568 2019 2,327,652 (162,936) 11,638,262.41 135,813,462 131,158,157 11,795,388 81,984,368 2020 2,498,968 (174,928) 12,494,838.52 145,809,333 140,811,398 12,663,529 91,974,002 2021 2,682,892 (187,802) 13,414,458.64 156,540,900 151,175,117 13,595,565 102,698,873 2022 2,880,353 (201,625) 14,401,762.80 168,062,310 162,301,605 14,596,198 114,213,094 2023 3,092,347 (216,464) 15,461,732.54 180,431,696 174,247,003 15,670,479 126,574,761 2024 3,319,943 (232,396) 16,599,716.05 193,711,469 187,071,583 16,823,826 139,846,248 2025 3,564,291 (249,500) 17,821,455.15 207,968,633 200,840,051 18,062,059 154,094,516 2026 3,826,623 (267,864) 19,133,114.25 223,275,125 215,621,879 19,391,427 169,391,456 2027 4,108,262 (287,578) 20,541,311.46 239,708,174 231,491,649 20,818,636 185,814,251 2028 - 239,708,174 239,708,174 21,557,569 207,371,820 2029 - 239,708,174 239,708,174 21,557,569 228,929,389 2030 239,708,174 - - - 119,854,087 10,778,784 0

TOTALS 39,273,941$ (2,749,176)$ 239,708,174$ -$ 196,369,703$ 2,812,271,604$



Page 14 of 14

MonticelloAccount 325 - Miscellaneous Equipment




2012 60,713,782$ 42,033,609$ 2013 315,712$ (12,628)$ 1,578,558$ 61,976,629 61,345,206$ 2,232,649$ 43,937,918 2014 322,278 (12,891) 1,611,392.36 63,265,743 62,621,186 2,279,088 45,881,837 2015 328,982 (13,159) 1,644,909.32 64,581,670 63,923,707 2,326,493 47,866,189 2016 335,825 (13,433) 1,679,123.43 65,924,969 65,253,320 2,374,884 49,891,816 2017 342,810 (13,712) 1,714,049.20 67,296,209 66,610,589 2,424,282 51,959,576 2018 349,940 (13,998) 1,749,701.42 68,695,970 67,996,089 2,474,707 54,070,345 2019 357,219 (14,289) 1,786,095.21 70,124,846 69,410,408 2,526,181 56,225,018 2020 364,649 (14,586) 1,823,245.99 71,583,443 70,854,144 2,578,726 58,424,508 2021 372,234 (14,889) 1,861,169.51 73,072,378 72,327,910 2,632,363 60,669,748 2022 379,976 (15,199) 1,899,881.83 74,592,284 73,832,331 2,687,116 62,961,689 2023 387,880 (15,515) 1,939,399.38 76,143,803 75,368,043 2,743,008 65,301,302 2024 395,948 (15,838) 1,979,738.88 77,727,594 76,935,699 2,800,063 67,689,579 2025 404,183 (16,167) 2,020,917.45 79,344,328 78,535,961 2,858,304 70,127,532 2026 412,591 (16,504) 2,062,952.54 80,994,690 80,169,509 2,917,757 72,616,195 2027 421,172 (16,847) 2,105,861.95 82,679,380 81,837,035 2,978,446 75,156,622 2028 - 82,679,380 82,679,380 3,009,103 78,165,725 2029 - 82,679,380 82,679,380 3,009,103 81,174,828 2030 82,679,380 - - - 41,339,690 1,504,552 0

TOTALS 5,491,399$ (219,656)$ 82,679,380$ -$ 27,456,997$ 1,273,719,587$


Docket No. E002/GR-13-868Exhibit __ (LHP-1), Schedule 14

Page 1 of 5

(17) Allowance for funds used during construction (Major and No major Utilities) includes the net cost for the period of construction of borrowed fundsreasonable rate on other funds when soused, not to exceed, without prior approval of the Commission, allowances computed in accordance with the formulafor construction projects which have been abandoned. a) The formula and elements for the computation of the allowance for fundssubparagraph. No allowance for funds used during construction charges shall be included in these accounts upon expenditures for construction projectswhich have been abandoned.(a) The formula and elements for the computation of the allowance for funds used during construction shall be:

Ai=s (S/W)+d (D/D+P+C)(1-S/W)Ae = [1-S/W][p (P/D+P+C)+c (C/D+P+C)]

Corresponding Amounts used in 2014 Forecasted rate calculation: Ai=Gross allowance for borrowed fund used during construction rateAe=Allowance for other funds used during construction rate

= $139,037,313 Current Year Forcasted= 0.3525% Current Year Forcasted= $3,900,002,415 Projected Book balance= 4.8831% Weighted average cost (forecasted)= $0 Projected Book balance= 0.0000% Weighted average cost (forecasted) Per part (b)= $4,414,661,203 Projected Book balance= 10.3700% Last authorized

= $1,028,560,614 Current Year Forcasted

Calculated Values Per FERC Electric Plant Instruction 17aAi=s (S/W)+d (D/D+P+C)(1-S/W)Ai=.3525% ($139,037,313/$1,028,560,614)+4.8831% ($3,900,002,415/$3,900,002,415+0+$4,414,661,203)(1-$139,037,313/$1,028,560,614)Ai=.003525 (.13517659)+.048831 (.46905)(.8648234)Ai=.000476497+.019808088Ai = 0.02028Ai = 2.028%

Ae = [1-S/W][p (P/D+P+C)+c (C/D+P+C)]Ae = [1-$139,037,313/$1,028,560,614][0% ($0/$3,900,002,415+$0+$4,414,661,203)+10.37% ($4,414,661,203/$3,900,002,415+$0+$4,414,661,203)]Ae = [.8648234][.1037 (.530948864)]Ae = 0.04762Ae = 4.762%

(b) The rates shall be determined annually. The balances for long-term debt, preferred stock and common equity shall be the actual book balancerates for long-term debt and preferred stock shall be the weighted average cost determined in the manner indicated in § 35.13 of the CommissionRegulations Under the Federal Power Act. The cost rate for common equity shall be the rate granted common equity in the last rate proceeding befothe ratemaking body having primary rate jurisdictions. If such cost rate is not available, the average rate actually earned during the preceding threyears shall be used. The short-term debt balances and related cost and the average balance for construction working progress plus nuclear fuel in procesof refinement, conversion, enrichment and fabrication shall be estimated for the current year with appropriate adjustments as actual data becomes availabl

"A number of respondents commented that previously capitalized AFUDC should be included in the cost base to which the AFUDC rate applies since AFUDC is cost of construction similar to labor, materials and other elements of construction. Thus, it is asserted that the compound method must be recognized if AFUDis to properly compensate the utility for use of funds while devoted to construction. We agree that compounding of AFUDC is proper in theory and necessary asmatter of sound cost determination; however, we believe that a monthly compounding of AFUDC as suggested by some respondents may result in excessivamounts capitalized since cash outlays for interest and dividends are not normally made on a monthly basis. We shall therefore permit compounding but no mofrequently then semiannually"

Debt Equity Total2.0285% 4.7617% 6.7902%

2.0384% 4.8180% 6.8564%

0.1683% 0.3929% 0.5612%

Note: To avoid possible negative AFUDC rates in the situations were short-term debt exceeds construction work in progress, ORDER NO. 561 - A states"We believe that this matter can best be clarified by stating herein that if short-term debt balances exceed construction work in progress plus nuclear fuin process of refinement, conversion, enrichment and fabrication the maximum total AFUDC rate to be utilized will be the weighted average short-term debt rat

FERC ORDER NO. 561 - A

Compounding AFUDC

FERC Electric Plant Instruction #3 (17)

W=Average balance in construction work in progress plus nuclear fuel in processes of refinement, conversion, enrichment and fabrication, less asset retirement cost (See General

S=Average short-term debt.s =Short-term debt interest rate.D=Long-term debt.d=Long-term debt interest rate

Effective Monthly Rate (Semi-Annual Compounding)

((1 + (Tot Nominal Rate / 2)) ^ 2) - 1 =

((1 + (Tot Nominal Rate / 2)) ^ 2)^*(1/12) - 1 =

P=Preferred stock.p =Preferred stock cost rate.C=Common equity.c =Common equity cost rate

Effective Annual Rate (Semi-Annual Compounding)

Simple Rate

FERC ORDER NO. 561



Page 2 of 5

Project CWIP Rollforward from Case:January February march April May June July august September October November December

Beginning Balance (a) 3,587,881 5,119,286 5,718,793 6,467,607 7,197,776 8,541,942 9,580,203 10,562,476 12,340,166 12,964,408 13,842,045 14,556,459Expenditures (b) 1,507,041 569,181 714,715 691,931 1,300,124 987,552 925,911 1,713,605 553,436 802,629 634,951 656,056AFUDC Debt (c) 7,307 9,095 10,226 11,467 13,208 15,207 16,903 19,219 21,234 22,495 23,830 12,525AFUDC Equity (d) 17,057 21,232 23,873 26,771 30,834 35,501 39,460 44,866 49,572 52,514 55,633 29,241Closings (e) 0 0 0 0 0 0 0 0 0 0 0 (15,254,281)Ending Balance (f) 5,119,286 5,718,793 6,467,607 7,197,776 8,541,942 9,580,203 10,562,476 12,340,166 12,964,408 13,842,045 14,556,459 0

Validation of AFUDC Calculation(*):CWIP Beginning Balance 3,587,881 5,119,286 5,718,793 6,467,607 7,197,776 8,541,942 9,580,203 10,562,476 12,340,166 12,964,408 13,842,045 14,556,459CWIP Ending Balance Without AFUDC 5,094,922 5,688,467 6,433,508 7,159,538 8,497,900 9,529,494 10,506,114 12,276,081 12,893,602 13,767,037 14,476,996 (41,766)Average CWIP Balance 4,341,401 5,403,876 6,076,151 6,813,573 7,847,838 9,035,718 10,043,158 11,419,278 12,616,884 13,365,722 14,159,521 7,257,347AFUDC Debt Rate (Monthly) 0.1683% 0.1683% 0.1683% 0.1683% 0.1683% 0.1683% 0.1683% 0.1683% 0.1683% 0.1683% 0.1683% 0.1683%AFUDC Debt Calculated 7,307 9,095 10,226 11,467 13,208 15,207 16,903 19,219 21,234 22,495 23,830 12,525AFUDC Equity Rate (Monthly) 0.3929% 0.3929% 0.3929% 0.3929% 0.3929% 0.3929% 0.3929% 0.3929% 0.3929% 0.3929% 0.3929% 0.3929%AFUDC Equity Calculated 17,057 21,232 23,873 26,771 30,834 35,501 39,460 44,866 49,572 52,514 55,633 29,241Difference 0 0 0 0 0 0 0 0 0 0 0 0Difference 0 0 0 0 0 0 0 0 0 0 0 0

Beginning Balance (a) 3,587,881 5,119,286 5,718,793 6,467,607 7,197,776 8,541,942 9,580,203 10,562,476 12,340,166 12,964,408 13,842,045 14,556,459Expenditures (b) 1,507,041 569,181 714,715 691,931 1,300,124 987,552 925,911 1,713,605 553,436 802,629 634,951 656,056AFUDC Debt (c) 7,307 9,095 10,226 11,467 13,208 15,207 16,903 19,219 21,234 22,495 23,830 12,525AFUDC Equity (d) 17,057 21,232 23,873 26,771 30,834 35,501 39,460 44,866 49,572 52,514 55,633 29,241Closings (e) 0 0 0 0 0 0 0 0 0 0 0 (15,254,281)Ending Balance (f) 5,119,286 5,718,793 6,467,607 7,197,776 8,541,942 9,580,203 10,562,476 12,340,166 12,964,408 13,842,045 14,556,459 0

Parent Work Order Details:Parent Work Order 11490412Beginning Balance (a) 3,492,380.55 3,536,945.65 3,581,760.85 3,626,827.55 3,672,147.16 4,292,485.38 4,918,888.17 5,859,368.33 7,564,057.06 8,142,473.26 8,952,837.47 9,622,862.03Expenditures (b) 24,896.00 24,896.00 24,896.00 24,896.00 598,052.00 600,628.00 910,321.00 1,667,128.00 534,467.00 762,529.00 618,047.00 648,876.00AFUDC Debt (c) 5,898.63 5,973.63 6,049.05 6,124.90 6,683.48 7,729.68 9,044.52 11,264.20 13,180.06 14,345.45 15,587.71 8,370.65AFUDC Equity (d) 13,770.47 13,945.57 14,121.65 14,298.71 15,602.74 18,045.11 21,114.64 26,296.53 30,769.14 33,489.76 36,389.85 19,541.47Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (10,299,650.15)Ending Balance (f) 3,536,945.65 3,581,760.85 3,626,827.55 3,672,147.16 4,292,485.38 4,918,888.17 5,859,368.33 7,564,057.06 8,142,473.26 8,952,837.47 9,622,862.03 0.00Beginning Balance (a) 3,492,380.55 3,536,945.65 3,581,760.85 3,626,827.55 3,672,147.16 4,292,485.38 4,918,888.17 5,859,368.33 7,564,057.06 8,142,473.26 8,952,837.47 9,622,862.03Expenditures (b) 24,896.00 24,896.00 24,896.00 24,896.00 598,052.00 600,628.00 910,321.00 1,667,128.00 534,467.00 762,529.00 618,047.00 648,876.00AFUDC Debt (c) 5,898.63 5,973.63 6,049.05 6,124.90 6,683.48 7,729.68 9,044.52 11,264.21 13,180.06 14,345.45 15,587.71 8,370.65AFUDC Equity (d) 13,770.47 13,945.57 14,121.65 14,298.71 15,602.74 18,045.11 21,114.64 26,296.53 30,769.14 33,489.77 36,389.85 19,541.47Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (10,299,650.15)Ending Balance (f) 3,536,945.65 3,581,760.85 3,626,827.55 3,672,147.16 4,292,485.38 4,918,888.17 5,859,368.33 7,564,057.07 8,142,473.26 8,952,837.48 9,622,862.03 0.00

Minnesota Valley - Kerkhoven Uprate ProjectEstimated In Service Date: December 31, 2014



Page 3 of 5

Project CWIP Rollforward from Case:

Minnesota Valley - Kerkhoven Uprate ProjectEstimated In Service Date: December 31, 2014

Parent Work Order 11799723Beginning Balance (a) 46,265.98 50,751.45 55,262.09 59,798.04 64,359.45 68,946.46 73,559.21 78,197.85 82,862.52 87,553.37 92,270.55 97,014.20Expenditures (b) 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00AFUDC Debt (c) 81.41 88.96 96.55 104.19 111.86 119.58 127.35 135.15 143.00 150.90 158.84 83.41AFUDC Equity (d) 190.06 207.68 225.40 243.22 261.15 279.17 297.29 315.52 333.85 352.28 370.81 194.72Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (101,506.33)Ending Balance (f) 50,751.45 55,262.09 59,798.04 64,359.45 68,946.46 73,559.21 78,197.85 82,862.52 87,553.37 92,270.55 97,014.20 0.00Beginning Balance (a) 46,265.98 50,751.45 55,262.09 59,798.04 64,359.45 68,946.46 73,559.21 78,197.85 82,862.52 87,553.37 92,270.55 97,014.20Expenditures (b) 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00 4,214.00AFUDC Debt (c) 81.41 88.96 96.55 104.19 111.86 119.58 127.35 135.15 143.00 150.90 158.84 83.41AFUDC Equity (d) 190.06 207.68 225.40 243.22 261.15 279.17 297.29 315.52 333.85 352.28 370.81 194.72Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (101,506.33)Ending Balance (f) 50,751.45 55,262.09 59,798.05 64,359.45 68,946.46 73,559.21 78,197.85 82,862.52 87,553.37 92,270.54 97,014.20 0.00

Parent Work Order 11735076Beginning Balance (a) 46,287.76 1,528,395.94 2,078,330.07 2,774,482.94 3,451,694.69 4,167,842.26 4,571,976.55 4,606,437.10 4,634,359.20 4,662,438.00 4,690,674.38 4,718,472.55Expenditures (b) 1,477,702.00 539,842.00 682,574.00 659,790.00 694,827.00 379,679.00 8,778.00 2,065.00 2,065.00 2,065.00 1,470.00 980.00AFUDC Debt (c) 1,321.38 3,026.56 4,072.21 5,224.66 6,393.89 7,333.97 7,702.02 7,754.37 7,801.36 7,848.62 7,895.64 3,971.00AFUDC Equity (d) 3,084.80 7,065.57 9,506.66 12,197.09 14,926.68 17,121.32 17,980.53 18,102.73 18,212.44 18,322.76 18,432.53 9,270.40Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (4,732,693.95)Ending Balance (f) 1,528,395.94 2,078,330.07 2,774,482.94 3,451,694.69 4,167,842.26 4,571,976.55 4,606,437.10 4,634,359.20 4,662,438.00 4,690,674.38 4,718,472.55 0.00Beginning Balance (a) 46,287.76 1,528,395.94 2,078,330.07 2,774,482.94 3,451,694.69 4,167,842.26 4,571,976.55 4,606,437.10 4,634,359.20 4,662,438.00 4,690,674.38 4,718,472.55Expenditures (b) 1,477,702.00 539,842.00 682,574.00 659,790.00 694,827.00 379,679.00 8,778.00 2,065.00 2,065.00 2,065.00 1,470.00 980.00AFUDC Debt (c) 1,321.39 3,026.57 4,072.22 5,224.67 6,393.90 7,333.98 7,702.02 7,754.37 7,801.36 7,848.62 7,895.64 3,971.01AFUDC Equity (d) 3,084.81 7,065.59 9,506.68 12,197.10 14,926.70 17,121.33 17,980.54 18,102.75 18,212.45 18,322.78 18,432.55 9,270.40Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (4,732,693.95)Ending Balance (f) 1,528,395.96 2,078,330.09 2,774,482.96 3,451,694.71 4,167,842.29 4,571,976.57 4,606,437.11 4,634,359.22 4,662,438.02 4,690,674.40 4,718,472.57 0.01

Parent Work Order 11742120Beginning Balance (a) 2,946.37 3,192.55 3,440.11 6,498.92 9,574.90 12,668.14 15,778.74 18,472.58 58,887.05 71,943.14 106,262.79 118,110.62Expenditures (b) 229.00 229.00 3,031.00 3,031.00 3,031.00 3,031.00 2,598.00 40,198.00 12,690.00 33,821.00 11,220.00 1,986.00AFUDC Debt (c) 5.15 5.57 8.34 13.49 18.67 23.87 28.74 64.92 109.79 149.54 188.28 100.23AFUDC Equity (d) 12.03 12.99 19.47 31.49 43.57 55.73 67.10 151.55 256.30 349.11 439.55 233.98Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (120,430.83)Ending Balance (f) 3,192.55 3,440.11 6,498.92 9,574.90 12,668.14 15,778.74 18,472.58 58,887.05 71,943.14 106,262.79 118,110.62 0.00Beginning Balance (a) 2,946.37 3,192.55 3,440.11 6,498.92 9,574.90 12,668.14 15,778.74 18,472.58 58,887.05 71,943.14 106,262.79 118,110.62Expenditures (b) 229.00 229.00 3,031.00 3,031.00 3,031.00 3,031.00 2,598.00 40,198.00 12,690.00 33,821.00 11,220.00 1,986.00AFUDC Debt (c) 5.15 5.57 8.34 13.49 18.67 23.87 28.74 64.92 109.79 149.54 188.28 100.23AFUDC Equity (d) 12.03 12.99 19.47 31.49 43.57 55.73 67.10 151.55 256.30 349.11 439.55 233.98Closings (e) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (120,430.83)Ending Balance (f) 3,192.55 3,440.11 6,498.92 9,574.90 12,668.14 15,778.74 18,472.58 58,887.04 71,943.13 106,262.79 118,110.62 (0.01)

From January - November the Minnesota Valley project is expected to be under construction and the AFUDC will calculate by taking:AFUDC Debt (c) ={Beginning Balance (a) + 1/2 Current Month Expenditures (b)} * Monthly Debt RateAFUDC Equity (d) ={Beginning Balance (a) + 1/2 Current Month Expenditures (b)} * Monthly Equity Rate

The Minnesota Valley project is scheduled to go into service in December, therefore only 1/2 month or 15 days of AFUDC will be calculated for the estimated In Service month:AFUDC Debt (c) =[{Beginning Balance (a) + 1/2 Current Month Expenditures(b)}* Monthly Debt]/2AFUDC Equity (d) =[{Beginning Balance (a) + 1/2 Current Month Expenditures(b)}* Equity Rate]/2



Page 4 of 5

Test Year 2014 TotalsAverage CWIP 1,009,148,193

January February March April May June July August September October November December Totals AVERAGE

2008 CWIP 1,001,961,654 1,029,955,769 1,097,471,082 1,171,084,753 877,863,785 900,005,869 870,558,142 939,415,310 937,238,893 986,182,545 754,597,552 765,477,770 11,331,813,124 944,317,760AFUDC 6,050,200 6,572,188 7,407,211 7,296,291 6,870,001 5,483,443 4,946,991 5,703,706 5,594,001 5,937,873 5,592,945 4,706,650 72,161,501 6,013,458As Percent 0.6038% 0.6381% 0.6749% 0.6230% 0.7826% 0.6093% 0.5683% 0.6072% 0.5969% 0.6021% 0.7412% 0.6149%

2009 CWIP 814,022,910 843,940,679 706,149,074 732,439,366 701,339,713 749,959,943 758,133,133 712,518,807 682,177,457 707,896,019 702,839,542 696,926,181 8,808,342,823 734,028,569AFUDC 4,671,741 5,175,084 4,812,449 4,263,982 4,266,729 4,795,002 4,184,977 4,164,251 3,663,350 4,007,523 4,255,712 3,999,474 52,260,275 4,355,023As Percent 0.5739% 0.6132% 0.6815% 0.5822% 0.6084% 0.6394% 0.5520% 0.5844% 0.5370% 0.5661% 0.6055% 0.5739%

2010 CWIP 760,639,542 788,908,255 810,405,599 865,774,307 907,874,396 1,012,562,772 1,098,709,002 1,193,003,010 1,242,801,598 1,283,395,804 1,351,918,223 831,059,719 12,147,052,227 1,012,254,352AFUDC 4,536,139 4,995,219 5,298,373 5,531,858 5,921,224 5,182,741 6,716,507 7,418,715 6,866,190 8,523,277 8,415,139 11,449,254 80,854,636 6,737,886As Percent 0.5964% 0.6332% 0.6538% 0.6389% 0.6522% 0.5118% 0.6113% 0.6219% 0.5525% 0.6641% 0.6225% 1.3777%

2011 CWIP 813,802,383 861,818,582 905,622,634 962,779,688 807,633,604 813,672,773 811,573,126 844,804,159 830,728,921 817,327,871 832,924,621 728,228,630 10,030,916,991 835,909,749AFUDC 5,164,934 4,962,183 4,137,662 6,091,611 6,154,385 5,300,180 5,152,314 5,357,946 4,062,043 5,183,008 5,134,621 4,473,113 61,174,001 5,097,833As Percent 0.6347% 0.5758% 0.4569% 0.6327% 0.7620% 0.6514% 0.6349% 0.6342% 0.4890% 0.6341% 0.6165% 0.6142%

2012 CWIP 734,460,281 772,646,348 868,404,933 911,879,808 950,672,867 1,018,246,644 1,081,340,625 1,120,601,079 1,117,751,155 1,097,005,738 1,130,737,731 1,097,709,863 11,901,457,073 991,788,089AFUDC 4,239,153 4,450,491 4,971,517 5,171,904 5,203,824 5,684,609 5,998,981 6,073,580 6,240,022 6,193,247 6,250,428 6,225,525 66,703,279 5,558,607As Percent 0.5772% 0.5760% 0.5725% 0.5672% 0.5474% 0.5583% 0.5548% 0.5420% 0.5583% 0.5646% 0.5528% 0.5671%

Average CWIP 903,659,704Average AFUDC 5,552,562

Charge Type January February March April May June July August September October November December Total AVERAGEBeg Balance 1,112,032,448 949,599,559 999,346,251 1,044,942,684 1,028,056,091 1,056,666,581 1,048,558,478 1,040,589,558 1,078,481,147 1,021,777,132 984,435,182 989,462,975Expenditures 80,847,920 79,551,659 99,534,283 107,174,608 99,010,402 81,075,088 76,371,845 72,635,791 82,983,705 59,081,306 49,982,043 158,767,894Closings (248,878,122) (35,146,656) (59,555,541) (129,762,828) (76,133,196) (94,964,112) (90,062,479) (40,542,290) (145,430,737) (101,906,386) (50,336,930) (218,467,038)Total CWIP 944,002,246 994,004,562 1,039,324,993 1,022,354,464 1,050,933,297 1,042,777,557 1,034,867,844 1,072,683,059 1,016,034,115 978,952,052 984,080,295 929,763,831 12,109,778,315 1,009,148,193

Debt 1,678,595 1,601,936 1,684,707 1,709,879 1,719,372 1,733,658 1,715,902 1,738,807 1,722,292 1,644,353 1,614,228 1,587,094Equity 3,918,718 3,739,753 3,932,985 3,991,748 4,013,911 4,047,263 4,005,811 4,059,281 4,020,726 3,838,777 3,768,452 3,705,105Total AFUDC 5,597,313 5,341,689 5,617,691 5,701,627 5,733,284 5,780,921 5,721,714 5,798,088 5,743,018 5,483,130 5,382,680 5,292,199 67,193,354 5,599,446

Ending Balance 949,599,559 999,346,251 1,044,942,684 1,028,056,091 1,056,666,581 1,048,558,478 1,040,589,558 1,078,481,147 1,021,777,132 984,435,182 989,462,975 935,056,031 12,176,971,669 1,014,747,639

Test Year 2014 Totals

Test Year 2014 Summary

Five Year Totals



Page 5 of 5

AFUDC RATE CALCULATION - FORECAST 2014 NSP-MN(000's)

The forecasted AFUDC rate is 6.856% This calculation ispresented below and includes CWIP Forecast through 2014

Input Values (000s) 13-May-13Prior Fcst Change

S = Average Short-Term Debt for year (2014 12 Mo. Avg.) = $ 139,037 ST DEBT TABLE 124,716 14,321 RS = Short-Term Debt Interest Rate = 0.353% Libor/Prime Rates 0.352% 0.00% D = Long-Term Debt (2013 YR. END) = $ 3,900,002 LTD/Equity DEBT TABLE 3,900,002 0 RD = Long-Term Debt Interest Rate = 4.883% LTD/Equity DEBT TABLE 4.883% 0.00% P = Preferred Stock (2013 YR. END) = $ 0 0 0 RP = Preferred Stock Cost Rate = 0.00% 0.00% 0.00% C = Common Equity (2013 YR. END) = $ 4,414,661 LTD/Equity DEBT TABLE 4,405,275 9,386 RC = Common Equity Cost Rate (Authorized) = 10.37% Authorized Rate - Docket E-002/GR-10-971. Dated 05/14 10.37% 0.00% W = Average CWIP plus Nuclear Fuel in Process (2014 13 Mo. Avg.) = $ 1,028,561 Capital Asset Accounting 1,018,364 10,197

Calculated Values AI = Rate for Gross Allowance for Borrowed Funds used during Construction AI = (RS * (S/W)) + (RD * (D/(D+P+C)) * (1-S/W)) AI 2.03% debt % = 29.87% 2.03% 2.06% -0.03%

AE = Rate for Allowance for Other Funds used during Construction AE = (1-S/W) * (RP * (P/(D+P+C)) + RC * (C/(D+P+C))) AE 4.76% equity % = 70.13% 4.76% 4.83% -0.07%

Simple Rate = 2.0285% + 4.7617% = 6.7902% 6.882% -0.09%

Effective Annual Rate (Semi-Annual Compounding) ((1 + (Tot Nominal Rate / 2)) ^ 2) - 2.0384% 4.8180% 6.8564% 6.950% -0.09%

Effective Monthly Rate (Semi-Annual Compounding) ((1 + (Tot Nominal Rate / 2)) ^ 2)^* 0.1683% 0.3929% 0.5612% 0.5687% -0.01%

Note: Per FERC Order 561-A, if STD exceeds CWIP, the STD rate becomes the AFUDC rate (100% debt). Monthly AFUDC by Debt or Equity: Thus, the AFUDC rate is the STD rate. Debt Forecast as an Expense Adj. 0.001683 0.001705 0.00% (all ABFUDC, no AEFUDC). Equity Forecast as Other Income 0.003929 0.003982 -0.01%

0.005612 0.005687 -0.01%

Citation Search Result Rank 51 of 5157 FPC 6081977 WL 17150 (F.P.C.)(Publication page references are not available for this document.)

DatabaseFEN-FERC

AMENDMENTS TO UNIFORM SYSTEM OF ACCOUNTS FOR PUBLIC UTILITIES ANDLICENSEES AND FOR NATURAL GAS COMPANIES (CLASSES A, B, C AND D) TO PROVIDE FOR

THE DETERMINATION OF RATE FOR COMPUTING THE ALLOWANCE FOR FUNDS USED DURINGCONSTRUCTION AND REVISIONS OF CERTAIN SCHEDULE PAGES OF.FPC REPORTS,

DOCKET NO. RM75-27

ORDER NO. 561

ORDER ADOPTING AMENDMENT TO UNIFORM SYSTEM OF ACCOUNTS FOR PUBLIC UTILITIES ANDLICENSEES AND FOR NATURAL GAS COMPANIES

February 2, 1977"

Before Commissioners: Richard L. Dunham, Chairman; Don S. Smith, John H.Holloman III and James G. Watt.

On May 20, 1975, the Commission issued a notice of proposed rulemaking inDocket No. RM75-27 (40 F.R. 23322, May 29, 1975). This rulemaking proposed toestablish a uniform formulary method for determining the maximum rates to beused in computing the Allowance for Funds UsedDuring Construction (AFUDC) andto provide accounting and reporting requirements for AFUDC which accord wfth theelements entering into the determination of AFUDC rates. The stated object’iveof the proposed rule was to establish a method which would give recognition tothe interrelationship between capital utilized for rate case purposes and thecapital components of AFUDC in a manner that would permit utility to achieve arate of return on its total utility operations, including its constructionsprogram, at approximately the rate which would be allowed in a rate case.

Comments were invited from interested parties on or before July 7, 1975. Dueto requests, this date was. extended to September 5, 1975. In response to the .proposed rulemaking, the Commission received comments from 79 respondents(Attachment A). In general, the reaction to the proposed rulemaking wasfavorable as to its overall objective, but many respondents questioned theability of the proposal to meet such objective and made suggestions forimprovement.Many respondents objected to the weight given short-term debt in the proposed

rule and suggested a number of alternatives. These respondents argued that:{hort-term debt is not necessarily the first source of construction funds, aswould be indicated by application of he proposed formula, and should be ignoredor given less weight. We are not convinced, however, that we should modify theproposed formula with respect to short-term debt. It is generally impossible tospecifically trace the source of funds used for various corporate purposes andit was not the purpose of our proposed rule to do so. Instead, we proposed arule that would give a utility an opportunity to be compensated for the totalcost of capital devoted to utility operations, including its construction

Copr. © West 2002 No Claim to Orig. U.S. Govt. Works



57 FPC 608(Publication page references are not available for this document.)

Page 2

program. In order to accomplish this, it is necessary to look to how the costof capital is handled in a rate proceeding so that a method for determiningAFUDC can be devised that will not result in double counting of the same capitalcost or will not omit important categories of capital cost. Typically, short-term debt has not been included in rate of return computations for cost ofservice purposes on the grounds that such debt is temporary and is usedessentially for construction purposes; however, the cost of .such debt representsa valid and necessary expenditure for conducting utility operations whichultimately must be recovered through rates. By adopting the approach ofpermitting the capitalization of short-term debt cost through AFUDC, we providesuch a mechanism. It should be understood that this method is for the purposeof establishing a rate for AFUDC and not for establishing a method forallocating short-term interest cost for the purpose of a rate proceeding.

Many respondents also questioned the use of embedded cost rates for long-termdebt and preferred stock in the proposed AFUDC formula and suggested incrementalcost rates be used instead. For essentially the same reasons that we believethe proposed handling of short-term debt should not be modified, we arerejecting this suggestion. If incremental cost rates were utilized for thesecategories of capital cost in the AFUDC formula, there would be a doublecounting for the same costs. Embedded cost rates are normally used for rate ~freturn purposes and such cost rates include the cost of new as. well as oldissues of long-term debt and preferred stock. Therefore, the composite returnon rate base collected through rates provides for the proportionate recovery ofnew or incremental capital costs in the ratio of ra~e base to the size of thecapital structure used for rate of return purposes. If we assume fo the ~ake ofargument tha.t the sum of a utility’s permanent capital structure plus short-term borrowing is equal to the sum of its rate base plus construction work inprogress balances, it is obvious that the use of incremental cost for AFUDCpurposes and embedded cost for rate of return purposes would result in doublecounting of the same costs. Although the above illustration somewhatoversimplifies the issue, we believe that the principle is adequatelydemonstrated.~The.other basic component for A~UDC relates to common equity, fun~

by respondents on this subject primarily related to how the reasonable cost ratefor common equity funds should be determined. Unlike debt costs or the cost ofpreferred stock, which can be objectively determined by analysis of actualcontractual obligations and expenditures, the cost of cormmon equity is notordinarily related to contractual requirements. In the proposed rule weindicated that the cost rate to be used for com~on equity would be the rategranted common equity in the last rate proceeding before the body having primaryrate jurrisdiction or, if such rate is not available, the average rate~ ~ ~actuallyearned during the preceding 3 years should be used. We~mment s red~ived~

~situ~iQ~si~here ~ r~t~m~kihgor where ut±lities are subject tO imu!£iple rate

we f~nd any p~Ssible iie~uities ofthis nature can best be handled on an individual company basis.

Having considered the broad issues of the various components of the AFUDC, it

Copr. © West 2002 No Claim tb Orig. U.S. Govt. Works



FPC 608(Publication page references are not avail~ble for this document.)

is now necessary to focus on the many constructive and helpful comments andsuggestions received relating to Other facets of the proposed rulemaking.Many cormments were received regarding the desirability of segregating AFUDC

into two components, borrowed funds and other funds, and the relocation of theallowance for borrowed funds to the Interest Charges Section of the incomestatement. The main objection to this proposed requirement was that it wouldhave the effect of reducing interest coverages and thereby restrict theissuances of additional debt by some companies. We recognized that this may bea particularly uninviting aspect of the proposed rule for some utilities since’Other Income’ will be reduced upon application of the proposed rule and suchincome is frequently, in whole or part, used for interest coverage tests. [FNI]However, we believe this change to be necessary in order to better informreaders of the financial statements of utilities as to the nature and level ofthe capitalized allowance for borrowed funds. Since there is little conceptualdifference between capitalization of the cost of borrowed funds used forconstruction purposes and other costs of construction such as labor andmaterials, we believe that the readers of finanbial statements will be betterinformed if such construction interest is shown as an allocation of cost by areduction in the Interest Charges Section of the income statement rather than ~asan income item.A number of respondents criticized the proposal to determine the current year’s

AFUDC rates by the use of average actual book balances~ and cost rates of theprior year principally because short-term debt cost rates and balances are very.volatile and the use of averages for a previous year does not give a properindication of the cost of short-term debt for prospective computations ofAFUDC.We agree that this is a valid point and believe that modifications of theproposed rule in this are are necessary.We are m. 9~.~~p~_Oposed rule to provide that the balances of lonq-tg~m

~9~t, prefe<red stock~_~d.~9_mm~n e. u~z for use in the formula for the current.~ear will be the balances in such accounts at the end of the prior year; thecost rates for long-term debt and preferred stock will be the effectlv~weightedaverage cost of such capital. The average short-term debt balances and related~ost ~and the~avera~e const.ructi.on work in progress balance will .be estimated f~r.the current year. l~e shall require, however, that public utilities.and naturalgas companies monitor their actual experience and adjust to actual at year-endif a significant deviation from the estimate should occur. For this purpose weshal! consider a significant deviation to exist if the gross AFUDC rate exceedsby more than one-quarter of a percgntage point (25 basis points)jthe rate thatis derived from the formula by use of actual 13 monthl~ balances of constructionwork in progress and the actua! weighted average cost and balances for short-term debt outstanding during the year.

Many respondents requested clarification as to whether premiums, discounts andexpenses related to long-term debt, and compensating balances and~commitmentfees related to short-term debt, were to be considered when determining the costrate for such funds. With respect to long-term debt, the cost of such capitalshould be the yield to maturity determined in the same manner as set forth in §35.13(b) (4) (iii), Statement G--Rate of Return, of the Com!~ission’s Regulationsunder the Federal Power Act and § 154.63(f), Statement F(3)--Debt Capital, of





Page 4

the Commission’s Regulations under the Natural Gas Act which gives appropriaterecognition to premiums, discounts and expenses related to long- term debt. Inregard to short-term debt, several respondents have pointed out thatcompensating balances and commitment fees have cost implications with respeet tobank loans and as support for commercial paper and urged that recognition begiven for such costs. We agree that in some instances, such items couldproperly be considered in determining the effective cost rate for short-termdebt for use in the formula. However, primarily because of measurement problems,we do not believe that specific recognition should be given in the general rule.Instead, where an individual company has a written agreement and can. support thefact that compensating balances and commitment fees are necessary in order toobtain favorable short-term financing and are not considered in its rateproceedings, we will permit an adjustment to the nominal short-term interestrates to reflect this additional cost. We believe that this approach isnecessary because of the diversity of rate treatment for these items; thecommingling and lack of identification of bank balances kept for normaloperating purposes and those used for compensating bank balance purposes; andthe frequent lack of formal agreements for required levels of compensating bankbalanoes.

Some respondents commented that the value of noninvestor sources of funds suchas accumulated deferred income taxes and contributions in aid of constructionshould be recognized in the formula. We are not adopting this suggestion sincenormally the entire balances in the accumulated deferred ±ncome taxes accountsare used to reduce rate base for cost of service purposes. [FN2] To includesuch balances in determining the AFUDC rate would result in double counting ofthe same dollars. The same reasons apply for contributions in aid ofconstruction, since under our Uniform System of Accounts such contributions arecredited directly to construction costs.A number of respondents commented that previously capitalized AFUDC should be

included in the cost base to which the AFUDC rate applies since AFUDC is a costof construction similar to labor, materials and other elements of construction.Thus, it is asserted that the compoundmethod must be recognized if AFUDC is topr-ape~ly Gompe~sate~the utility for use ~f ~unds.whi!e devoted~to~construct~on .....We agree that compounding of AFUDC is proper in theory and necessary as a matterof sound cost determination; however, we believe that a monthly compounding ofAFUDC as suggested by some respondents may result in excessive amountscapitalized since Gash outlays for interest and dividends are not normally madeon a monthly basis. We shall therefore permit oompounding but no morefrequently than semiannually.A number of respondents also indiGated that any rules issued with respect to

AFUDC should apply to Nuclear Fuel in Process of Refinement, Conversion,Enrichment and Fabrication (Account 120.1) in the same manner as ConstructionWork in Progress. We agree with these comments and will so provide.

Certain other constructive suggestions received from respondents have beenincluded in the accounting instructions for the purpose of adding clarity to theaccounting text.

We have also deleted that portion of the proposed plant instructions pertainingto computations of income taxes. We believe that these prgposed instructions




FPC 608

.(Publication page references are not available for this document.)

are not now necessary in view of our Order Nos. 530 (53 FPC 2123), 530-A (55 FPC162) and 530-B (56 FPC 739) in Docket Nos. R-424, Accounting for Premiums,Discount and Expense of Issue, Gains and Losses Debt, and Interperiod Allocationon Refunding and Reaquisition of Long-Term Debt, and Interperiod AllocationofIncome Taxes and R-446, Amendments to the Uniform System of Accounts for ClassesA, B and C Public Utilities and Licensees and Natural Gas Companies: DeferredIncome Taxes. As stated in Order No. 530- A:

The accounting for deferred income taxes prescribed in Order No. 530 wasstructured to accommodate utilities under the rate jurisdiction of the variousstate regulatory bodies that may or may not authorize deferred tax accountingfor rate purposes (See General Instruction 18). If a net of tax allowance forfunds rate is prescribed by a regulatory body in setting the rate levels ofutilities, we consider that such treatment is consistent with the intent ofOrder No. 530 and it is not necessary for utilities to set aside deferred incometaxes related to the interest component of the allowance for funds rate. In

light of this, we do not believe that it is necessary to make provision in theUniform System of Accounts to cover this matter.

The Commission finds:

(i) The notice and opportunity to participate in this rulemaking proceedingwith respect to the matters presently before this Commission through thesubmission¯ in writing, of data, views, comments and suggestions in the mannerdescribed above, are consistent and in accordance with the proceduralrequirements prescribed by 5 U.S.C. 553.

(2) The amendments to Parts 101 and 104 of the Commission’s Uniform System ofAccounts for Public Utilities and Licensees and to FPC Forms No. i, No. l-F, and

¯ No. 5 required by ~ 141.1, 141.~2, and 141.25 in Chapter I, Title 18 of the Codeof Federal Regulations, herein prescribed, are necessary and appropriate for theadministration of the Federal Power Act.

(3) The amendments to Parts 201 and 204 of .the Commission’s Uniform System ofAccounts for Natural Gas Companies, and to FPC Forms No. 2] No. 2-A, and No. ii

required-by ~ 260.1, 260~2~-.and~-2~0~3 in.Chapter .I~ Title 18 of.th~ Code of ........Federal Regulations, herein prescribed, are necessary and appropriate for theadministration of the Natural Gas Act.

(4) Since the amendments prescribed herein, which were not included in thenotice of the proceeding, are consistent with the prime purpose of the ProposedRulemaking, further notice thereof is unnecessary.

(5) Good cause exists for making the amendments to the Uniform System ofAccounts for Public Utilities and Licensees and Natural Gas Companies orderedherein effective on January i, 1977, and the amendments to FPC Forms No. I, No.I-F, No. 2, No. 2-F, No. 5, and No. II ordered herein, effective for thereporting year 1977.

The Commission, acting pursuant to the provisions of the Federal Power Act, asamended, particularly Sections 3, 4, 301, 304, 308, 309; and 311 (41 Stat. 1063,1065; 49 Stat. 838, 83-9, 854, 855, 858, 859; 16 U.S.C. 796, 797, 825, 825c, 825g¯ 825h, 825j) and of the Natural Gas Act, as amended, particularly Sections 8,i0, and 16 (52 Star. 825, 826, 830; 15 U.S.C. 717g, 717i, 717o), orders:




FP¢ 608(Publication page references are not avail~ble for this document.)

(A) Effective January i, 1977, the Commission’s Uniform System of Accounts forClass A and Class B Public Utilities and Licensees in Part I01, Chapter I, Title18 of the Code of Federa! Regulations is amended as follows:

(i)~ The General Instructions are amended by revising paragraph ’I’ ofInstruction ’17. Long-Term Debt: Premium, Discount and Expense, and Gain ofLoss on Reacquisition.’ As amended, this portion of General Instruction 17reads:

GENERAL INsTRUcTIONS

****************************************17. Long-Term Debt: Premium, Discount and Expense, and Gain or Loss on

Reacquisition.

I. Premium, discount, or expense on debt shall not be included as anelement in the cost of construction or acquisition of property (tangible orintangible), ~ under the provisions of account 432, Allowance for BorrowedFUnds Used During Construction-Credit.

(2) Subparagraph ’(17) Allowance for Funds Used During Construction’ ofElectric Plant Instruction ’3. Components of Construction Cost.’ is amended byrevising the first sentence of the paragraph and by adding two new paragraphs(a) and (b) i~lediately following the first paragraph. As amended, subparagraph(17) reads:

ELECTRIC PLANT INSTRUCTIONS

3. Components of Construction Cost.

(17) ’Allowance for funds used during construotion’ incl~ues the net costfor the period of construction of borrowed funds used for construction purposeso&~d a tea,son-able rate on other funds when so used, -not-to e~ceed~ wit.ho~t pr~or~approval of the~ Contmission, allowances computed ~in accordance with the formulaprescribed in paragraph (a) below. No allowance for funds used duringconstruction charges shall be included in these accounts upon expenditures forconstruction projects which have been abandoned.

(a) The formula and elements fo~ the computation of the allowance for fundsused during construction shall be:

A subi = s(S/W) + d(D/D + P + C) (i - S/W)A sube~= [i - S/W] [p(P/D + P + C) + c(C/m + P + C)]

A subi = Gross allowance for borrowed funds used .during construction rateA sube = Allowance for other funds used during construction rateS = Average short-term debts = Short-term debt interest rateD = Long-term debtd = long-term debt interest rateP = Preferred stock





Page 7

p~= Preferred stock cost rateC = Common equityc ~ Common equity cost rateW = Average balance in construction work in progress plus nuclear fuel in

process of refinement, conversion, enrichment and fabrication.(4) The rates shall be determined annually.=~h_~_.~alan

debt, preferrg~_.stoc~_.9~Q~D._.~q~.~.~ shall be the actual book balances as ofThe cost rates for long-term debt and preferred

stock shall be the weighted average cost determined in the manner indicated in35.13 of the Con~nission’s Regulations under the Federal Power Act. The costrate for contmon equity shall be the rate granted common equity in the last rateproceeding before the ratemaking body having primary rate jurisdict.ions. Ifsuch cost rate is not available, the average rate actually earned during thepreceding 3 years shall be used. The short-term debt balances and related costand the average balance for construction work in progress plus nuclear fuel inprocess of refinement, conversion, enrichment, and fabrication shall be

NOTE: * * *(3) The Chart of Income Accounts is amended by revising the title of accoun~

’419.1, Allowance for Funds Used During Construction,’ to read ’419.1, Allowancefor Other Funds Used During Construction;’ by adding a new account 432,Allowance for Borrowed Funds Used During Construction-Credit, immediatelyfollowing account ’431, Other Interest Expense’ and revising the sub-totalcaption ’Total Interest Charges’ to read ’Net Interest Charges.’ As amended,the Chart of Income Accounts~ reads:

INCOME ACCOUNTS

(Chart of Accounts)

¯ 2. Other Incom@ and Deductions

A. Other Income

419.1 Allowance for other funds used during construction.******************************

3. Interest Charges

432 Allowance for borrowed funds used during construction-Credit.Net interest charges

(4) The text of the Income Accounts is amended by revising the title and text





Page 8

of accounz ’419.], Allowance for Funds Used During Construction,’ and by addinga new account 432, Allowance for Borrowed Funds Used During Construction-Credit, immediately following accounn ’431, Other Inzeres5 Expense.’ Asamended, these portions of the ~exn of the Income Accounts reads:

INCOME ACCOUNTS

2. Other Income and Deductions

419.1 Allowance for other funds used durinq construction.This accounz shall include concurren< credits for allowance for other funds

used during construction, noz zo exceed amounts computed in accordance with theformula prescribed in Electric Plant Instruction 3(17).

3. Interes~ Charges

432 Allowance for borrowed funds used during construction-Credit.This account shall include concurrent cr~edits for allowance for borrowed

funds used during construciion, not to exceed amounts computed in accordancewith the formula prescribed in Electric Plant Instruction 3(17).****************************************

(By. Effective January I, 1977, the Commission’s Uniform System of Accounts forClass C and Class D Public Utilities and Licensees in Part 104, Chapter I, Title18 of the Code of Federal Regulations is amended as follows:

(I) The General Instructions are amended by revising paragraph ’I’ ofInstruction ’15. Long-Term Debt: Premium, Discount and Expense, and Gain orLoss on Reacquisition.’ As amended, this portion of General Instruction 15reads~ ............................. .........

GENERAL INSTRUCTIONS

15. Long-Term Debt: Premium, Discount and Expense, and Gain or Loss onReacquisition.******************************************

I. Premium, discount, or expense on debt shall not be included as anelement in the cost of construction or acquisition of property (tangible orintangible), except under the provisions of account 432, Allowance for BorrowedFunds Used During Construction-Credit.

(2) Electric Plant Instruction ’2. Components of Construction Cost.’ isamended by revising the first paragraph and lettering it ’A.’ and by adding twonew paragraphs B. and C. immediately following the first paragraph. As amended,




57 FPC 608(Pt~blication page references

Instruction 2 reads:

are not available for this document.)

Page 9

ELECTRIC PLANT INSTRUCTIONS

2. Components of Construction Cost.A.. The cost of construction of property chargeable to the electric plant

accounts shall include, where applicable, the cost of labor; materials andsupplies; transportation; work done by others for the utility; injuries anddamages incurred in construction work; privileges and permits; special machineservice; allowance for funds used during construction, not to exceed withoutprior approva! of the Commission amounts computed in accordance with the formulaprescribed in paragraph B below; and such portion of general engineering, ¯administrative salaries and expenses, insurance, taxes, and other analogousitems as may be properly includible in construction costs.

B. The formula and elements for computation of the allowance for funds usedduring construction shall be:

A subi = s(S/W)~+ d(D/D + P + C) (I - S/W)A sube = [i - S/W] [p(P/D + P + C) + c(C/D + P + C)]

A subi = Gross allowance for borrowed funds used during construction rateA sube = Allowance for other funds used during construction rateS = Average short-term debts = Short-term debt interest rateD = Long-term debtd = Long-term debt interest rateP = Preferred stockp = Preferred stock cost rateC = Common equityc = Common equity cost rateW = Average balance in construction work in progress plus nuclear fuel in

process of refinement, conversion, enrichment and fabricationC. The rates shall be determined annually. The balances for long-term

debt, preferred stoc~ and.common equity shall be the actual book balances as of-..the end of the prior year. The cost rates .for long-term debt and preferredstock shall be the weighted average cost determined in the manner indicated in §35.13 of the Commission’s Regulations under the Federal Power Act. The costrate for common equity shall be the rate granted common equity in the last rateproceeding before the ratemaking body having primary rate jurisdiction. If suchsoct rate is not available, the average rate actually earned during thepreceding 3 years shall be used. The short-term debt balances and related costand the average balance for construction work in progress plus unclear fuel inprocess of refinement, conversion, enrichment, and fabrication shall beestimated for the current year with with appropriate adjustments as actual databecomes available.

(3) The Chart of Income Accounts is amended by revising the title of account’419.1, Allowance for Funds Used During Construction,’ to read ’419.1, Allowancefor Other Funds Used During Construction’ and by adding a new account 432,Allowance for Borrowed Funds Used During Construction--Credit immediately




Page i057 FPC 608(Publication page references are not available for this document.)

following account ’431, Other Interest Expense’ and revising the subtotalcaption ’Total Interest Charges’ to read ’Net Interest Charges.’ As amended,the Chart of Income Accounts reads:

INCOME ACCOUNTS

(Chart of Accounts)


A. Other Income

419.1 Allowance for other funds used during construction.

3. Interest Charges

432 Allowance for borrowed funds used during constructlon--Credit.Ne< interest charges

(4) The texn of zhe Income Accounts is amended by revislng the title and nexnof accounn ’419.1, Allowance for Funds Used During Construction,’ and by addinga new accounn 432, Allowance for Borrowed Funds Used During Construction--Credit immediately following accounn ’432, Other Interest Expense.’ As amended,these porzlons of the nexn of the Income Accounzs reads:

INCOME ACCOUNTS


419.1 Allowace for other funds used during construction.This account shall include concurrent credits for allowance for other funds

used during construction, not to exceed amounts computed in accordance with theformula prescribed in Electric Plant Instruction 2. No allowance for funds usedduring construction shall be capitalized on plant which is completed and readyfor service.

3. Interest Charges

432 Allowance for borrowed funds used during construction--Credit.





Page Ii

This account shall include concurrent credits for allowance for borrowedfunds used during construction, not to exceed amounts computed in accordancewith the formula prescribed in Electric Plant Instruction 2. No allowance forfunds used during construction shall be capitalized on plant which is completedand ready for service.

(C) Effective January I, 1977, the Commission’s Uniform system of Accounts forClass A and Class B Natural Gas Companies in Part 201, Chapter I, Title 18 ofthe Code of Federal Regulations is amended as follows:

(I) The General Instructions are amended by revising paragraph ’I’ ofInstruction ’17. Long-Term Debt: Premium, Discount and Expense, and Gain orLoss on Reacquisition.’ As .amended, this portion of General Instruction 17reads :


17. Long-Term Debt: Premium, Discount and Expense, and Gain or Loss onReacquisition. .****************************************

I. Premium, discount, or expense on debt shall not be included as anelement in the cost of construction or acquisition of property (tangible orintangible), except under the provisions of account 432, Allowance for BorrowedFunds Used During Construction--Credit.

(2) Subparagraph ’(17) Allowance for Funds Used During Construction’ of GasPlant Instruction ’3. Components of Construction Cost.’ is amended by revisingthe present paragraph, and immediately following the present paragraph, addingtwo new paragraphs (a) and (b). As amended, subparagraph (17) reads:

GAS PLANT INSTRUCTIONS

3. Components of Construction Cost.****************************************

(17) ’Allowance for funds used during construction’ fncludes the net costfor the period of construction of borrowed funds used for construction purposesand a reasonable rate on other funds when so used, not to exceed withodt priorapproval of the Commission al!owances computed in accordance with the formulaprescribed in paragraph (a) below, except when such other funds are used forexploration and development of leases acquired after October 7, 1969, noallowance on such other funds shall be included in these accounts. No allowancefor funds used during construction charges shall be included in these accountsupon expenditures for construction projects which have been abandoned.

(a) The formula and elements for the computation of the allowance for fundsused during construction shall be:

A subi = s(S/W) + d(D/m + P + C) (i + S/W)A sube = [i S/W] [p(P/D + P + C) + c(C/D + P + C)]

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57 FPC 608(P~blication page references are not available for this document.)

Page 12

subi = Gross allowance for borrowed funds used during construczlon ra~esube = Allowance for other funds used during, conssruction razeA

S = Average short-term debts Short-term debt interest razeD = Long-zerm debtd =Long-zerm debt interest ra~eP = Preferred stockp = Preferred stock cost razeC = Common equityc = Common equity cost rateW = Average balance in construction work in progress

(b) The rates shall be determined annually. The balances for long-termdebt, preferred stock and common equity shall be the actual book balances as ofthe end of the prior year. The cost rates for long-term debt and preferredstock shal! be the weighted average cost determined in the manner indicated in154.63 of the Com~ission’s Regulations under the Natura~ Gas Act. The cost ratefor common equity shall be the rate granted common equity in the last rateproceeding before the ratemaking body having primary rate jurisdiction. If .suchcost rate is not available, the average rate actually earned during thepreceding 3 years shall be used. The short-term debt balances and related costand the average balance for construction work in progress shall beestimated forthe current year with appropriate adjustments as actua! data becomes available.

NOTE: * * *(3) The Chart of Income Accounts is amended by revising the title of account

’419.1, Allowance for Funds Used During Construction,’ to read ’419.1, Allowancefor Other Funds Used During Construction’ and by adding a new-account 432,Allowance for Borrowed Funds Used During Construction--Credit, immediatelyfollowing account ’431, Other Interest Expense’ and revising the sub-totalcaption ’Total Interest Charges’ to read ’Net Interest Charges.’ As amended,the Chart of Income Accounts reads:

INCOME AccOUNTS

(Chart of Accounts)


A. Other Income

419.1 Allowance for the funds used during construction.

3. Interest Charges

**********************************432 Allowance for borrowed funds used during construction--Credit.




57 FPC 608(Publication page references are not available for this docuraent.)

Page 13

Net interest charges.

(4) The text of the Income Accounts is amended by revising the title and textof account ’419.1, Allowance for Funds Used During Construction.’ and by addinga new account 432, Allowance for Borrowed Funds Used During ConstructiOn--Credit, immediately following account ’431, Other Interest Expense.’ Asamended, these portions of the text of the Income Accounts read: ~.

INCOME ACCOUNTS


419~I Allowance for other funds used during construction.This account shall include concurrent credits for allowance for other funds

used during construction, not to exceed amounts computed in accordance with theformula prescribed in Gas Plant Instruction 3(17).

Interest Charges

432 Allowance for borrowed funds used during construction--Credit.This account shall include concurrent credits for allowance for ~borrowed

funds used during construction, not to exceed amounts computed in accordancewith the formula prescribed in Gas Plant Instruction 3(17).*****************************************(D) Effective January I, 1977, the Commission’s Uniform System of Accounts for

Class C and Class D Natural Gas Companies in Part 204, Chapter I, Title 18 ofthe Code of Federa! Regulations is amended as follows:

(i)’ The General Instructions are amended by revising paragraph ’I’ ofInstruction ’15. Long-Term Debt: Premium, Discount and Expense, and Gain orLoss on Reacquisition.’ As amended, this portion of General Instruction 15reads:


15. Long-Term Debt: Premium, Discount and Expense, and Gain or Loss onReacquisition.****************************************

I. Premium, discount, or expense on debt shall not be included as anelement in the cost of construction or acquisition of property (tangible orintangible), except under the provisions of account 432, Allowance for BorrowedFunds Used During Construction--Credit.





Page 14

(2) Amend Gas Plant Instruction ’2. Components of Construction Cost.’ byrevising the first paragraph and lettering it ’A.’ and by adding two newparagraphs B. and C. immediately following the first paragraph. As amended,Instruction 2 reads:

GAS PLANT INSTRUCTIONS

2. Components of Construction Cost.A. The cost of construction of property chargeable to the gas plant

accounts shall include, where applicable, fees for construction certificateapplications paid after grant of certificate, the cost of labor, materials andsupplies, transportation, work done by others for the utility, injuries anddamages incurred in. construction, privileges and permits, special machineservice, allowance for funds used during construction, not to exceed withoutprior approval of the Commission amounts computed in accordance with the formulaprescribed in paragraph B below, training costs and such portion of generalengineer£ng, administrative salaries ~and expenses, insurance, taxes, and otheranalogous items as may be properly includible in construction costs. (SeeOperating Expense Instruction 3.) When the utility employs its own funds inexploration and development on leases acquired after October 7, 1969, noa!lowance for funds used during construction on such funds shall be included inthese accounts.

B. The formula and elements for the computation of the allowance for fundsused during construction shal! be:

A subi = s(S/W) + d(D/D + P + C) (I - S/W)A sube = [I - S/W] [p(P/m + P + C) + c(C/D + P + C)]

A subi = Gross allowance for Borrowed funds used during construction rateA sube = Allowance fo9 other {unds used during construction rateS = Average short-term debts = Short-term debt interest rateD = Long-term debtd = Long-term. debt .interest~ra~¯ ~ ........P = Preferred stockp = Preferred stock cost ra~eC = Common equityc= Common equity cost rateW = Average balance in construction work in progress

C. The rates shall be determined annually. The balances for long-termdebt, preferred stock and common equity shall be the actual book balances as ofthe end of the prior year. The cost rates for long-term debt and preferredstock shall be the weighted average cost determined in the manner indicated in §154.63 of the Commission’s Regulations under the Natural Gas Act. The cost ratefor common equity shall be the rate granted common equity in the last rateproceeding before the ratemaking body having primary rate jurisdiction. If suchcost rate is not available, the average rate actually earned during thepreceding 3 years shall be used. The short-term debt balances and related costand the average balance for construction work in progress shall be estimated for




57 FPC 608(Publication page references are not available for this doc%%ment.)

Page 15

the’current year with appropriate adjustments as actual data becomes available.(3) The Chart of Income Accounts is amended by revising the title of account

’419.1, Allowance for Funds Used During Construction,’ to read ’419.1, Allowancefor Other Funds Used During Construction’ and by adding a new account 432,Allowance for Borrowed Funds Used During Construction--Credit, immediatelyfollowing account ’431, Other Interest Expense’ and revising the sub-totalcaption ’Total Interest Charges’ to read ’Net Inzeres< Charges.’ As amended,the Chart of Income Accounts reads:

INCOME ACCOUNTS

(Chart of Accounts)


A. Other Income

419.1 Allowance for other funds used duringconszruction.

3. Interest Charges

432 Allowance for borrowed funds used during construction--Credit.Net interest charges.

(4) The text of the Income Accounts is amended by revising the title and textof account ’419.1, Allowance for Funds Used During Construction," and by addinga new account 432, Allowance for Borrowed Funds Used During Construction--C~edit,~-i~ediately following account ’431~.©ther. Interest Expense..-~ As .........amended, these portions of the text of the Income Accounts read:

INCOME ACCOUNTS


419.1 Allowance for other funds used during construction.This account shall include concurrent credits for allowance for other funds

used during construction, not to exceed amounts computed in accordance with theformula prescribed in Gas Plant Instruction 2. No allowance for funds usedduring construction shall be capitalized on plant which is completed and readyfor service.




57 FPC 608(Publication page references are not available for this docuxaent.)

Page 16

3. Interest Charges

432 Allowance for borrowed funds used during construction--Credit.This account shall include concurrent credits ~for allowance for borrowed

funds used during construction, not to exceed amounts computed in accordancewith the formula prescribed in Gas Plant Instruction 2. No allowance for funds~ed ~during construction shall be capitalized on plant which is completed andready for service.*****************************************(E) Effective for the reporting year 1977, certain schedule pages of FPC Form

No. i, Annual Report for Electric Utilities, Licensees and Others (Class A andClass B), prescribed by § 141.1, Chapter I, Title 18 of the Code of FederalRegulations are emended, all as set out in Attachments B [FN3] ~nd C [FN4]hereto.

(F) Effective for the reporting year 1977, certain schedule pages of FPC FormNo. 2, Annual Report for Natural Gas Companies (Class A and Class B), prescribedby § 260~I, Chapter I, Title 18 of the Code of Federal Regulations are amended,all as set out in Attachments B and D [FN5] hereto.

(G) Effective for the reporting year 1977, certain schedule pages of FPC For~No. l-F, Annual Report for Public Utilities and Licensees (Class C and Class D),prescribed by § 141.2, Chapter I, Title 18 of the Code of Federal Regulationsare amended, all as set out in Attachment E [FN6] hereto.

(H) Effective for the reporting year 1977, certain schedule pages of FPC FormNo. 2-A, Annual Report for Natural Gas Companies (Class C and Class D),prescribed by § 260.2, Chapter I, Title 18 of the Code of Federal Regulationsare amended, all as set out in Attachment C hereto.

(I) Effective for the reporting year 1977, certain schedulepages of FPC FormNo. 5, Monthly Statement of Electric Operating Revenue and Income, prescribed by§ 141.25, Chapter I, Title 18 of the Code of Federal Regulations is amended, allas set out in Attachment F [FN7] hereto.

(J) Effective for the reporting year1977, certain schedule pages of FPC FormNo-. ll,~Natural Gas ~Pipeline Company. Monthly Statement, prescribed~by~2601.3~Chapter I, Title 18 of the Code of Federal Regulations is amended, all as setout in.Attac.hment G [FN8] hereto.

(K) The Secretary shall cause prompt publication of this Order to be made inthe Federal Register.

ATTACHMENT A

Respondents RM75-27

Respondent

Accounting Firms

Arthur [FN9] Anderson & Co.Orrin [FN9] T. Colby, Jr.





Page 17

Coopers [FN9[ & LybrandHaskins & SellsPrice [FN9] Waterhouse & Co.

Associations

American Gas Association (AGA)Edison [FN9] Electric Institute (EEI)Interszane Natura! Gas Association of America INGAA)

Electric Utility Companies

Alabama [FN9] Power Co.American Electric Power Service Corp.Appalachian Power Co.£ndiana & Michigan Electric Co.Kentucky Pcwer Co.Kingsporz Power Co.Michigan Power Co.Ohio Power Co.Wheeling Electric Co.Arkansas [FN9] Power & Light Co.Carolina Power.& Light Co.Cincinnati Gas & Electric Co.Lawrenceburg Gas Company, TheUnion Light, Heat and Power Co., TheWest Harrison Gas & Electric Co., TheCleveland [FN9] Electric Illuminating Co.,Columbus and Southern Ohio Electric Co.Commonwealth EdisonConsolidated Edison Co. of New York, Inc.Consumers Power Co.Day~ [FN9] Power and.Licht Co., .TheDetroit [FN9] Edison Co., TheDuke Power Co.Florida Power & Light Co.F!orida [FN9] Power Corp.General Public Utilities Corp.Jersey Central Power & Limht Co.Metropolitan Edison Co.Pennsylvania Electric Co.Georgia Power Co.Gulf [FN9] Power Co.Gulf [FN9] States Utilities Co.Idaho [FN9[ Power Co.Illinois [FN9] Power Co.Iowa-Illinois [FN9~ Gas and Electkic Co.Iowa [FN9] Power and Light Co.

The




57 FPC 608(Publication page references are not available for this document.

Page 18

Iowa Public Service Co.Kansas City Power & Light Co.Kansas Gas and Electric Co.Long [FN9] Island Lighting Co.Middle [FN9] South Services, Inc.Arkansas-Missouri Power Co.Arkansas Power & Light Co.Louisana Power & Light Co.Mississippi Power & Light Co.New Orleans Public Service, Inc.Minnesota Power & Light Co.New [FN9] England Electric SystemGranite State Electric Co.Massachusetts Electric Co.Narragansett Electric Co., TheNew England Power Co.Niagara [FN9] Mohawk Power Corp.Northeast [FNg] UtilitiesConnecticut Light & Power Co., TheHartford Electric L~ght Co.’, TheHolyoke Power & Electric Co.Holyoke Water Power Co.W@stern Massachusetts Electric Co.Northern [FNg] States Power Co.Ohio EdisDn Co.Pennsylvania Power Co.Otter [FN9] Tail Power Co.Pacific [FNg] Gas and Electric Co.Pannsylvania [FN9] Power & Light Co.Philadelphia Electric Co.Portland [FN9] General Electric Co.Public [FN9] Service Co. of Indiana,¯ Public~ Servi~ Co. of New Mex~i~uPublic Service Co. of OklahomaPublic Service Electric and Gas Cc.Puget Sound Power & Light Co.Rochester Gas and Electric Corp.San [FN9] Diego Gas & Electric Co.Southern California Edison Co.South [FN9] Carolina Electric & GasTampa Electric Co.Toledo [FN9] Edison Co., TheTucson Gas & Electric Co.Union Electric Co.Utah [FN9] Power & Light Co.Washington Water Power Co., TheWest [FN9] Texas Utilities Co.Wisconsin [FN9] Power & Light Co.

Inc.

Co.

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Natural Gas Companies

Columbia Gas Transmission Corp.Consolidated Gas Supply Corp.Consolidated System LNG Co.E1 Paso Natural Gas Co.Natural Gas Pipeline Co. of AmericaNorthern [FN9] Natural Gas Co.Panhandle Eastern Pipe Line Co.Trunkline Gas Co.Texas Eastern Transmission Corp.

State Regulatory Commissions

Florida [FN9] Public Service CommissionPublic Service Commission of the State of New York

Page 19

Rural Electric Cooperative Associations

National Rural Electric Cooperative AssociatlonPublic [FN9] SyszemsSouthern Engineering Company

Others

First National City BankDan L. NeidlingerStone & Webster Managemenz Consultants, Inc.FN* Published in the Federal Register on February 15, 1977 (42 F.R. 1961).

Order issued April I, 1977 granting application for rehearing for purpose offurther consideration, unreported. Order No. 561-A issued August i, 1977denying application for rehearing and clarifying prior order, 59 FPC 1340

.... [Editor’s note: ~ o~etition fo~,roview.file~.on Sep~embe~.~28~, J~-97.~.sub nom.: Jersey.Central Power & Light Co., et al. v. F.P.C:, in CADC No. 77-1883.] Order issuedJanuary 20, 1978 clarifying Order Nos. 561 and .561-A, 2 FERC ~ .... .

FNI We also recognize that interest coverages for some utilities may beincreased if in their coverage computations they use net interest charges sincethis amount will be reduced upon application of the proposed rule.

FN2 There is one category of accumulated deferred taxes which is not used toreduce rate base. Under our ratemaking practices the balances of Account 281,Accumulated deferred income tax~s-Accelerated amortization, are included in thecapitalization used for rate of return purposes at zero cost. The balances inthese accounts, however, are relatively small and the effect on theAFUDC rateif taken into consideration would be negligible.

FN3 Omitted in printing.FN4 Omitted in printing.FN5 Omitted in printing.FN6 Omitted in printing.




57 FPC 608(Publication page references are not available for this document,)

FN7 Omitted in printing.FN8 Omitted in printing.FN9 Not filed within the time prescribed.

FEDERAL POWER COMMISSION57 FPC 608, 1977 WL 17150 (F.P.C.)END OF DOCUMENT

Page 2O




Citation Search Result59 FPC 13401977 WL 16744 (F.P.C.)(Cite as: 59 F.P.C. 1340)

Rank 46 of 51

Page 21

9atabase£EN-FERC

AMENDMENTS TO UNIFORM SYSTEM OF ACCOUNTS FOR PUBLIC UTILITIES ANDLICENSEES AND FOR NATURAL GAS COMPANIES (CLASSES A, B, C AND D) TO PROVIDE FOR

THE DETERMINATION OF RATE FOR COMPUTING THE ALLOWANCE FOR FUNDS USED DURINGCONSTRUCTION AND REVISION OF CERTAIN SCHEDULE PAGES OF FPC REPORTS,

DOCKET NO. RM75-27

ORDER NO. 561-A

ORDER DENYING APPLICATIONS FOR REHEARING AND CLARIFYING PRIOR ORDER

August i, 1977"

"1340 Before Commissioners: Richard L. Dunham, Chairman; Don S. Smith and JohnH. HollomaD III.

On March 4, 1977, E! Paso Natural Gas Company (El Paso), Public Systems [FNI],three bulk power suppliers for rural electric cooperatives (Oglethorp) [FN2] andeight investor-owned public utilities (Private Group) [FN3] filed Applicationsfor Rehearing of our Order No. 561, issued Eebruary 2, 1977, in Docket No.RM75-27, 57 FPC 608. On March 7, 1977, Pennsylvania Power & Light Company(PP&L) filed a separate Application for Rehearing. On April I, 1977, an orderwas issued granting application for rehearing by the aforementioned petitionersfor the purpose of further consideration of Order No. 561. On April 18, 1977,pursuant to Section 1.34(d) of the Commission’s Rules of Practice and Procedure,the Public Service Commission of the State of New York (New York) and thePrivate Group filed responses to Applications for Rehearing filed by the PrivateGroup and Public Systems, respectively.

Short-Term Debt

E1 Paso’s application stated that it fully supported the Commission’s objectivein the instant rulemaking proceeding of providing adequate compensation forfunds devoted to construction but believed that the formulas devised by theCommission and promulgated pursuant to Order No. 561 fall short of accomplishingthis objective. E1 Paso submits that the approach adopted by the Commission isgrounded upon two erroneous assumptions, i.e. (i) that short-term debt is thefirst source of funds for construction purposes, and (ii) that short-term debtis used exclusively for construction. E1 Paso proposed that instead of theformula adopted by the Commission that the rate for AFUDC be expressed asfollows:

"1341 R = d(D/D + P + C) + p(P/D + P + C) + c(C/D + P + C)In hhis formula R represents the AFUDC rate and the other symbols have the same




FPC 1340(Cite as: 59 F.P.C. 1340, "1341)

meaning as defined in Order No. 561 except that D would equal the sum of long-term and short-term debt and d would equal the weighted average interest ratefor D. E! Paso states that this formula is grounded upon the more realisticassumption that construction work in progress is financed by funds providedaccording to the pro rata capitalization of the company, including short-termdebt, if any. In the event, however,, that the Co~mmission chooses to retain theformula set forth in Order No. 561, E1 Paso requests clarification in caseswhere short-term debt exceeds construction work in progress to ensure thatnegative AFUDC rates do not result.

Public Systems states that the Commission correctly concludes that short-termdebt is the primary source of funds for the construction of new utility plantand the procedures for the calculation of AFUDC reflect this fact. However,Public Systems expressed concern over the statement in Order No. 561 that theAFUDC method established was not fob the purposes of establishing a method forallocating short-term interest cost for the purpose of a rate proceeding. Theybelieve that such statement may be interpreted as an invitation to include thecost of construction related short-term borrowings in the development of AFUDCand to recognize the same costs in the development of the allowed return in rateproceedings. Public Systems also objects to any possible recognition of costsassociated with bank or other borrowings, such as compensating bank balances, indetermining short-term debt cost. They believe that recognition of such costsshould be sanctioned, if at all, only in general rate proceedings after ahearing on the record.

PP&L also disagrees with the Commission’s premise in Order No. 561 that allshort-term debt should be allocated to financing construction work in progress.PP&L states that there are many instances when a utility can specificallyidentifythe utilization of short-term debt for purposes other than financingconstruction work in progress and in such cases, it would be erroneous toinclude this debt in the AFUDC computation.As we stated in Order No. 561, it is generally impossible to specifically trace

the source of funds used for various corporate purposes and it was not thepurpose of the proposed rule to do so. We recognize that short-term debt is asource of funds that can be used’fo~ many corporate purposes other than -construction. However, short-term debt cost is a valid cost of conductingutility operations and a mechanism for the recovery of such cost should beprovided for with£n the regulatory framework. Recovery of capital costs isusually provided for through the rate of return allowance in a general rateproceeding. However, in a typical rate case situation, short-term debt costdoes not lend itself to reasonable measurement for use in setting future ratessince, as E1 Paso graphically illustrated in the Appendix to its application,"1342 the amount of short-term debt that a company has outstanding can fluctuatewidely over short periods of time. In addition, the interest rate for short-term debt often changes at frequent intervals. On the other hand, the cost ofshort-term debt can be effectively measured and capitalized for subsequentrecovery (through depreciation charges in rates) since under our formula thebalances and rates for the forthcoming year are estimated annually, withappropriate adjustments to the amounts capitalized if the estimates used are not

reasonably reflective of actual experience. Therefore, we do not believe that we




59FPC 1340(Cite as: 59 F.P.C. 1340, "1342)

Page 23

should modify Order No. 561 with respect to the weight given short-term debt inthe formula.

E1 Paso’s point on possible negative AFUDC rates in situations where short-term debt exceeds construction work in progress is well taken. We believe thatthis matter can best be clarified b~atinq herein that if short-term debtbalances exceed construction. _~or~ in pr~ regulus nuc_ ~ear fuel in ~rocess ofrefinement, conversion, enrichment and fabrication the maximum total AFUDC rateto be utilized will be the weighted average short-term debt rate. In instanceswhere this occurs, the entire credit for AFUDC will be recorded in Account~J32,Allowa~ce for borrowed funds used during constructi0n--Credit.

We do not believe that Public System’s concerns are well founded with regard tothe inclusion of short-term debt for rate of return purposes or the potentialrecognition, in certain instances of short-term debt costs arising from suchitems as compensating balances. Order No. 561 neither changes the Commission’sIpolicy with respect to treatment of short-term debt in capitalization used for~rate of return purposes nor does it grant blanket.approval for recognition ofcompensating balances and commitment fees in costing short-term debt. Theburden of proof is upon the companies to justify such items before they will be1permitted.

State Commission Rate Determinations

Both Public Systems and Oglet~orp object to the provision in Order No. 561 thatthe cost rate to be used for common equity be the rate granted common equity inthe l~st rate proceeding before the body having primary rate jurisdiction~or, ifsuch rate is not available, the average rate actually earned during thepreceding three years. They believe-that the return on equity rate should bebased upon Determinations of the Federal Power Commission, whether the FPC hasprimary rate jurisdiction or not. Public Systems and Oglethorp believe that theapproach adopted by the Commission is an unjustified abdication of statutoryresponsibility. On the other hand, Private Group urges that Order No. 561 beamended to provide that, if a state ratemaking agency having primary rate

¯ ju~-isdi~tion over an electric utility has prescribed a method of. determining orapplying an AFUDC rate, such electric utility may use such State Commission-directed rate rather than the rate developed under the formulain Order 561.

¯ 1343 In its response to the application for rehearing filed by Public Systems,the Private Group stated the following:

Order No. 561 is designed to provide an orderly method for acgrual of AFUDCmonth-by-month during the on-g~ing operations of a public utility. For the mostpart, the facilities constructed by an electric utility cannot be segregated asbetween those which will be emp!oyed solely for retail service and those whichwill be employed solely for wholesale service; instead, al!ocation proceduresfor joint use facilities ~re required and appropriate methods of allocation havebeen developed and are routinely applied. Under those circumptances, theutility must have a single AFUDC rate to apply to facilities under constructionwhich will ultimately serve both groups of customers. A reasonable recognitionof, and accommodation to, the Federa!- State relationship involves the use of acost rate for common.equity which is equal to that last approved by the body

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59 FPC 1340(Cite as: 59 E.P.C. 1340, "1343)

Page 24

having prlmary rane 3urisdiction.We fully agree with the above response by the Private Group with respect to the

cost rate for equity funds. We believe that this argument is also supportive ofthe Commission’s adoption of a uniform method for all jurisdictional companiesto follow so that a single rate is developed for each company. Additionally,since the financial statements of electric utilities and natural gas companiesare used by government agencies, investors, the general public, and others forpurposes other than setting rates, it is important that a uniform method beused. This is especially important in an area such as AFUDC which has such amaterial impact on the earnings and-cost determinations of utilities. We shalltherefore deny rehearing on this point.

The Relocation of AFUDC in the Interest Charges Section of the Income Statement

The Private Group and PP&L urged that Order No] 561 be revised to eliminate theprovision that directs the relocation of the allowance for borrowed funds as acredit to the interest charge section of the income statement. New York in itsresponse to application for rehearing filed by Private Group supported this ~position. These parties argue that the relocation required by Order No. 561 islikely to have an adverse ~ffect on the ability to finance both debt andpreferred stock securities due to coverage test requirements included inmortgage indentures and corporate charters. PP&L also questions whether therelocation of a portion of AFUDC as a reduction of interest charges wil! betterinform readers of the financial statements as to the nature of the capitalizedal!owance for borrowed funds as stated in Order No. 561. They argue that suchreclassification may in fact mislead readers of financial statements if suchamount is considered a reduction of the actual amount of interest~a company mustpay.

We are unpersuaded by these arguments that we should modify Order No. 561 withrespect to the location of the interest portion of AFUDC in the "1344 incomestatement. We purposely did not require that the amount of interest charged tothe income statement be shown net of interest capitalized but instead required~hat’the g~oss~interes’t charge~"be ~shown in the income’statement with-a" separate"line item for the capitalized allowance for borrowed funds. This enables _oreaders of financigl statements to be informed as to the total interestliability incurred for the year as well as to any lesser amount of interestentering into the determination of net income for the year.. We continue tobelieve that the readers of the financial statements will be better informedwith this form of accounting disc!osure than other suggested methods.Furthermore, the change in the location on the income statement for theallowance for intere~ capitali~zed does not in itself change either the natureof the item or the degree of protection afforded security holders by earnings ofa utility.

Net-of-tax AFUDC Rate

Public Systems objects to the normalization of income tax benefits ofconstruction interest through the use of a net-of-tax AFUDC rate and asks that




59 FPC 1340(Cite as: 59 F.P.C. 1340, "1344)

Page 25

Order No. 561 be revised to prohibit this practice.Public Systems’ arguments are misplaced. The proposed plant instructions

pertaining to computation of income taxes were deleted when the Commissionadopted Order No. 561 because these matters were previously spoken to in theCommission’s Order Nos. 530 (53 FPC 2123), 530-A (55 FPC 162) and 530- B (56 FPC44) in Docket Nos. R-424 and R-446. These orders are currently under review bythe D.C. Circuit (Public Systems, et al. v. F.P.C., CADC Nos. 46-1609, 76-1830.)[FN4]

Other Matters

Private Group states in their application that in order for the AFUDC rate tobe fully compensatory, estimates of weighted average embedded long-term debt andpreferred stock costs as they are expected to exist during the current yearshould be used rather than the effective weighted average cost of the long-termdebt and preferred stock at the end of the prior year as required by Order No.561.

Private Group also argues that compounding of A~UDC should be permitted monthlyrather than semi-annually, since utility accounting is on an accrual basis, if,however, the Conunission considers the timing of cash outlays for interest anddividend to be relevant, Private Group argues that quarterly compounding wouldbe more appropriate than semi-annual compounding since dividends on preferredand common stock and interest on short-term debt are almost invariably paidquarterly, and these items account in the aggregate for more than half of theAFUDC accrual. The ~*1345 remainder of the accrual relates to long-term d@btwhich is normally paid semi-annually.

Public Systems objects to the provisions of Order No. 561 which indicate thatamounts capitalized for AFUDC for the year will not be required to be adjustedif the gross AFUDC rate actually used for the year does not exceed by more than25 basis points the rate that would be derived from the formula.by use of actualthirteen monthly balances of construction work in progress and the actualweighted average cost and balances for short-term debt outstanding during the

..... year.- Public System-argues that this piovi~on~ creates an incentive to ......’misestimate’ AFUDC and. pocket additional prospective but unjustified revenues.Public System assumes that this provision was intended to ease accountingburdens but submits that the governing statutes do not contemplat9 suchwindfalls in the name of administrative convenience.

Oglethorp states that Order No. 561 excludes all non-investor sources of fundsfrom the AFUDC computation on the ground that such sources are treated as ratebase deductions but argues that some non-investor funds may not be treated asrate base deductions and hence could be incorrectly also over!ooked for AFUDCpurposes. Oglethorp believes the Order should be modified to provide that allnon-investor funds which are not deducted from rate base should be included inthe AFUDC formula, at zero cost.

The requirement that the AFUDC rate for the current year be based on theeffective weighted average cost of the long-term debt and preferred stock at theend of the prior year and the requirement that the AFUDC be compounded no morefrequently than semi-annually may, in some instances, tend to slightly




59 FPCI340(Cite as: 59 F.P.C. 1340, "1345)

Page 26

understate the cost of capital used for construction. Conversely, there may berelatively minor items of consumer contributed capital which are not consideredin either the ratemaking process or through AFUDC and there may well be someinstances in which the estimates used exceed by up to 25 basis points the ratethat would be derived from actual experience.

We conclude that Order No. 561 should not be modified with respect to thesematters. When considered together the proposed modifications tend to offseteach other. We believe that Order No. 561 clearly provides for a rate for AFUDCwhich is in the zone of reasonableness, based upon uniform standards which canbe effectively implemented and administered.

In light of the above, we believe that the applications for rehearing filed bythe aforementioned applicants should be denied.

The Commission fin~ds

The application for rehearing filed on March 4, 1977, by El Paso, PublicSystems, Oglethorp and Private Group and on March 7, 1977, by PP&L pre~ent nofacts or principles of law which would require modification of Order No. 561.

¯1346 The Commission orders:

(A) The applications for rehearing filed by E1 Paso, Public Systems, Oglethorpand Private Group on March 4, 1977, and PP&L on March 7, 1977, are denied.

(B) The Seqretary shall cause prompt publication of the Order in the FederalRegister.

APPENDIX A

PUBLIC SYSTEMS SPONSORING THE APPLICATION FOR REHEARING OF ORDER NO. 561

Anaheim, CaliforniaAzusa, CalifornlaBanning,- CaliforniaBowling Green, OhioBryan, OhioColton, CaliforniaCroswell, MichiganElectric Cities of

municipalities:

Virginia:

Blacks~oneChlpeperFranklinHarrisonburgIron GateManassas

North Carolina and ins members, the following

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59 FPC 1340(Cite as: 59 1340, "1346

Page 27

Wakefield

North Carolina:

AlbermarleApexAydenBelhav%nBensonBlack CreekBosticCherryvilleClaytonConcordCorneliusDallasDavidsonDrexelEdentonElizabeth CityEnfieldFarmvilleFayettevilleForest CityFountainFremontGastoniaGranite FallsGreenvilleHamiltonHertfordHighlandsHigh PointHobgoodHookertonHuntersvilleKings MountainKingstonLaGrangeLandisLaurinburgLexingtonLincolntonLouisburgLucamaLumbertonMacclesfieldMaiden

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59 FPC 1340(Cite as: 59 F.P.C. 1340, *1346)

Page 28

MonroeMorgannonMurphyNew DernNewtonOak CityPikevillePinetopsPinevilleRed SpringsRobersonvilleRocky MountScotland NeckSelma¯1347 SharpsburgShelbySmithfieldSouthporzStantonsburgStatesvilleTarboroWake ForestWalztonburgWashingnonWaynesvilleWilsonWindsorWinterville

Municipals and Cooperatives in zhe State ofAlachuaBartowBushnellChattahoocheeForz MeadeLake HelenLeesburgMount DoraNewberryOcalaQuincyWilliston

Frankfort, KentuckyIndiana Municipa! Electric Association and

municlpalit±es in [ndiana:Town of BainbridgeTown of BargersvilleTown of Centerville

"Town of Coving<on

Ziorida:

its members, the following

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59 FPC 1340(Cite as: 59 F.P.C. 1340, "1347)

Page 29

Town of Darlingnon.Town of EdinburgTown of FloraTown of GreendaleCity of GreenfieldTown of HagerstownLawrenceburg UtilitiesLawrenceburgCity of LebanonCity of LintonTown of MiddletownTown of PaoliTown of PendletonCity of Rising SunTown of RockvilleCity of ScottsburgTown of South WhitleyTown of ThorntownCity of TiptonTown of VeedersburgTown of Waynetown

NEPCO Customer Rate CommitteeMunicipal Electric Association offollowing Massachusetts municipal

AshburnhamBoylstonDanversGeorgetownGrotonHinghamHoldenHudsonHullIpswichLittletonMansfieldMarbleheadMerrimacMiddletonNorth AttleboroPaxtonPeabodyPrincetonShrewsburySterlingTempletonWakefieldWest Boylston and Manchester

(successor no the Power Planning Committee ofMassachusetts, Inc.) and its mentbers thelight departments and plants:

Electric Company

the

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59 FPC 1340(Cite as: 59 F.P.C. 1340, "1347)

Page 30

New Hampshire Electric Cooperative,Littleton, New Hampshire

City of Riverside, CaliforniaVermont Electric Cooperative, Inc.,Village of Clinton, MichiganVillage of Sebewaing, Michigan

Inc.

Johnson, Vermont

FN* Published in the Federal Register on August 5, 1977 (42 F.R. 39661).Order issued January 20, 1978 clarifying Order Nos. 561 and 561-A, 2 FERC [61,050.

FNI See Appendix A for members of Public Systems.FN2 Oglethorp Electric Membership Corporation, North Carolina Electric

Membership Corporation and Old Dominion Electric Cooperative, Inc.FN3 Jersey Central Power & Light Company, Long Island Lighting Company,

Metropolitan Edison Company, New England Power Company, Northeast UtilitiesCompany, Pacific Power & Light Company, Pennsylvania Electric Company andPennsylvania Power & Light Company.

FN4 [Editor’s none: Remanded, Public Systems, e~ al. v. F.E.R.C., 606973 (CADC-1979).]FEDERAL POWER COMMISSION59 F.P.C. 1340, 1977 WL 16744 (F.P.C.)END OF DOCUMENT

F. 2d




Description Amount Not Capitalized Support Allocation/Sharing Guidance Accounting Conclusion[TRADE SECRET BEGINS

TRADE SECRET ENDS]

Regulatory & Legislative efforts related to transmission issues. 50,000$ Development phase only Amount shared with 9 CapX PartiesAll NSPM; Amount shared among CapX owners (1)

Record costs as O&M. There is no project to assess; thus, there is noway to assign a probability that this study will result in construction.

Env. Compliance study - CapX2020 participation (labor, consultant fees) in any MISO or other study work associated with impacts to transmission upgrade/buildout due to EPA regs, etc. 75,000$

Survey-level study; not tied to specific capital asset Amount shared with 9 CapX parties

All NSPM; Amount shared among CapX owners (1)

Record costs as O&M. There is no project to assess; thus, there is no way to assign a probability that this study will result in construction.

CapX2020 - GRE, object 713101 - This line item is not a new cost category - it is the total CapX2020 related costs that is billed and allocated to NSPM by GRE 350,000$ Development phase only Amount shared with 9 CapX Parties NSPMN Portion (1) Record costs as O&M. This study will never result in a capital project.CapX2020 Allocation - This is not a new cost category - it is the total cost that NSPM will bill to GRE; in return, GRE will then bill NSPM and all other CapX2020 owners. (287,500)$

Survey-level study; not tied to specific capital asset Amount shared with other CapX Parties

Billing to other CapX Participants (1) Record costs as O&M. This study will never result in a capital project.

MISO Studies - Interconnection (Reimbursable) 250,000$ Development phase only Historical Trends All NSPM (2) Record costs as O&M.

NERC Compliance Audit Preparation - Xcel Energy is required to prepare for and participate in Regional Entity audit for NERC Compliance Standards. Preparation is needed to ensure that data and documentation are available for the audit. 70,000$

Regional Entity audits and audit preparation are not considered capitalized expenses and are a part of Xcel Energy's O&M expense.

Approximately 200 hours of internal preparation per standard is required for the 7 Compliance Standards subjectto audit. Internal loaded rate of $50/hr. Calculated: 200 hrs/std x 7 stds x $50/hr = $70,000. All NSPM

CAPE Relay Checking Analysis for misoperation prevention - This project utilizes Computer Aided Protection Engineering (CAPE), Xcel Energy's protection system model, to analyze its protection system performance and identify potential misoperations. Preventing misoperations improves our transmission system performance. 100,000$

Analysis and studies for existing protection systems are not considered capitalized expenses and are a part of Xcel Energy's O&M expense.

There are roughly 415 protection systems in the NSP transmission system. Approximately 4 hours of modeling and analysis is required per system. The consulting engineering rate is $120/hr. Calculated at: 415 systems x 4 hr/system x $120/hr = $199,200. Half of the expenditure completed in 2013, the remainder ($100,000) in 2014. All NSPM (3)

Record costs as O&M as they relate to equipment operational efficiencies.

FERC Order 754 Data Request - Xcel Energy is required by federal law to response to NERC Rules of Procedure Section 1600 - Requests for Data or Information. Order 754 requests reliability data concerning Xcel Energy assets and this project responds to that order. 120,000$

This project is to respond to the FERC Order 754 data request. Responses to FERC orders are not considered capitalized expenses and are a part of Xcel Energy's O&M expense.

There are 50 substation facilities subject to this order. Approximately 40 hours of research per facility is required. The consulting engineering rate is $120/hr. Calculated at: 50 facilities x 40 hr/facility x $120/hr = $240,000. Half of the expenditure completed in 2013, the remainder ($120,000) in2014. All NSPM (2) Record costs as O&M.

FERC Technical Analysis Order 754 - Mandatory NERC data request 140,000$ Survey-level study; not tied to specific capital asset

Estimate based engineering judgement of consulting engineering time to complete study. All NSPM (1)


MTACT - Required annual NERC assessment 25,000$ Survey-level study; not tied to specific capital asset



Annual joint regional study - Studying NSP customer interests 50,010$ Survey-level study; not tied to specific capital asset



NSP Generation Retirement Study - Analysis needed to determine feasibility 60,000$ Survey-level study; not tied to specific capital asset



High Wind Penetration Study - Studying operational issues 50,000$ Survey-level study; not tied to specific capital asset



Northern States Power Company EXPENSED STUDIES



References: (1) Code of Federal Regulations, CFR 18 Parts 1 to 399, Electric Plant Instruction No. 3, Components of Construction Cost, 2012.

20) Studies include the costs of studies such as nuclear operational, safety, or seismic studies or environmental studies mandated by regulatory bodies relative to plant under construction. Studies relative to facilities in service shall be charged to account 183, Preliminary Survey and Investigation Charges. [Emphasis added]

Code of Federal Regulations, CFR 18 Part 101, Balance Sheet Accounts, 2012. 183. Preliminary survey and investigation charges (Major only).

A. This account shall be charged with all expenditures for preliminary surveys, plans, investigations, etc., made for the purpose of determining the feasibility of utility projects under contemplation. If construction results, this account shall be credited and the appropriate utility plant account charged. [Emphasis added]

(2) Code of Federal Regulations, CFR 18 Part 101, Operation and Maintenance Expense Accounts

561.1 Load Dispatch--Reliability This account shall include the cost of labor, materials used and expenses incurred by a regional transmission service provider or other transmission provider to manage the reliability coordination function as specified by the North American Electric Reliability Council (NERC) and individual reliability organizations. These activities shall include performing current and next day reliability analysis. This account shall include the costs incurred to calculate load forecasts, and performing contingency analysis. [Emphasis added]

561.6 Transmission Service Studies. This account shall include the cost of labor, materials used and expenses incurred to conduct transmission services studies for proposed interconnections with the transmission system. Detailed records shall be maintained for each study undertaken and all reimbursements received for conducting such a study. [Emphasis added]

561.7 Generation Interconnection Studies. This account shall include the cost of labor, materials used and expenses incurred to conduct generation interconnection studies for proposed interconnections with the transmission system. Detailed records shall be maintained for each study undertaken and all reimbursements received for conducting such a study. [Emphasis added]

(3) Code of Federal Regulations, CFR 18 Parts 101 Operating Expense Instructions, 2012

1. Supervision and Engineering (Major Utilities) The supervision and engineering includible in the operating expense accounts shall consist of the pay and expenses of superintendents, engineers, clerks, other employees and consultants engaged in supervising and directing the operation and maintenance of each utility function. Wherever allocations are necessary in order to arrive at the amount to be included in any account, the method and basis of allocation shall be reflected by underlying records.

Items

Labor

1. Special tests to determine efficiency of equipment operation. [Emphasis added].

Northern States Power Company EXPENSED STUDIES



Docket No. E002/GR-13-868Exhibit___(LHP-1), Appendix A

Depreciation Discovery - 2013 Electric Rate Case - Docket No. E002/GR-12-961Index

Question Addressed in 2014 Case

DOC 109

For the following question, please be advised that the DOC expects the response will include actual account balances from March 31, 2012 and that the source of the information will be identified. The DOC will also expect to be able to track the budgeted/forecasted data used for the months of April 2012 through December 2013 in the test-year rate base, to the Xcel Board of Directors approved capital budgets for the years 2012 and 2013. A. Please provide work papers (or identify where they may exist in the rate case filing) that show the development of the test year Plant in Service, Accumulated Depreciation, and Construction Work in Progress, beginning with actual March 31, 2012 balances. B. Please provide all source documents (or identify where they exist within the rate case filing) used in the development of (A) above.

Appendix A

DOC 132Subject: Depreciation Lives A. Is Xcel planning on extending any of the lives of its generation plants in the next two years? If yes, please identify which generation plants Xcel is planning to extend and the expected life of that extension. B. Is Xcel planning on extending any of the lives of its transmission, distribution and general plants in the next two years? If yes, please identify which lives Xcel is planning to extend and the expected life of that extension.

Testimony p. 8 - 30

DOC 133

Subject: Depreciation Lives Reference: A. Please provide and identify plant additions of $1 million or more in all generation, transmission and distribution plants in the 2013 test year. Please explain for each capital addition to generation, transmission, distribution and general plant if the depreciation rate was updated and reflected in the test year, showing depreciation rate changes and an impact on depreciation expense in the test year. B. Please explain why it is reasonable where the Company did not extend the depreciation rate where there were capital additions of $1 million or more.

Testimony p. 8 - 35Schedule 8

DOC 137 Subject: Change in 2012 and 2013 Depreciation Test Year Expense Reference: Lisa Perkett’s Direct Testimony, Exhibit__(LHP-1), Schedule 5 Please provide detailed support for the totals presented in the Proposed 2013 Increase column of Schedule 5. Schedule 11

DOC 168Subject: Depreciation References: No Specific Reference A. Please provide a schedule identifying all depreciation rates that are different (in North Dakota and South Dakota) than Minnesota depreciation rates. B. For all depreciation rates where there are differences in the Minnesota approved depreciation rates compared to the North and South Dakota depreciation rates, please explain the causes for these differences.

Appendix A

OAG 0051Explain whether retirement work in progress (RWIP) results in a return included in setting rates and whether AFUDC is calculated on this amount. Explain the tax treatment for RWIP. Provide the total amount of RWIP and the associated return proposed for setting rates in this proceeding. Provide the supporting FERC accounting authorization that permits the recording of RWIP.

Testimony p. 67 - 69

OAG 0058Explain if and to what extent FERC allows CWIP in rate base. Identify FERC rules, notices or orders that explain FERC's position on CWIP inclusion in rate base. Identify any FERC rules, notices or orders that establish the rate( s) used to compute AFUDC. Explain whether NSP is in compliance with FERC rules on CWIP and the determination of AFUDC.

Schedule 14

OAG 0065 Explain whether NSP computes AFUDC on all CWIP and if so why. If not, explain what criteria NSP uses to determine whether to calculate AFUDC on a particular project. Testimony p. 58 - 62

OAG 0066Explain whether NSP computes AFUDC in accordance with FERC accounting requirements. Provide the relevant language of FERC regulations that support NSP’s calculation of AFUDC. Also explain whether NSP’s computation of AFUDC always includes a return on equity. If not, explain the criteria that NSP uses to determine when to compute a return on equity for AFUDC.

Schedule 14

OAG 0067 For each of the years 2008 through 2012 provide the amount of CWIP and AFUDC actually recorded . Schedule 14

OAG 0070 Reference Test Year Workpapers, Volume 4, tab P3A. For the years 2012 and 2013 provide the total amount of AFUDC that is included in CWIP. Also provide the total amount of AFUDC for 2012 and 2013 assuming there is no monthly compounding of AFUDC, instead assume an annual calculation of AFUDC. Appendix A

OAG 0070.1 Reference NSP response to OAG IR 70. Response did not provide the requested information. Provide four amounts: 2012 AFUDC total and the MN electric jurisdiction and 2013 AFUDC total and MN electric jurisdiction. Appendix A

OAG 0107 Provide the 2012 average level of CWIP costs by project incurred through December 31, 2012 for projects that were still under construction on December 31, 2012. Identify the level of 2013 test year CWIP costs for these same projects. Appendix A

OAG 73 Ten largest projects being requested in base rates where the Company is requesting a return on CWIP without an AFUDC offset, based on the standards in Section 216B.16, subd. 6a. Testimony p. 55

OAG 74 Twenty smallest projects being requested in base rates where the Company is requesting a return on CWIP without an AFUDC offset, based on the standards in Section 216B.16, subd. 6a. Testimony p. 55

XLI 204 The XLI 200 series relates to the testimony of Lisa Perkett. Please provide a schedule quantifying the most recently determined theoretical reserve with the actual book depreciation reserve balance by FERC account for Nuclear Production Plant using the currently approved life spans and any proposed plant life changes.


XLI 206 The XLI 200 series relates to the testimony of Lisa Perkett. Please provide a listing of all NSP generating units with their in-service date, retirement date associated with their approved remaining life and retirement date associated with the proposed remaining life in Docket E, G002/D-12-151. Appendix A

XLI 207

The XLI 200 series relates to the testimony of Lisa Perkett. Schedule F from Docket No. E, G002/D-12-151 states that for Sherco Units 1 and 2 the company plans to conduct a comprehensive life cycle management study over the next two or three years. Exhibit LHP-1, Schedule 2 from Docket E002/GR-10-971 stated that “a study is also underway studying the viability of the future operations of the units past the current remaining life.” Was this study ever completed? If yes, what did it recommend concerning a life extension? a. Please address the reasons for the delay in the study. b. If the lives are extended does Xcel Energy propose any adjustments to revenue requirements to reverse the excess reserve accumulated with the rates based on the shorter lives?


XLI 209

The XLI 200 series relates to the testimony of Lisa Perkett. On page 6 of NSP’s Petition for 2010 Annual Review of Remaining Lives, (Docket No. E,G002/D-10-173), the following is stated: The Sherco plant is Xcel Energy’s largest coal plant and is an integral part of the Company’s long-term production outlook. With continued regular maintenance, the plant remains in good condition and we believe could operate well beyond the currently established remaining life. In an effort to ensure that we do not financially over-recover for the current generating assets of an essential base load facility, it is important that we avoid using a depreciation schedule that is too rapid. a. Please state the criteria used to determine if the depreciation schedule is too rapid. b. If a depreciation schedule is determined to be too rapid, please discuss what steps should be taken to correct past accelerated recovery.


XLI 211 Provide the following data in electronic format for the Monticello and Prairie Island nuclear plants for each depreciable FERC account: a. Annual additions b. Annual retirements by vintage year c. Annual adjustments by vintage year d. 1/1/2012 Investment balance by vintage year


XLI 212 Referring to page 19 of Ms. Perkett’s Rebuttal testimony, please provide documents supporting the current depreciation rates, which demonstrate that interim retirements are not reflected in the nuclear depreciation rates.


XLI 213

Page 16 of Ms. Perkett’s Rebuttal testimony includes the statement: “In addition, our need to make significant additional nuclear investments is inconsistent with decreasing the Actual Reserves.” a. Are the additional nuclear investments referenced in this statement projected to occur during the test year? b. Please define what future investments should be considered in setting depreciation rates. c. Please provide any authoritative source for the statement that future investments should be considered in determining test year depreciation expense.


IR No.

Page 1 of 35


Depreciation Discovery - 2013 Electric Rate Case - Docket No. E002/GR-12-961Index

Question Addressed in 2014 Case

IR No.

XLI 214 Referring to page 11 of Ms. Perkett’s Rebuttal Testimony, please provide work papers demonstrating there is no accumulated reserve surplus for nuclear assets.


XLI 215 Please explain if the affects of interim retirements and interim net salvage are not allowed in the depreciation rate determination why they should be accounted for in the theoretical reserve determination.


XLI 216 Please provide a schedule of estimated interim retirements by FERC account for Monticello and Prairie Island nuclear plants for the period 2012 – 2016. Testimony p. 43 - 50Schedule 13

Page 2 of 35

Docket No. E002/GR-13-868 Exhibit___(LHP-1), Appendix A

Docket No. E002/GR-12-961 Information Request No. DOC-109 _________________________________________________________________

Question: Subject: Plant in Service, Depreciation Reserve, and Construction Work in Progress Reference: Xcel Energy Exhibit ____(AEH-1), Schedule 4, page 2 of 6 Xcel Energy Exhibit ____, Heuer Direct, page 37. For the following question, please be advised that the DOC expects the response will include actual account balances from April 30, 2013 and that the source of the information will be identified. The DOC will also expect to be able to track the budgeted/forecasted data used for the months of May 2013 through December 2014 in the test-year rate base, to the Xcel Board of Directors approved capital budgets for the years 2013 and 2014. A. Please provide work papers (or identify where they may exist in the rate case filing) that show the development of the test year Plant in Service, Accumulated Depreciation, and Construction Work in Progress, beginning with actual April 30, 2013 balances. B. Please provide all source documents (or identify where they exist within the rate case filing) used in the development of (A) above.

Response: A. The requested information for May 2013 through December 2014 can be found in Volume 4 Test Year Workpapers of the Company’s application, with the specific location within the Workpapers identified below. These reports are referred to as the “Roll Forward” reports.

The starting balances for Plant in Service, Accumulated Depreciation, and Construction Work in Progress (“CWIP”) are shown in Volume 4 Test Year Workpapers; “III. Rate Base (Plant)” section, under the tab labeled “P3. Roll Forward Reports”. There are 3 reports behind this tab including P3A-CWIP

Page 3 of 35


2

Roll Forward, P3B-Plant In Service Roll Forward and P3C-Accumulated Depreciation Roll Forward.

The first report in this section, Volume 4 Test Year Workpapers, III. Rate

Base (Plant) section, P3A – CWIP Roll Forward, shows the grandparent projects by functional class. This report starts with the CWIP Beginning Balance, adds the CWIP expenditures, Debt and Equity Allowance for Funds Used During Construction (“AFUDC”) and subtracts the Closings to Plant and adjusts for transfers and other adjustments ending in the CWIP Ending Balance.

This report and the following two reports roll forward the monthly balances starting from January 2013 through the forecasted months to December 2014. The rate case forecast includes 4 months of actuals and 8 months of forecast in 2013.

The next roll forward report is Volume 4 Test Year Workpapers, III. Rate

Base (Plant) section, P3B – Plant In Service Roll Forward. This report is by functional class and starts with the Gross Plant Beginning Balance, subtracts the Retirements, and adds the Plant Additions and adjusts the Transfers and Adjustments, ending with the Ending Plant balance for each month through 2014. The Plant Additions relate to the closings in the CWIP Roll Forward report.

The final roll forward report is Volume 4 Test Year Workpapers, III. Rate Base

(Plant) section P3C – Accumulated Depreciation Roll Forward. This report is also by functional class and takes the Beginning Accumulated Depreciation Balance adds the Book Depreciation, subtracts the Retirements, the Book Removals, and the Salvage and adjusts for the Transfers & Adjustments, ending with the Ending Accumulated Depreciation Balance for each month through 2014. The retirements relate to the retirements in the Plant in Service Roll forward.

The total CWIP Expenditures from the CWIP roll forward report for 2013 is

$1,393,523,850. There is a difference between this and the Xcel Energy Board of Directors approved capital budget for 2013 because the data in the CWIP roll forward for 2013 is the bridge year from the current budget run for 2013 and contains 4 months of actuals. This data also includes rate case adjustments.

The total CWIP Expenditures from the CWIP roll forward report for 2014 is

$1,047,016,545. There is a difference between this and the Xcel Energy Board of Directors approved capital budget for 2014 because subsequent to the initial budget

Page 4 of 35


3

approval, the Xcel Energy Board of Directors approved additional expenditures for two wind projects (Borders and Pleasant Valley). The 2014 portion of these approved additional expenditures total $35 million. Subsequent to Board approval, cash flow projections have been refined, thus the rate case data reflects a shift in CWIP expenditures from 2015 to 2014 for the wind projects. The CWIP roll forward report reflects adjustments for the two wind projects as well as other rate case adjustments.

Please see Attachment A for the 2013 Board approved budget, Attachment B

for the 2014 Board approved budget, and Attachment C for the tie out between the Board approved amounts and the CWIP roll forward. B. The source is the Company’s PowerPlant system and the jurisdictional allocating system (JUR File). The data is extracted from these systems and becomes the work papers. The cost of service uses data extracted directly from the JUR file and ties to the work papers. As such, the workpapers are the source documents which are summarized in Volume 4, Test Year Workpapers, III. Rate Base (Plant) section, P1 Summary. __________________________________________________________________ Preparer: Linda Hudgins/Gregory Robinson Title: Consultant/Manager Department: Capital Asset Accounting/Financial Forecasting

Page 5 of 35

Xcel Energy Inc. Board of Directors

10/24/12

Resolution to Approve the Cancellation of the SPS CSAPR Project and a Revised 2013 Capital Budget

WHEREAS, the Finance Committee is authorized by its charter to make recommendations to the Board of Directors regarding Xcel Energy’s capital budget, including major capital projects in excess of $25 million; and WHEREAS, on June 20, 2012 the Board of Directors approved the 2013 capital budget totaling $3.219 billion. The 2013 total capital budget included $85 million for the SPS Cross-State Air Pollution Rule (“CSAPR”) project which was originally approved by the Board of Directors on December 13, 2011 as a major capital project having a life-of-project authorization of $472 million; and WHEREAS, on August 21, 2012, the U.S. District Court of Appeals vacated the Cross-State Air Pollution Rule and sent it back to the U.S. Environmental Protection Agency for revision. The court reinstated the previous Clean Air Act Interstate Rule with which SPS must continue to comply; and

WHEREAS, based on the court’s decision, which affects the ultimate amount and timing of the required capital investment at SPS, management recommends canceling the SPS CSAPR Project and removing $85 million from the original 2013 capital budget, as well as future amounts required for this project from the capital forecast; and

WHEREAS, incremental investment of $19 million will be required in 2013 at SPS to achieve near-term compliance with other U.S. Environmental Protection Agency mandates, and management recommends adding this amount to the original 2013 capital budget ; and

WHEREAS, incremental investment of $32 million will be required at PSCo in 2013 to accelerate the replacement of certain natural gas pipeline assets to improve overall system reliability, and management recommends adding this amount to the original 2013 capital budget.

WHEREAS, the Finance Committee has reviewed the cancellation of the SPS CSAPR Project and the net reduction of $34 million to the original 2013 capital budget to reflect the three changes discussed above, and recommends that the full Board of Xcel Energy Inc. approve the cancellation of the SPS CSAPR Project and a revised 2013 capital budget of $3.185 billion.

Docket No. E002/GR-12-961 Information Request No. DOC-109 Attachment A


Page 6 of 35

NOW, THEREFORE, BE IT RESOLVED, that the Board of Directors of

Xcel Energy Inc. has reviewed the Finance Committee’s recommendation and does hereby approve the cancellation of the SPS CSAPR Project and a revised 2013 capital budget of $3.185 billion.

Docket No. E002/GR-12-961 Information Request No. DOC-109 Attachment A


Page 7 of 35

Docket No. E002/GR-12-961 Information Request No. DOC-109 Attachment B


Page 8 of 35



Page 9 of 35



Page 10 of 35



Page 11 of 35

Docket No. E002/GR-12-961 Docket E002/GR-13-868Information Request No. DOC-109 Exhibit___(LHP-1), Appendix AAttachment C

(Thousands of Dollars)

Legal Entity 2013 BudgetPSCo $1,064,000NSPM $1,442,000SPS $490,000NSPW $175,000WYCO $14,000

Total $3,185,000

(Thousands of Dollars)

Legal Entity 2014 BudgetPSCo $986,000NSPM $1,087,000SPS $517,000NSPW $291,000

Total $2,881,000

Xcel Energy Inc. 2013 Capital Budget

Xcel Energy Inc. 2014 Capital Budget

Page 12 of 35

Docket No. E002/GR-12-961Information Request No. DOC-109Attachment C

NSP-MN Board Approved Expenditures to CWIP Rollforwards (P3A)

2013 BOD Budget 2014 BOD BudgetTotal NSP-MN Budget Capital Expenditures $1,442,000,000 $1,087,000,000

2013 Forecast 2014 BudgetTotal CWIP $1,443,994,810 $1,100,322,309Total RWIP $57,400,626 $25,099,828Total Capital Expenditures $1,501,395,436 $1,125,422,136

Difference in Forecast from Budget $59,395,436 $38,422,136

Electric $1,215,895,228 $828,630,228Nuclear Fuel $91,458,332 $139,957,791Common $86,170,290 $78,428,526Non-utility $468,302 $0Gas $50,002,658 $53,305,764Total CWIP $1,443,994,810 $1,100,322,309

Total CWIP $1,443,994,810 $1,100,322,309Less : Gas and Non-utility ($50,470,960) ($53,305,764)

Base CWIP $1,393,523,850 $1,047,016,545

CWIP Roll Forwards (Rate Base Section P3A) $1,393,523,850 $1,047,016,545

Docket E002/GR-13-868Exhibit___(LHP-1), Appendix A

Page 13 of 35


Docket No. E002/GR-12-961 Information Request No. DOC-168 ________________________________________________________________

Question: Subject: Depreciation References: No Specific Reference

A. Please provide a schedule identifying all depreciation rates that are different (in North Dakota and South Dakota) than Minnesota depreciation rates. B. For all depreciation rates where there are differences in the Minnesota approved depreciation rates compared to the North and South Dakota depreciation rates, please explain the causes for these differences.

Response: Please see Attachment A for a schedule identifying all depreciation groups where remaining lives or depreciation rates differ between the Minnesota, North Dakota, and South Dakota jurisdictions. Attachment A also includes an explanation for each of the differences. Remaining lives are shown as of January 1, 2013. Please note that this attachment only includes currently approved depreciation lives and rates. Remaining life and depreciation rate changes proposed in Minnesota in Docket Nos. E,G002/D-12-151 and E,G002/D-12-858 were not included in this analysis, unless previously approved in E002/GR-12-961. For Sherco 3, the remaining life shown represents the remaining life as of January 1, 2012, when the remaining life was suspended due to the plant being offline. The remaining life will remain suspended until January 1, 2014. Changes to remaining lives and depreciation rates proposed in the Company’s pending North Dakota electric rate case also were not included. __________________________________________________________________ Preparer: Brandon Kirschner Title: Senior Accounting Analyst Department: Capital Asset Accounting

Page 14 of 35

Docket No. E002/GR-12-961Information Request No. DOC-168, Attachment A


FERC Account Plant

Remaining

Life Net

Salvage %

Remaining

Life Net

Salvage %

Remaining

Life Net

Salvage % Explanation for Difference

311 Red Wing 5.0 -23.3% - -23.3% 5.0 -23.3%

New remaining life approved for MN in Docket No. E,G002/D-10-173 and for SD in Docket No. EL11-019, to match new fuel contract. ND remaining life expired at end of 2012.

311 Sherco 1&2 10.0 -5.1% 22.0 -5.1% 10.0 -5.1%Different ND remaining life approved as a part of settlement to Docket No. PU-07-776.

311 Sherco 3 21.0 -4.3% 22.0 -4.3% 20.0 -4.3%

For MN, the suspension of remaining life as of January 1, 2012 was approved by the MPUC in E002/GR-12-961 due to plant being offline. Life will resume on January 1, 2014. Revised remaining life was approved in Docket No. E002/GR-12-961. Different ND remaining life approved as a part of settlement to Docket No. PU-07-776.

311 Wilmarth 5.0 -23.0% - -23.0% 5.0 -23.0%


312 Red Wing 5.0 -23.3% - -23.3% 5.0 -23.3%



312 Sherco 3 21.0 -4.3% 22.0 -4.3% 20.0 -4.3%


312 Wilmarth 5.0 -23.0% - -23.0% 5.0 -23.0%


314 Red Wing 5.0 -23.3% - -23.3% 5.0 -23.3%



314 Sherco 3 21.0 -4.3% 22.0 -4.3% 20.0 -4.3%


314 Wilmarth 5.0 -23.0% - -23.0% 5.0 -23.0%


315 Red Wing 5.0 -23.3% - -23.3% 5.0 -23.3%



315 Sherco 3 21.0 -4.3% 22.0 -4.3% 20.0 -4.3%


315 Wilmarth 5.0 -23.0% - -23.0% 5.0 -23.0%


316 Red Wing 5.0 -23.3% - -23.3% 5.0 -23.3%



316 Sherco 3 21.0 -4.3% 22.0 -4.3% 20.0 -4.3%


316 Wilmarth 5.0 -23.0% - -23.0% 5.0 -23.0%


Minnesota North Dakota South Dakota

Steam Production

Page 15 of 35



FERC Account Plant

Remaining

Life Net

Salvage %

Remaining

Life Net

Salvage %

Remaining

Life Net



341 Angus Anson Units 2&3 22.4 -4.5% 26.0 -4.5% 22.4 -4.5%Different ND remaining life approved as a part of settlement to Docket No. PU-07-776.

341 Angus Anson Unit 4 22.4 -4.5% 26.0 -4.5% 22.4 -4.5%Different ND remaining life approved as a part of settlement to Docket No. PU-07-776.

341 Granite City 6.0 -38.8% 1.0 -38.8% - -38.8%

New life linked to major plant addition approved in Docket No. E002/GR-12-961, effective June 2013. Different ND remaining life approved as a part of settlement to Docket No. PU-07-776. Remaining life for MN and SD expired at end of 2012.

341 High Bridge 35.4 -3.1% 40.4 -3.1% 35.4 -3.1%Different ND remaining life approved as a part of settlement to Docket No. PU-07-776.

341 Inver Hills 14.0 -11.0% 4.0 -11.0% 14.0 -11.0%

New remaining life approved for MN in Docket No. E,G002/D-10-173 and for SD in Docket No. EL11-019 Remaining life change made due to rework of all plant turbines.

341 Key City - -38.6% 2.0 -38.6% 5.0 -38.6%

Different ND remaining life approved as a part of settlement to Docket No. PU-07-776. SD remaining life approved as a part of Docket No. EL12-046

341 Riverside 36.2 -5.0% 26.2 -5.0% 36.2 -5.0%New remaining life approved for MN as a settlement to Docket No. E002/GR-10-971 and for SD in Docket No. EL11-019.



342 Blue Lake Units 1-4 - -11.9% - -11.9% 5.0 -11.9%Different SD remaining life approved as a part of Docket No. EL12-046

342 Granite City 8.0 -38.8% 1.0 -38.8% - -38.8%



342 Inver Hills 14.0 -11.0% 4.0 -11.0% 14.0 -11.0%


342 Key City - -38.6% 2.0 -38.6% 5.0 -38.6%






344 Granite City 6.0 -38.8% 1.0 -38.8% - -38.8%



344 Inver Hills 14.0 -11.0% 4.0 -11.0% 14.0 -11.0%


344 Key City - -38.6% 2.0 -38.6% 5.0 -38.6%






Other Production

Page 16 of 35



FERC Account Plant

Remaining

Life Net

Salvage %

Remaining

Life Net

Salvage %

Remaining

Life Net



345 Granite City 6.0 -38.8% 1.0 -38.8% - -38.8%



345 Inver Hills 14.0 -11.0% 4.0 -11.0% 14.0 -11.0%


345 Key City - -38.6% 2.0 -38.6% 5.0 -38.6%






346 Granite City 6.0 -38.8% 1.0 -38.8% - -38.8%



346 Inver Hills 14.0 -11.0% 4.0 -11.0% 14.0 -11.0%


346 Key City - -38.6% 2.0 -38.6% 5.0 -38.6%



Page 17 of 35



FERC Account Account Description

Minnesota Depr Rate

North Dakota

Depr Rate

South Dakota

Depr Rate Explanation for Difference

352 Structures and Improvements 1.4706% 1.8606% 2.2224%

Average service life rate was approved for MN in Docket No. E002/GR-12-961. ND depreciation rate approved as a part of settlement to Docket No. PU-07-776 and is based off of a settled depreciation expense adjustment.

352.1 Structures and Improvements - Prod 1.4706% 1.8606% 2.2224%


353 Station Equipment 1.9643% 2.3584% 2.6316%


353.1 Station Equipment - Prod 1.9643% 2.3584% 2.6316%


354 Towers & Fixtures 1.9286% 1.2538% 1.8720%

Average service life rate was approved for MN in Docket No. E002/GR-12-961. ND depreciation rate approved as a part of settlement to Docket No. PU-07-776 and is based off of a settled depreciation expense adjustment. MN rates approved in settlement to Docket No. E002/GR-10-971. SD rates approved in Docket No. EL11-019.

354.1 Towers & Fixtures - Prod 1.9286% 1.2538% 2.5000%


355 Poles & Fixtures 2.1774% 2.0806% 1.8163%


355.1 Poles & Fixtures - Prod 2.1774% 2.0806% 2.4444%


356 OH Conductors 2.0635% 2.2175% 2.4668%


356.1 OH Conductors - Prod 2.0635% 2.2175% 3.0948%


357 UG Conduit 1.3699% 1.4952% 1.1900%


358 UG Conductors 1.8182% 2.1536% 1.8715%


361 Structures and Improvements 2.1667% 1.5077% 2.8884%


361.1 Structures and Improvements - Prod 2.1667% 1.5077% 2.8884%


362 Station Equipment 2.1818% 2.0617% 2.8944%


362.1 Station Equipment - Prod 2.1818% 2.0617% 2.8944%


Electric Transmission

Electric Distribution

Page 18 of 35




Minnesota Depr Rate

North Dakota

Depr Rate

South Dakota


364 Poles & Fixtures 4.5455% 1.2657% 3.5952%


365 OH Conductors 3.0769% 2.2032% 2.5599%


366 UG Conduit 2.1154% 1.5210% 0.8456%


367 UG Conductor 2.2222% 1.9415% 1.1313%


368 Line Transformers 3.2813% 2.2227% 1.8829%


368.1 Capacitors 4.0000% 3.3387% 3.0700%


369.1 OH Service 4.2500% 1.3333% 2.4454%


369.2 UG Service 2.5610% 1.8174% 2.4454%


370 Meters 6.6667% 6.0053% 5.7371%


370.1 Meters - Old 5.0000% 4.3387% 4.0704%


373 Street Lighting 4.6552% 3.1204% 4.8000%


Page 19 of 35




Minnesota Depr Rate

North Dakota

Depr Rate

South Dakota


390 Structures & Improvements 2.1053% 2.2224% 2.2224%Average service life rate was approved for MN in Docket No. E002/GR-12-961.

391 Office Furniture & Equipment 5.0000% 5.5556% 5.5556%Average service life rate was approved for MN in Docket No. E002/GR-12-961.

392 Transportation Equipment - Automobiles 10.0000% 9.0000% 9.0000%Average service life rate was approved for MN in Docket No. E002/GR-12-961.

392.2 Transportation Equipment - Light Trucks 8.3333% 9.0000% 9.0000%Average service life rate was approved for MN in Docket No. E002/GR-12-961.

392.3 Transportation Equipment - Trailers 6.6667% 9.0000% 9.0000%Average service life rate was approved for MN in Docket No. E002/GR-12-961.

392.4 Transportation Equipment - Heavy Trucks 7.1429% 7.9170% 7.9170%Average service life rate was approved for MN in Docket No. E002/GR-12-961.

396 Power Operated Equipment 8.3333% 9.0000% 9.0000%Average service life rate was approved for MN in Docket No. E002/GR-12-961.

Electric General

Page 20 of 35


Docket No. E002/GR-12-961 Information Request No. OAG-70.1 ____________________________________________________________

Question: Reference NSP response to OAG IR 70. Response did not provide the requested information. Provide four amounts: 2013 AFUDC total and the MN electric jurisdiction and 2014 AFUDC total and MN electric jurisdiction. Response: Please see Attachment A for AFUDC detail requested that is included in our rate case submittal information for 2013 and 2014 (cited in the question in IR OAG-70). These totals will tie to the roll forward reports originally submitted (Volume 4, Test Year Workpapers, tab P3, Roll Forward Reports (P3A) with the exception of common plant as it has been allocated to the Electric Utility and for the pre-funded AFUDC that is not included in the roll forward. The four amounts requested are summarized in the table below.

Year

Total Company

Electric

MN Retail Electric

2013

$63,232

$53,884

2014

$40,488

$35,027

_________________________________________________________________ Preparer: Shari Cardille / Jason Hegna Title: Principal Rate Analyst / Accounting Analyst Department: Revenue Requirements North / Capital Asset Accounting

Page 21 of 35


Docket No. E002/GR-12-961 Information Request No. OAG-70 _________________________________________________________________

Question: For all responses show amounts for Total Company and the Minnesota jurisdictional electric company unless indicated otherwise. Total Company is meant to include costs incurred by Xcel Energy Services and NSP Minnesota, both regulated and non-regulated operations. Reference Test Year Workpapers, Volume 4, tab P3A. For the years 2012 and 2013 provide the total amount of AFUDC that is included in CWIP. Also provide the total amount of AFUDC for 2013 and 2014 assuming there is no monthly compounding of AFUDC, instead assume an annual calculation of AFUDC. Response: For the amount of AFUDC calculated on CWIP throughout the period requested, see Attachment A. The Company only calculates AFUDC based on the FERC method that compounds AFUDC semi annually. An approximation of the amount of AFUDC calculated assuming no monthly compounding is shown on the bottom of Attachment A. _________________________________________________________________ Preparer: Jason Hegna Title: Principal Financial Consultant Department: Capital Asset Accounting

Page 22 of 35

Docket No. E002/GR-12-961 Docket No. E002/GR-13-868Information Request No. OAG-70Attachment A

Exhibit___(LHP-1), Appendix A

AFUDC in CWIP Rollforward2013

January February March April May June July August September October November DecemberElectric Intangible Plant

AFUDC CWIP Beginning Balance 2,865,523 2,979,361 3,092,946 3,219,572 3,344,249 3,471,174 3,599,566 3,542,294 3,679,073 3,824,446 3,979,807 4,145,069 AFUDC Debt 34,643 35,363 38,628 40,200 38,773 40,667 41,137 41,818 44,456 47,521 50,558 47,160

AFUDC Equity 79,195 80,849 87,998 91,735 88,192 92,502 93,570 95,120 101,121 108,093 115,000 107,270 Closings to Plant - (2,628) - (7,258) (40) (4,777) (191,979) (158) (204) (254) (296) (1,920,106)

CWIP Ending Balance 2,979,361 3,092,946 3,219,572 3,344,249 3,471,174 3,599,566 3,542,294 3,679,073 3,824,446 3,979,807 4,145,069 2,379,393

Electric Steam Production PlantAFUDC CWIP Beginning Balance 2,039,359 2,262,604 2,527,558 2,821,841 3,045,771 3,318,902 3,443,099 3,750,623 4,017,773 3,247,652 2,297,525 1,590,271

AFUDC Debt 74,804 84,084 94,780 99,904 107,636 112,182 113,166 120,284 110,619 80,929 55,655 41,966 AFUDC Equity 171,281 192,233 215,931 227,974 244,829 255,170 257,409 273,600 251,616 184,081 126,594 95,457

Closings to Plant (22,841) (11,362) (16,428) (103,947) (79,333) (243,156) (63,051) (126,734) (1,132,356) (1,215,137) (889,504) (455,715) CWIP Ending Balance 2,262,604 2,527,558 2,821,841 3,045,771 3,318,902 3,443,099 3,750,623 4,017,773 3,247,652 2,297,525 1,590,271 1,271,979

Electric Nuclear Production PlantAFUDC CWIP Beginning Balance 86,277,585 89,354,215 92,540,168 96,048,226 99,688,293 90,497,606 52,407,118 55,867,613 58,956,316 62,250,380 63,305,150 66,972,100

AFUDC Debt 945,752 969,663 1,070,190 1,114,008 1,238,305 1,251,410 1,059,892 976,748 1,036,464 1,090,533 1,134,902 917,158 AFUDC Equity 2,161,469 2,216,290 2,437,868 2,541,796 2,804,998 2,847,428 2,411,189 2,221,798 2,357,626 2,480,612 2,581,520 2,086,245

Closings to Plant (30,591) - - (15,738) (13,233,989) (42,189,326) (10,585) (109,843) (100,026) (2,516,376) (49,472) (31,663,675) CWIP Ending Balance 89,354,215 92,540,168 96,048,226 99,688,293 90,497,606 52,407,118 55,867,613 58,956,316 62,250,380 63,305,150 66,972,100 38,311,828

Electric Hydro Production PlantAFUDC CWIP Beginning Balance 26,941 34,430 42,975 53,477 65,820 80,286 97,026 116,335 138,402 162,905 187,005 11,286

AFUDC Debt 2,279 2,600 3,203 3,761 4,418 5,112 5,917 6,770 7,513 7,780 4,241 624 AFUDC Equity 5,210 5,945 7,299 8,583 10,048 11,627 13,460 15,398 17,088 17,695 9,646 1,419

Closings to Plant - - - - - - (67) (101) (98) (1,375) (189,606) (2,692) CWIP Ending Balance 34,430 42,975 53,477 65,820 80,286 97,026 116,335 138,402 162,905 187,005 11,286 10,638

Electric Other Production PlantAFUDC CWIP Beginning Balance 5,299 2,986 2,380 4,711 10,450 13,633 19,089 30,050 43,341 54,064 65,487 27,564

AFUDC Debt 673 509 711 1,763 2,945 3,089 4,016 5,128 5,958 7,288 6,213 2,207 AFUDC Equity 1,539 1,165 1,620 4,022 6,698 7,027 9,134 11,665 13,552 16,578 14,132 5,020

Closings to Plant (4,524) (2,280) - (46) (6,460) (4,661) (2,189) (3,503) (8,787) (12,444) (58,268) (30,488) CWIP Ending Balance 2,986 2,380 4,711 10,450 13,633 19,089 30,050 43,341 54,064 65,487 27,564 4,302

Electric Transmission PlantAFUDC CWIP Beginning Balance 16,538,990 17,961,597 19,466,302 21,068,697 21,134,639 20,375,784 21,001,566 22,614,161 24,806,317 27,313,567 29,945,835 32,895,737

AFUDC Debt 448,533 467,515 509,755 528,790 558,639 581,922 629,122 695,707 776,594 849,223 921,502 888,190 AFUDC Equity 1,025,387 1,068,841 1,162,009 1,206,747 1,268,668 1,323,879 1,431,125 1,582,463 1,766,448 1,931,653 2,096,059 2,020,286

Closings to Plant (51,313) (31,651) (69,370) (1,669,594) (2,586,163) (1,280,019) (447,652) (86,014) (35,792) (148,609) (67,658) (9,003,405) CWIP Ending Balance 17,961,597 19,466,302 21,068,697 21,134,639 20,375,784 21,001,566 22,614,161 24,806,317 27,313,567 29,945,835 32,895,737 26,800,808

Electric Distribution PlantAFUDC CWIP Beginning Balance 692,027 754,943 893,398 1,054,662 1,238,506 1,606,989 1,950,741 1,902,802 1,569,950 1,411,778 1,396,713 1,341,392


Closings to Plant (72,081) (24,420) (47,148) (38,586) 101,264 84,386 (291,181) (563,133) (376,977) (223,258) (268,486) (109,227) CWIP Ending Balance 754,943 893,398 1,054,662 1,238,506 1,606,989 1,950,741 1,902,802 1,569,950 1,411,778 1,396,713 1,341,392 1,447,611

Electric General PlantAFUDC CWIP Beginning Balance 237,058 275,604 293,425 294,649 354,399 365,170 574,725 608,372 638,876 687,578 741,965 801,028


Closings to Plant (3,140) (23,787) (37,894) 6,886 (43,000) 160,754 (15,297) (16,318) (951) (873) (551) (30,159) CWIP Ending Balance 275,604 293,425 294,649 354,399 365,170 574,725 608,372 638,876 687,578 741,965 801,028 831,580

Common Intangible PlantAFUDC CWIP Beginning Balance 594,611 680,354 768,956 859,730 905,740 1,032,597 1,180,913 1,333,478 1,493,644 1,588,983 1,221,682 1,368,930


Closings to Plant - - (10,137) (61,524) (10,406) (3,524) (18,607) (34,530) (116,907) (578,119) (63,430) (748,342) CWIP Ending Balance 680,354 768,956 859,730 905,740 1,032,597 1,180,913 1,333,478 1,493,644 1,588,983 1,221,682 1,368,930 803,284

Common General PlantAFUDC CWIP Beginning Balance 3,638 17,602 41,591 79,770 127,041 28,256 25,494 23,310 21,587 24,973 28,681 32,651


Closings to Plant - (198) - (1,693) (125,482) (12,583) (14,998) (16,899) (13,654) (14,800) (15,708) (45,848) CWIP Ending Balance 17,602 41,591 79,770 127,041 28,256 25,494 23,310 21,587 24,973 28,681 32,651 5,841

Nuclear FuelAFUDC CWIP Beginning Balance 10,718,921 6,505,213 7,006,292 7,455,889 7,906,063 8,408,877 9,019,708 9,666,917 5,491,958 5,803,276 6,126,519 6,451,874


Closings to Plant (4,926,927) - - - (36,591) - - (4,641,290) - - - - CWIP Ending Balance 6,505,213 7,006,292 7,455,889 7,906,063 8,408,877 9,019,708 9,666,917 5,491,958 5,803,276 6,126,519 6,451,874 6,857,573

TotalAFUDC CWIP Beginning Balance 119,999,951 120,828,909 126,675,990 132,961,223 137,820,972 129,199,274 93,319,044 99,455,954 100,857,237 106,369,602 109,296,369 115,637,901

AFUDC Debt 1,807,833 1,808,780 1,972,286 2,057,162 2,264,145 2,324,309 2,196,259 2,137,576 2,228,675 2,332,471 2,426,076 2,167,135 AFUDC Equity 4,132,541 4,134,628 4,493,924 4,694,087 5,134,359 5,288,367 4,996,257 4,862,230 5,069,442 5,305,538 5,518,437 4,929,458

Closings to Plant (5,111,416) (96,326) (180,977) (1,891,500) (16,020,202) (43,492,906) (1,055,606) (5,598,524) (1,785,752) (4,711,243) (1,602,980) (44,009,658) CWIP Ending Balance 120,828,909 126,675,990 132,961,223 137,820,972 129,199,274 93,319,044 99,455,954 100,857,237 106,369,602 109,296,369 115,637,901 78,724,836

From P3A 1,807,833 1,808,780 1,972,286 2,057,162 2,264,145 2,324,309 2,196,259 2,137,576 2,228,675 2,332,471 2,426,076 2,167,135 From P3A 4,132,541 4,134,628 4,493,924 4,694,087 5,134,359 5,288,367 4,996,257 4,862,230 5,069,442 5,305,538 5,518,437 4,929,458

- - - - - - - - - - - - - - - - - - - - - - - -

Base No Compounding AFUDC 114,059,578 114,888,536 120,732,583 126,495,013 131,069,723 121,800,770 85,706,368 92,263,438 93,857,431 99,071,485 101,658,360 107,693,389

Simple Rates Debt/Equity

0.020285 2,313,699 2,330,514 2,449,060 2,565,951 2,658,749 2,470,729 1,738,554 1,871,564 1,903,898 2,009,665 2,062,140 2,184,560

0.047617 5,431,175 5,470,647 5,748,923 6,023,313 6,241,147 5,799,787 4,081,080 4,393,308 4,469,209 4,717,487 4,840,666 5,128,036Total AFUDC 7,744,873 7,801,161 8,197,984 8,589,264 8,899,896 8,270,516 5,819,634 6,264,872 6,373,107 6,727,152 6,902,806 7,312,596

Approximate 2013 AFUDC Approximate AFUDC No Compounding 88,903,863

Page 23 of 35

Docket No. E002/GR-12-961 Docket No. E002/GR-13-868Information Request No. OAG-70 Exhibit___(LHP-1), Appendix AAttachment ACWIP Rollforward

2014January February March April May June July August September October November December

Electric Intangible PlantAFUDC CWIP Beginning Balance 2,379,393 2,519,047 2,667,081 2,761,793 2,914,925 3,076,114 3,115,071 3,290,387 3,336,536 3,474,871 3,200,804 2,479,212


Closings to Plant (784) (768) (57,902) (2,584) (2,496) (131,060) (725) (131,701) (37,637) (440,329) (855,734) (966,148) CWIP Ending Balance 2,519,047 2,667,081 2,761,793 2,914,925 3,076,114 3,115,071 3,290,387 3,336,536 3,474,871 3,200,804 2,479,212 1,615,384

Electric Steam Production PlantAFUDC CWIP Beginning Balance 1,271,979 1,343,386 1,403,539 1,560,975 1,583,357 1,435,754 1,339,726 1,459,967 1,576,872 1,727,327 1,563,585 1,602,539


Closings to Plant (56,720) (87,170) (15,152) (171,843) (344,527) (268,503) (33,789) (54,771) (39,605) (347,431) (121,866) (129,623) CWIP Ending Balance 1,343,386 1,403,539 1,560,975 1,583,357 1,435,754 1,339,726 1,459,967 1,576,872 1,727,327 1,563,585 1,602,539 1,631,911

Electric Nuclear Production PlantAFUDC CWIP Beginning Balance 38,311,828 24,395,274 25,385,496 26,480,848 26,413,888 27,690,055 28,925,613 30,327,185 30,235,641 29,526,459 25,611,079 26,371,089

AFUDC Debt 490,542 326,881 347,087 363,181 383,315 408,700 437,082 455,371 447,684 402,791 363,308 336,727 AFUDC Equity 1,145,182 763,111 810,281 847,855 894,857 954,120 1,020,377 1,063,073 1,045,129 940,324 848,149 786,096

Closings to Plant (15,552,278) (99,770) (62,015) (1,277,997) (2,005) (127,262) (55,887) (1,609,987) (2,201,996) (5,258,496) (451,446) (2,252,261) CWIP Ending Balance 24,395,274 25,385,496 26,480,848 26,413,888 27,690,055 28,925,613 30,327,185 30,235,641 29,526,459 25,611,079 26,371,089 25,241,651

Electric Hydro Production PlantAFUDC CWIP Beginning Balance 10,638 1,602 762 0 0 0 0 0 0 0 0 0

AFUDC Debt 240 - - - - - - - - - - - AFUDC Equity 560 - - - - - - - - - - -

Closings to Plant (9,836) (839) (762) - - - - - - - - - CWIP Ending Balance 1,602 762 0 0 0 0 0 0 0 0 0 0

Electric Other Production PlantAFUDC CWIP Beginning Balance 4,302 6,317 10,522 8,929 72,682 239,214 454,648 677,339 912,411 1,151,163 1,400,464 1,629,440

AFUDC Debt 704 1,261 1,995 19,601 50,401 64,878 67,544 70,553 72,867 75,623 77,500 74,915 AFUDC Equity 1,644 2,944 4,658 45,759 117,662 151,460 157,683 164,707 170,110 176,544 180,925 174,891

Closings to Plant (333) - (8,247) (1,606) (1,530) (904) (2,536) (188) (4,225) (2,867) (29,448) (91,555) CWIP Ending Balance 6,317 10,522 8,929 72,682 239,214 454,648 677,339 912,411 1,151,163 1,400,464 1,629,440 1,787,690

Electric Transmission PlantAFUDC CWIP Beginning Balance 26,800,808 29,516,043 31,472,646 33,086,251 27,319,210 29,169,831 29,290,362 25,225,577 27,785,295 30,170,455 32,826,620 35,620,978

AFUDC Debt 827,298 891,757 927,508 893,969 857,189 847,567 790,024 774,368 804,470 822,379 844,003 781,573 AFUDC Equity 1,931,344 2,081,827 2,165,287 2,086,991 2,001,126 1,978,663 1,844,329 1,807,778 1,878,054 1,919,863 1,970,344 1,824,599

Closings to Plant (43,406) (1,016,981) (1,479,191) (8,748,001) (1,007,694) (2,705,698) (6,699,138) (22,427) (297,364) (86,077) (19,990) (7,187,061) CWIP Ending Balance 29,516,043 31,472,646 33,086,251 27,319,210 29,169,831 29,290,362 25,225,577 27,785,295 30,170,455 32,826,620 35,620,978 31,040,089

Electric Distribution PlantAFUDC CWIP Beginning Balance 1,447,611 1,588,908 1,759,790 1,954,996 2,159,311 1,180,515 1,244,510 1,348,638 1,452,669 1,572,027 1,698,419 1,834,944


Closings to Plant (79,342) (79,977) (89,811) (109,962) (1,237,729) (121,843) (84,253) (92,538) (84,873) (86,398) (81,897) (111,216) CWIP Ending Balance 1,588,908 1,759,790 1,954,996 2,159,311 1,180,515 1,244,510 1,348,638 1,452,669 1,572,027 1,698,419 1,834,944 1,945,260

Electric General PlantAFUDC CWIP Beginning Balance 831,580 890,014 950,576 979,167 1,037,181 1,097,537 1,161,065 1,226,344 1,294,312 1,364,749 1,437,129 1,510,633


Closings to Plant (1,670) (994) (32,184) (1,340) (1,378) (1,123) (1,068) (1,010) (837) (1,194) (2,199) (1,269,322) CWIP Ending Balance 890,014 950,576 979,167 1,037,181 1,097,537 1,161,065 1,226,344 1,294,312 1,364,749 1,437,129 1,510,633 281,348

Common Intangible PlantAFUDC CWIP Beginning Balance 803,284 932,847 1,009,895 939,730 1,102,708 1,287,036 1,443,115 1,661,517 1,897,655 2,124,752 2,143,384 2,182,357


Closings to Plant (22,821) (88,269) (242,243) (21,543) (21,808) (68,699) (21,971) (21,604) (46,320) (259,672) (234,017) (687,436) CWIP Ending Balance 932,847 1,009,895 939,730 1,102,708 1,287,036 1,443,115 1,661,517 1,897,655 2,124,752 2,143,384 2,182,357 1,746,956

Common General PlantAFUDC CWIP Beginning Balance 5,841 7,452 8,997 10,343 11,520 12,506 13,814 15,140 16,813 18,243 17,898 17,647


Closings to Plant (15,023) (13,544) (12,586) (12,275) (12,848) (12,950) (12,926) (11,813) (10,934) (13,791) (16,246) (18,133) CWIP Ending Balance 7,452 8,997 10,343 11,520 12,506 13,814 15,140 16,813 18,243 17,898 17,647 17,590

Nuclear FuelAFUDC CWIP Beginning Balance 6,857,573 7,339,046 7,824,008 8,327,881 8,850,607 9,378,095 9,921,612 10,486,862 6,999,709 7,397,091 7,614,632 7,835,011


Closings to Plant - - - - - - - (4,063,093) - - - - CWIP Ending Balance 7,339,046 7,824,008 8,327,881 8,850,607 9,378,095 9,921,612 10,486,862 6,999,709 7,397,091 7,614,632 7,835,011 8,355,414

AFUDC CWIP Beginning Balance 78,724,836 68,539,937 72,493,313 76,110,912 71,465,388 74,566,656 76,909,536 75,718,956 75,507,912 78,527,138 77,514,013 81,083,849 AFUDC Debt 1,678,595 1,601,936 1,684,707 1,709,879 1,719,372 1,733,658 1,715,902 1,738,807 1,722,292 1,644,353 1,614,228 1,587,094

AFUDC Equity 3,918,718 3,739,753 3,932,985 3,991,748 4,013,911 4,047,263 4,005,811 4,059,281 4,020,726 3,838,777 3,768,452 3,705,105 Closings to Plant (15,782,213) (1,388,313) (2,000,092) (10,347,151) (2,632,015) (3,438,042) (6,912,294) (6,009,132) (2,723,792) (6,496,255) (1,812,844) (12,712,756)

CWIP Ending Balance 68,539,937 72,493,313 76,110,912 71,465,388 74,566,656 76,909,536 75,718,956 75,507,912 78,527,138 77,514,013 81,083,849 73,663,293

1,678,595 1,601,936 1,684,707 1,709,879 1,719,372 1,733,658 1,715,902 1,738,807 1,722,292 1,644,353 1,614,228 1,587,094 3,918,718 3,739,753 3,932,985 3,991,748 4,013,911 4,047,263 4,005,811 4,059,281 4,020,726 3,838,777 3,768,452 3,705,105 67,193,354

- - - - - - - - - - - - 67193354.24- - - - - - - - - - - -

Base No Compounding AFUDC 71,628,243 62,942,623 67,151,624 70,493,221 65,763,761 68,833,373 71,128,614 69,997,242 69,709,824 72,784,120 72,030,883 75,701,169

Simple Rates Debt/Equity

0.020285 1,452,979 1,276,791 1,362,171 1,429,955 1,334,018 1,396,285 1,442,844 1,419,894 1,414,064 1,476,426 1,461,146 1,535,598

0.047617 3,410,722 2,997,139 3,197,559 3,356,676 3,131,473 3,277,639 3,386,931 3,333,059 3,319,373 3,465,761 3,429,895 3,604,663Total AFUDC 4,863,701 4,273,930 4,559,730 4,786,631 4,465,491 4,673,924 4,829,775 4,752,953 4,733,436 4,942,187 4,891,041 5,140,261

Approximate 2014 AFUDC Approximate AFUDC DifferenceNo Compounding 56,913,059 (10,280,295)

Page 24 of 35


Docket No. E002/GR-12-961 Information Request No. OAG-107 _________________________________________________________________

Question: Provide the 2013 average level of CWIP costs by project incurred through December 31, 2013 for projects that were still under construction on December 31, 2012. Identify the level of 2014 test year CWIP costs for these same projects. Response: Please see Attachment A to this response for the 2013 and 2014 Total Company CWIP balances for each project that was still under construction on December 31, 2013. Attachment B to this response contains the 2013 and the 2014 test year Minnesota Jurisdiction CWIP balances for each of these projects. _________________________________________________________________ Preparer: Michael Bliss / Shari Cardille Title: Analyst / Principal Rate Analyst Department: Capital Asset Accounting / Revenue Requirements North

Page 25 of 35

Docket No. E002/GR-12-961Information Request No. OAG-107Attachments A and B


NSPM Total CompanyCWIP Balances for All Projects that Had a CWIP Balance at December 31, 2013Based on Forecast Data included in the Case($)

2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average BalElectric Intangible PlantBT_Business Demand 2,397,642 999,094 1,698,368 999,094 126,393 562,743 BT_Legal/Regulatory Required 290,919 2,528,839 1,409,879 2,528,839 - 1,264,419 GIST-III TLines Computer Software 3,272,414 5,748,135 4,510,275 5,748,135 - 2,874,067 MNGP-Monticello-Regulatory 10,899,530 3,907,506 7,403,518 3,907,506 1,115,821 2,511,664 Other Capital 1,416,785 3,090,085 2,253,435 3,090,085 - 1,545,043 PI-Prairie Island-Regulatory 2,202,627 8,973,411 5,588,019 8,973,411 15,640,070 12,306,740 PI-Prairie Island-Safety - 250,013 125,007 250,013 - 125,007 Strategic Technology (CEO Only) - 48,450 24,225 48,450 51,816 50,133 Total Balance 20,479,918 25,545,533 23,012,725 25,545,533 16,934,099 21,239,816

Electric Steam Production PlantASK_Allen S King 12,420,861 2,484,382 7,452,622 2,484,382 2,646,520 2,565,451 BDS_Black Dog 30,765 152,301 91,533 152,301 2,297,158 1,224,729 Engineering and Supervision 43,605 281,223 162,414 281,223 281,223 281,223 REW_Red Wing 402,093 28,171 215,132 28,171 714,641 371,406 SHC_Sherco Common Consolidated 1,075,906 903,422 989,664 903,422 250,238 576,830 SHC_Sherco Common to Units 1 & 2 6,037,654 294,574 3,166,114 294,574 40,380 167,477 SHC_Sherco Unit 1 1,951,681 7,764,846 4,858,263 7,764,846 18,631,735 13,198,290 SHC_Sherco Unit 2 4,820,187 2,553,211 3,686,699 2,553,211 3,001,617 2,777,414 SHC_Sherco Unit 3 14,752,852 5,034,239 9,893,546 5,034,239 9,382 2,521,810 WLM_Wilmarth 331,185 1,432,638 881,911 1,432,638 1,142,424 1,287,531 Total Balance 41,866,789 20,929,007 31,397,898 20,929,007 29,015,318 24,972,162

Electric Nuclear Production PlantEngineering and Supervision 156,717 141,090 148,904 141,090 141,090 141,090 MNGP-Monticello-Facilities 2,553 619,021 310,787 619,021 102,840 360,931 MNGP-Monticello-Power Uprate 226,693,475 224,513,228 225,603,352 224,513,228 - 112,256,614 MNGP-Monticello-Regular 551,335 1,717,302 1,134,318 1,717,302 3,896,924 2,807,113 MNGP-Monticello-Regulatory 9,296,307 12,522,626 10,909,466 12,522,626 16,764,753 14,643,690 MNGP-Monticello-Safety 11,013,402 287,931 5,650,667 287,931 - 143,965 MNGP-Monti-Equipment Reliability 6,784,088 10,358,293 8,571,190 10,358,293 21,303,265 15,830,779 PI-Pr Island-Equipment Reliability 12,986,011 11,641,572 12,313,792 11,641,572 17,216,888 14,429,230 PI-Pr Island-Spent Fuel Storage 62,933,957 45,077,193 54,005,575 45,077,193 36,699,932 40,888,563 PI-Prairie Island-Facilities 303,101 1,511,868 907,485 1,511,868 - 755,934 PI-Prairie Island-Life Extension 12,333,737 78,109,009 45,221,373 78,109,009 63,836,967 70,972,988 PI-Prairie Island-Power Uprate 27,831,598 7,337,971 17,584,785 7,337,971 - 3,668,986 PI-Prairie Island-Regulatory 504,612 5,010,057 2,757,335 5,010,057 11,622,979 8,316,518 PI-Prairie Island-Safety 5,148,056 9,562,196 7,355,126 9,562,196 14,576,486 12,069,341 Total Balance 376,538,951 408,409,359 392,474,155 408,409,359 186,162,124 297,285,742

Electric Hydro Production PlantHNI_Hennepin Island 1,267,814 282,256 775,035 282,256 - 141,128 Total Balance 1,267,814 282,256 775,035 282,256 - 141,128

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2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average Bal

Electric Other Production PlantBorder Wind ND - 48,411 24,205 48,411 19,479,398 9,763,905 HBR_High Bridge 275,327 19,247 147,287 19,247 235,734 127,490 PLV_Pleasant Valley Wind - 37,821 18,910 37,821 22,976,653 11,507,237 RIV_Riverside 216,358 195,995 206,176 195,995 132,792 164,393 Total Balance 491,685 301,473 396,579 301,473 42,824,577 21,563,025

Electric Transmission PlantAPT 550 Minnesota 510,585 211,379 360,982 211,379 - 105,690 Big Stone-Brookings 345 kV Line 2,485,365 3,049,375 2,767,370 3,049,375 1,217,223 2,133,299 Black Dog - Savage 110,307 4,663,997 2,387,152 4,663,997 - 2,331,999 CAPX La Crosse (1) 18,199,953 75,939,506 47,069,730 75,939,506 76,253,622 76,096,564 CAPX2020 Brookings MN (1) 139,108,853 187,707,937 163,408,395 187,707,937 153,029,384 170,368,661 CAPX2020 Fargo MN (1) 48,377,481 125,776,143 87,076,812 125,776,143 109,522,763 117,649,453 CapX2020 Hampton Sub (1) 92,155 3,209 47,682 3,209 - 1,605 Chisago 2nd Transformer Addition 30,822 209,904 120,363 209,904 6,779,685 3,494,794 Chisago Cty 40 MVAR Inductor - 110,729 55,365 110,729 1,326,253 718,491 ELR - Breakers - NSPM 133,267 1,033,296 583,281 1,033,296 114,294 573,795 ELR - NSPM Relays RT 8,538 281,820 145,179 281,820 311,286 296,553 ELR - Relay - NSPM 99,744 1,056,493 578,118 1,056,493 196,158 626,325 Engineering and Supervision 89,949 249,206 169,577 249,206 249,206 249,206 Fault Recorders - NSPM 22,318 257,071 139,694 257,071 - 128,536 First Lake Sub - 7,930 3,965 7,930 188,659 98,295 Fort Ridgely Cap - 143,174 71,587 143,174 - 71,587 Franklin Transformer 4,152,789 7,388,151 5,770,470 7,388,151 - 3,694,075 G491 Wind Interconnect - 700,224 350,112 700,224 - 350,112 GRE Crooked Lake - Enterprise 37,652 1,768,046 902,849 1,768,046 - 884,023 Hollydale Dist.115 kV 1,411,866 2,705,044 2,058,455 2,705,044 6,193,227 4,449,136 Hwy 212 conversion 1,723,711 4,923,615 3,323,663 4,923,615 - 2,461,808 IA Tariff Fund - 1,236,697 618,349 1,236,697 1,190,232 1,213,465 Kohlman Lake Inductor 12,011 479,065 245,538 479,065 - 239,532 Kohlman Lake-Goose Lake 2nd ckt 793,915 3,818,675 2,306,295 3,818,675 3,986,305 3,902,490 Lake Marion Burnsville 243,991 2,341,354 1,292,672 2,341,354 127,977 1,234,665 Line 0840 Fiber - 253,110 126,555 253,110 - 126,555 Mallard Sub 15,027 86,758 50,893 86,758 - 43,379 Maple Lake-Annandale 69 kV Uprate - 177,573 88,786 177,573 196,787 187,180 Maple River Red River 2nd 115kV - 227,056 113,528 227,056 798,340 512,698 Midtown - Hiawatha 10,670,092 26,161,794 18,415,943 26,161,794 - 13,080,897 Minn Vly-Kerkhoven Uprate 1,274 3,587,881 1,794,577 3,587,881 - 1,793,940 NSP Line Capacity 1,337,437 2,253,241 1,795,339 2,253,241 - 1,126,620 NSPM Group 1 Switch Replacements 382,625 46,717 214,671 46,717 - 23,358 NSPM Major Line Rebuild 50,325 364,607 207,466 364,607 389,933 377,270 Prairie Sub Expansion - 4,700,542 2,350,271 4,700,542 7,553,776 6,127,159

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2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average BalRed Rock 115 kV Inductor Replmnt - 718,115 359,057 718,115 - 359,057 Relays ELR - NSPM 1,860,311 6,427,903 4,144,107 6,427,903 1,041,978 3,734,941 Riverside - Apache Upgrade - 306,544 153,272 306,544 - 153,272 S&E - NSP Sub 118,037 358,501 238,269 358,501 - 179,250 Sioux Falls Northern 115kV Loop 247,331 6,391,213 3,319,272 6,391,213 14,659,153 10,525,183 SWTC 13,455,208 621,560 7,038,384 621,560 5,643,822 3,132,691 Westgate Fault - 514,162 257,081 514,162 - 257,081 Wilmarth - TC Thru Flow Mitigation 2,907 23,225 13,066 23,225 24,834 24,029 Total Balance 245,785,846 479,282,542 362,534,194 479,282,542 390,994,898 435,138,720

Electric Distribution PlantCIAC (1,381,965) (1,363,720) (1,372,843) (1,363,720) (1,363,720) (1,363,720) Engineering and Supervision 248,502 1,932,455 1,090,479 1,932,455 1,932,455 1,932,455 Midtown-Hiawatha Rail 3,580,523 17,109,795 10,345,159 17,109,795 8,007,016 12,558,405 OH Extension 470,221 197,224 333,723 197,224 253,598 225,411 OH Rebuilds 1,528,900 808,602 1,168,751 808,602 1,887,934 1,348,268 OH Reinforcements 838,343 675,694 757,019 675,694 1,017,887 846,790 OH Relocations 3,490,336 1,961,136 2,725,736 1,961,136 1,472,001 1,716,569 OH Services - 665,657 332,828 665,657 1,038,465 852,061 OH Street Lights 332,297 22,999 177,648 22,999 74,290 48,645 Other Capital 5,524 (754,007) (374,242) (754,007) (90) (377,048) Subs Cap Reinforce 9,166,223 3,278,241 6,222,232 3,278,241 5,771,898 4,525,069 Subs Equip Replace 973,099 7,628,138 4,300,619 7,628,138 13,233,505 10,430,822 System Reliability 2,491,222 964,039 1,727,630 964,039 1,557,649 1,260,844 UG ConvrsnsRebuilds 950,316 414,708 682,512 414,708 879,631 647,170 UG Extension 1,848,511 1,094,599 1,471,555 1,094,599 1,077,914 1,086,256 UG Network 251,511 966,418 608,965 966,418 1,114,504 1,040,461 UG Reinforcements 1,704,375 537,724 1,121,049 537,724 2,294,535 1,416,130 UG Relocations (26,745) 219,606 96,430 219,606 695,431 457,518 UG Street Lights (178,757) 343,116 82,179 343,116 311,637 327,376 Total Balance 26,292,435 36,702,423 31,497,429 36,702,423 41,256,541 38,979,482

Electric General PlantBT_Critical Sys Upgrades/Rplmt(<5M) 1,003,209 1,219,542 1,111,375 1,219,542 - 609,771 BT_HW Refreshes 1,401,248 249,948 825,598 249,948 - 124,974 BT_Legal/Regulatory Required 206,178 703,491 454,835 703,491 - 351,746 BT_Other IT Infrastructure - 158,157 79,078 158,157 18,829 88,493 ET_Physical Security (CEO Only) - 23,533 11,766 23,533 13,784 18,658 Fault Recorder Upgrades - ELR 1,049,659 75,437 562,548 75,437 80,675 78,056 General Building 88,753 7,021 47,887 7,021 1,183 4,102 General Furniture 190,191 6,229 98,210 6,229 305 3,267 General Network 258,588 750,000 504,294 750,000 - 375,000 General Tools and Equipment 1,579,676 568,647 1,074,161 568,647 528,354 548,500 General Transportation 2,888,832 2,001,095 2,444,964 2,001,095 1,404,464 1,702,779

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2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average BalMI_Energy Management System 3,258,029 8,543,482 5,900,756 8,543,482 - 4,271,741 MI_Network Strategy - 409,965 204,982 409,965 546,056 478,010 PI-Prairie Island-Regulatory - 260,000 130,000 260,000 - 130,000 Total Balance 11,924,364 14,976,548 13,450,456 14,976,548 2,593,650 8,785,099

Common Intangible PlantBT_Business Demand 8,076,885 13,655,823 10,866,354 13,655,823 11,958,735 12,807,279 BT_Critical Sys Upgrades/Rplmt(<5M) 2,388,905 3,315,976 2,852,440 3,315,976 16,502,545 9,909,261 BT_IT Security 260,237 3,030,322 1,645,279 3,030,322 11,608 1,520,965 BT_Other IT Infrastructure 2,446,615 2,879,751 2,663,183 2,879,751 3,222,597 3,051,174 MI_Enterprise Asset Management - 2,677,798 1,338,899 2,677,798 8,968,461 5,823,129 Strategic Technology (CEO Only) - 198,395 99,198 198,395 54,752 126,574 Total Balance 13,172,641 25,758,064 19,465,353 25,758,064 40,718,699 33,238,381

Common General PlantBT_Business Demand 144,252 812,657 478,454 812,657 1,054,549 933,603 BT_HW Refreshes 491,924 129,979 310,951 129,979 32 65,005 BT_IT Security 7,364,053 65,313 3,714,683 65,313 215,970 140,642 BT_Other IT Infrastructure 4,383,907 1,547,340 2,965,624 1,547,340 92,137 819,738 ET_Physical Security (CEO Only) - 17,098 8,549 17,098 13,129 15,113 General Building 863,276 3,028,289 1,945,782 3,028,289 3,261,949 3,145,119 General Furniture 73,918 (714) 36,602 (714) 25,299 12,293 General Tools and Equipment 140,345 241,699 191,022 241,699 238,716 240,207 General Transportation 615,926 193,742 404,834 193,742 92,794 143,268 Total Balance 14,077,602 6,035,403 10,056,502 6,035,403 4,994,574 5,514,988

Nuclear FuelNFC-Nuc Fuel Commodity-Conversion 5,539,551 4,160,074 4,849,813 4,160,074 10,322,238 7,241,156 NFC-Nuc Fuel Commodity-Enrichment 35,714,455 28,844,859 32,279,657 28,844,859 36,625,758 32,735,309 NFC-Nuc Fuel Commodity-Uranium 89,134,969 51,669,679 70,402,324 51,669,679 116,658,497 84,164,088 NFM-Nuc Fuel-Monticello 9,576,766 8,958,555 9,267,661 8,958,555 (7,535,313) 711,621 NFP-1-Nuc Fuel-PI Unit 1 5,113 176,673 90,893 176,673 22,844 99,759 Total Balance 139,970,854 93,809,841 116,890,347 93,809,841 156,094,025 124,951,933

Total Electric and Common Balance 891,868,898 1,112,032,448 1,001,950,673 1,112,032,448 911,588,505 1,011,810,477

Notes(1) Removed in Adjustment Remove Riders - TCR, Volume 4 Test Year Workpapers

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NSPM - Minnesota JurisdictionCWIP Balances for All Projects that Had a CWIP Balance at December 31, 2013Based on Forecast Data included in the Case($)

2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average Bal AllocatorElectric Intangible Plant Minnesota ElectricBT_Business Demand 2,101,862 875,843 1,488,853 875,843 110,801 493,322 Intangible Composite 87.6637%BT_Legal/Regulatory Required 255,031 2,216,875 1,235,953 2,216,875 - 1,108,437 GIST-III TLines Computer Software 2,868,721 5,039,030 3,953,876 5,039,030 - 2,519,515 MNGP-Monticello-Regulatory 9,554,936 3,425,466 6,490,201 3,425,466 978,170 2,201,818 Other Capital 1,242,006 2,708,884 1,975,445 2,708,884 - 1,354,442 PI-Prairie Island-Regulatory 1,930,906 7,866,428 4,898,667 7,866,428 13,710,671 10,788,549 PI-Prairie Island-Safety - 219,171 109,585 219,171 - 109,585 Strategic Technology (CEO Only) - 42,473 21,237 42,473 45,424 43,949 Total Balance 17,953,463 22,394,170 20,173,816 22,394,170 14,845,065 18,619,618

Electric Steam Production PlantASK_Allen S King 9,233,652 1,846,887 5,540,269 1,846,887 1,967,419 1,907,153 IA Demand 87.6729%BDS_Black Dog 22,870 113,220 68,045 113,220 1,707,704 910,462 MN Demand 84.7923%Engineering and Supervision 32,416 209,061 120,738 209,061 209,061 209,061 MN Jur Demand after IA 74.3399%REW_Red Wing 298,915 20,942 159,929 20,942 531,263 276,103 SHC_Sherco Common Consolidated 799,827 671,603 735,715 671,603 186,027 428,815 SHC_Sherco Common to Units 1 & 2 4,488,384 218,986 2,353,685 218,986 30,019 124,502 SHC_Sherco Unit 1 1,450,877 5,772,376 3,611,626 5,772,376 13,850,807 9,811,592 SHC_Sherco Unit 2 3,583,321 1,898,054 2,740,687 1,898,054 2,231,398 2,064,726 SHC_Sherco Unit 3 10,967,251 3,742,447 7,354,849 3,742,447 6,975 1,874,711 WLM_Wilmarth 246,202 1,065,021 655,612 1,065,021 849,277 957,149 Total Balance 31,123,716 15,558,596 23,341,156 15,558,596 21,569,949 18,564,273

Electric Nuclear Production PlantEngineering and Supervision 116,503 104,886 110,695 104,886 104,886 104,886 IA Demand 87.6729%MNGP-Monticello-Facilities 1,898 460,180 231,039 460,180 76,451 268,315 MN Demand 84.7923%MNGP-Monticello-Power Uprate 168,523,631 166,902,838 167,713,235 166,902,838 - 83,451,419 MN Jur Demand after IA 74.3399%MNGP-Monticello-Regular 409,862 1,276,640 843,251 1,276,640 2,896,968 2,086,804 MNGP-Monticello-Regulatory 6,910,862 9,309,304 8,110,083 9,309,304 12,462,895 10,886,100 MNGP-Monticello-Safety 8,187,349 214,047 4,200,698 214,047 - 107,024 MNGP-Monti-Equipment Reliability 5,043,282 7,700,341 6,371,812 7,700,341 15,836,819 11,768,580 PI-Pr Island-Equipment Reliability 9,653,784 8,654,329 9,154,056 8,654,329 12,799,012 10,726,671 PI-Pr Island-Spent Fuel Storage 46,785,021 33,510,326 40,147,673 33,510,326 27,282,681 30,396,504 PI-Prairie Island-Facilities 225,325 1,123,921 674,623 1,123,921 - 561,961 PI-Prairie Island-Life Extension 9,168,884 58,066,135 33,617,509 58,066,135 47,456,317 52,761,226 PI-Prairie Island-Power Uprate 20,689,974 5,455,038 13,072,506 5,455,038 - 2,727,519 PI-Prairie Island-Regulatory 375,128 3,724,470 2,049,799 3,724,470 8,640,507 6,182,489 PI-Prairie Island-Safety 3,827,058 7,108,524 5,467,791 7,108,524 10,836,141 8,972,332 Total Balance 279,918,560 303,610,980 291,764,770 303,610,980 138,392,678 221,001,829

Electric Hydro Production Plant IA Demand 87.6729%HNI_Hennepin Island 942,491 209,829 576,160 209,829 - 104,914 MN Demand 84.7923%Total Balance 942,491 209,829 576,160 209,829 - 104,914 MN Jur Demand after IA 74.3399%

Electric Other Production PlantBorder Wind ND (3) - 37,168 18,584 37,168 14,955,459 7,496,313 IA Demand 87.6729%HBR_High Bridge (2) 204,678 14,308 109,493 14,308 175,244 94,776 MN Demand 84.7923%

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2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average Bal AllocatorPLV_Pleasant Valley Wind (3) - 29,037 14,519 29,037 17,640,503 8,834,770 MN Jur Demand after IA (2) 74.3399%RIV_Riverside (2) 160,840 145,702 153,271 145,702 98,717 122,210 IA Demand 87.6729%Total Balance 365,518 226,215 295,867 226,215 32,869,923 16,548,069 Energy 87.5707%

MN Jur Energy after IA (3) 76.7758%Electric Transmission PlantAPT 550 Minnesota 379,568 157,139 268,354 157,139 - 78,569 IA Demand 87.6729%Big Stone-Brookings 345 kV Line 1,847,617 2,266,901 2,057,259 2,266,901 904,882 1,585,892 MN Demand 84.7923%Black Dog - Savage 82,002 3,467,210 1,774,606 3,467,210 - 1,733,605 MN Jur Demand after IA 74.3399%CAPX La Crosse (1) 13,529,821 56,453,329 34,991,575 56,453,329 56,686,842 56,570,086 CAPX2020 Brookings MN (1) 103,413,338 139,541,833 121,477,586 139,541,833 113,761,843 126,651,838 CAPX2020 Fargo MN (1) 35,963,756 93,501,819 64,732,787 93,501,819 81,419,078 87,460,449 CapX2020 Hampton Sub (1) 68,508 2,386 35,447 2,386 - 1,193 Chisago 2nd Transformer Addition 22,913 156,042 89,477 156,042 5,040,009 2,598,025 Chisago Cty 40 MVAR Inductor - 82,316 41,158 82,316 985,935 534,125 ELR - Breakers - NSPM 99,070 768,151 433,611 768,151 84,966 426,559 ELR - NSPM Relays RT 6,347 209,505 107,926 209,505 231,409 220,457 ELR - Relay - NSPM 74,150 785,395 429,772 785,395 145,823 465,609 Engineering and Supervision 66,868 185,260 126,064 185,260 185,260 185,260 Fault Recorders - NSPM 16,591 191,106 103,849 191,106 - 95,553 First Lake Sub - 5,895 2,947 5,895 140,249 73,072 Fort Ridgely Cap - 106,436 53,218 106,436 - 53,218 Franklin Transformer 3,087,178 5,492,341 4,289,760 5,492,341 - 2,746,171 G491 Wind Interconnect - 520,546 260,273 520,546 - 260,273 GRE Crooked Lake - Enterprise 27,990 1,314,363 671,177 1,314,363 - 657,182 Hollydale Dist.115 kV 1,049,579 2,010,926 1,530,253 2,010,926 4,604,037 3,307,482 Hwy 212 conversion 1,281,404 3,660,209 2,470,807 3,660,209 - 1,830,105 IA Tariff Fund - 919,359 459,680 919,359 884,817 902,088 Kohlman Lake Inductor 8,929 356,136 182,533 356,136 - 178,068 Kohlman Lake-Goose Lake 2nd ckt 590,195 2,838,798 1,714,496 2,838,798 2,963,414 2,901,106 Lake Marion Burnsville 181,383 1,740,559 960,971 1,740,559 95,138 917,849 Line 0840 Fiber - 188,162 94,081 188,162 - 94,081 Mallard Sub 11,171 64,496 37,834 64,496 - 32,248 Maple Lake-Annandale 69 kV Uprate - 132,007 66,004 132,007 146,291 139,149 Maple River Red River 2nd 115kV - 168,793 84,397 168,793 593,485 381,139 Midtown - Hiawatha 7,932,132 19,448,643 13,690,388 19,448,643 - 9,724,322 Minn Vly-Kerkhoven Uprate 947 2,667,226 1,334,086 2,667,226 - 1,333,613 NSP Line Capacity 994,249 1,675,056 1,334,653 1,675,056 - 837,528 NSPM Group 1 Switch Replacements 284,443 34,729 159,586 34,729 - 17,365 NSPM Major Line Rebuild 37,412 271,048 154,230 271,048 289,876 280,462 Prairie Sub Expansion - 3,494,377 1,747,189 3,494,377 5,615,467 4,554,922 Red Rock 115 kV Inductor Replmnt - 533,846 266,923 533,846 - 266,923 Relays ELR - NSPM 1,382,953 4,778,495 3,080,724 4,778,495 774,605 2,776,550 Riverside - Apache Upgrade - 227,885 113,942 227,885 - 113,942 S&E - NSP Sub 87,748 266,509 177,129 266,509 - 133,255 Sioux Falls Northern 115kV Loop 183,865 4,751,219 2,467,542 4,751,219 10,897,595 7,824,407 SWTC 10,002,584 462,067 5,232,326 462,067 4,195,610 2,328,838 Westgate Fault - 382,227 191,114 382,227 - 191,114 Wilmarth - TC Thru Flow Mitigation 2,161 17,265 9,713 17,265 18,462 17,863

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2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average Bal AllocatorTotal Balance 182,716,874 356,298,011 269,507,442 356,298,011 290,665,093 323,481,552

Electric Distribution PlantCIAC (1,381,965) (1,363,720) (1,372,843) (1,363,720) (1,363,720) (1,363,720) Direct Assigned By StateEngineering and Supervision 248,502 1,932,455 1,090,479 1,932,455 1,932,455 1,932,455 Midtown-Hiawatha Rail 3,580,523 17,109,795 10,345,159 17,109,795 8,007,016 12,558,405 OH Extension 238,102 151,007 194,554 151,007 174,813 162,910 OH Rebuilds 1,399,977 630,012 1,014,994 630,012 1,730,926 1,180,469 OH Reinforcements 737,032 499,403 618,218 499,403 810,853 655,128 OH Relocations 3,446,706 1,721,722 2,584,214 1,721,722 1,319,284 1,520,503 OH Services - 665,657 332,828 665,657 1,038,465 852,061 OH Street Lights 316,798 19,513 168,156 19,513 62,252 40,883 Other Capital 5,524 (754,007) (374,242) (754,007) (90) (377,048) Subs Cap Reinforce 8,606,381 1,367,968 4,987,174 1,367,968 2,175,492 1,771,730 Subs Equip Replace 973,099 7,628,138 4,300,619 7,628,138 13,233,505 10,430,822 System Reliability 2,354,818 904,875 1,629,847 904,875 1,454,582 1,179,728 UG ConvrsnsRebuilds 715,692 378,050 546,871 378,050 823,333 600,692 UG Extension 826,755 934,631 880,693 934,631 910,303 922,467 UG Network 251,511 966,418 608,965 966,418 1,114,504 1,040,461 UG Reinforcements 1,416,547 448,739 932,643 448,739 206,409 327,574 UG Relocations (138,905) 202,960 32,028 202,960 682,054 442,507 UG Street Lights (180,340) 336,639 78,149 336,639 302,906 319,773 Total Balance 23,416,757 33,780,256 28,598,507 33,780,256 34,615,342 34,197,799

Electric General Plant Minnesota ElectricBT_Critical Sys Upgrades/Rplmt(<5M) 878,636 1,068,106 973,371 1,068,106 - 534,053 General Composite 87.5825%BT_HW Refreshes 1,227,248 218,911 723,080 218,911 - 109,455 BT_Legal/Regulatory Required 180,576 616,135 398,356 616,135 - 308,068 BT_Other IT Infrastructure - 138,518 69,259 138,518 16,491 77,505 ET_Physical Security (CEO Only) - 20,611 10,305 20,611 12,072 16,341 Fault Recorder Upgrades - ELR 919,318 66,070 492,694 66,070 70,657 68,363 General Building 77,732 6,149 41,941 6,149 1,036 3,593 General Furniture 166,574 5,456 86,015 5,456 267 2,862 General Network 226,478 656,869 441,674 656,869 - 328,435 General Tools and Equipment 1,383,520 498,036 940,778 498,036 462,745 480,391 General Transportation 2,530,113 1,752,610 2,141,361 1,752,610 1,230,065 1,491,337 MI_Energy Management System 2,853,465 7,482,599 5,168,032 7,482,599 - 3,741,299 MI_Network Strategy - 359,057 179,529 359,057 478,250 418,654 PI-Prairie Island-Regulatory - 227,715 113,857 227,715 - 113,857 Total Balance 10,443,661 13,116,841 11,780,251 13,116,841 2,271,584 7,694,212

Common Intangible Plant MN Electric CommonBT_Business Demand 5,939,382 10,041,885 7,990,633 10,041,885 8,793,922 9,417,903 Intangible Composite 87.5528%BT_Critical Sys Upgrades/Rplmt(<5M) 1,756,695 2,438,421 2,097,558 2,438,421 12,135,238 7,286,830 BT_IT Security 191,367 2,228,364 1,209,865 2,228,364 8,536 1,118,450 Electric GasBT_Other IT Infrastructure 1,799,132 2,117,641 1,958,386 2,117,641 2,369,755 2,243,698 Common Software 83.99% 16.01%MI_Enterprise Asset Management - 1,969,134 984,567 1,969,134 6,595,007 4,282,071 Strategic Technology (CEO Only) - 145,891 72,946 145,891 40,262 93,077

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2013 Beg Bal 2013 End Bal 2013 Average Bal 2014 Beg Bal 2014 End Bal 2014 Average Bal AllocatorTotal Balance 9,686,575 18,941,336 14,313,955 18,941,336 29,942,721 24,442,028

Common General Plant MN Electric CommonBT_Business Demand 117,010 659,190 388,100 659,190 855,401 757,295 General Composite 87.6100%BT_HW Refreshes 399,026 105,433 252,229 105,433 26 52,729 BT_IT Security 5,973,379 52,979 3,013,179 52,979 175,185 114,082 3 Factor Electric GasBT_Other IT Infrastructure 3,556,022 1,255,130 2,405,576 1,255,130 74,737 664,934 Common General 92.5869% 7.4131%ET_Physical Security (CEO Only) - 13,869 6,934 13,869 10,650 12,259 General Building 700,249 2,456,408 1,578,329 2,456,408 2,645,942 2,551,175 General Furniture 59,959 (579) 29,690 (579) 20,521 9,971 General Tools and Equipment 113,841 196,055 154,948 196,055 193,635 194,845 General Transportation 499,611 157,155 328,383 157,155 75,270 116,212 Total Balance 11,419,098 4,895,639 8,157,369 4,895,639 4,051,367 4,473,503

Nuclear FuelNFC-Nuc Fuel Commodity-Conversion 4,118,095 3,092,594 3,605,344 3,092,594 7,673,538 5,383,066 IA Demand 87.6729%NFC-Nuc Fuel Commodity-Enrichment 26,550,079 21,443,230 23,996,654 21,443,230 27,227,541 24,335,385 MN Demand 84.7923%NFC-Nuc Fuel Commodity-Uranium 66,262,819 38,411,171 52,336,995 38,411,171 86,723,773 62,567,472 MN Jur Demand after IA 74.3399%NFM-Nuc Fuel-Monticello 7,119,355 6,659,778 6,889,567 6,659,778 (5,601,742) 529,018 NFP-1-Nuc Fuel-PI Unit 1 3,801 131,338 67,570 131,338 16,982 74,160 Total Balance 104,054,148 69,738,112 86,896,130 69,738,112 116,040,092 92,889,102

Total Electric and Common Balance 672,040,861 838,769,984 755,405,423 838,769,984 685,263,815 762,016,900

Notes(1) Removed in Adjustment Remove Riders - TCR, Volume 4 Test Year Workpapers

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Docket No. E002/GR-12-961 Information Request No. XLI-206 __________________________________________________________________

Question: The XLI 200 series relates to the testimony of Lisa Perkett: Please provide a listing of all NSP generating units with their in-service date, retirement date associated with their approved remaining life and retirement date associated with the proposed remaining life in Docket E, G002/D-12-151. Response: Please see Attachment A for a listing of the in-service dates, retirement dates based on approved remaining lives, and retirement dates based on proposed remaining lives for all NSP-MN generating units. __________________________________________________________________ Preparer: Brandon Kirschner Title: Senior Accounting Analyst Department: Capital Asset Accounting

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Docket No. E002/GR-12-961 Docket No. E002/GR-13-868Information Request No. DOC-168Attachment A

Exhibit___(LHP-1), Appendix A

Generating UnitIn-Service

YearApproved

Retirement DateProposed

Retirement Date

Steam ProductionBlack Dog Unit 3 1955 December 2015 December 2015Black Dog Unit 4 1960 December 2015 December 2015Allen S. King 2007 July 2037 July 2037Minnesota Valley 1953 June 2017 December 2012Red Wing 1949 December 2017 December 2017Sherco Unit 1 1976 December 2022 December 2022Sherco Unit 2 1977 December 2022 December 2022Sherco Unit 3 1987 December 2034 December 2034Wilmarth Unit 1 1948 December 2017 December 2017Wilmarth Unit 2 1951 December 2017 December 2017

Nuclear ProductionMonticello 1971 September 2030 September 2030Prairie Island Unit 1 1973 August 2033 August 2033Prairie Island Unit 2 1974 October 2034 October 2034

Hydro ProductionHennepin Island 2001 February 2034 February 2034Lower Dam 1895 February 2034 February 2034Upper Dam 1954 February 2034 February 2034

Other ProductionAngus C. Anson Units 2&3 1994 October 2019 October 2019Angus C. Anson Unit 4 2005 May 2035 May 2035Black Dog Unit 5 2002 December 2031 December 2031Blue Lake Units 1-4 1974 December 2012 December 2012Blue Lake Units 7&8 2005 May 2035 May 2035Grand Meadow 2008 November 2033 November 2033Granite City 1969 May 2019 May 2019High Bridge 2008 May 2048 May 2048Inver Hills 1972 December 2026 December 2026Key City 1970 December 2012 December 2012Nobles 2009 December 2035 December 2035Riverside 2009 March 2049 March 2049

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1 of 7 - depreciation and remaining lives - perkett testimony

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