Rebuttal Testimony and Schedules Karen L. Everson ... - Xcel Energy

Table of ContentsI. Introduction and Qualifications 1II. Deferral and Amortization Accounting Method 2III. 2011 Test Year Nuclear Outage Amortization Expense 5IV. Response to OAG Recommendations 7V. 2012 Step-in Nuclear Outage Amortization Expense 11VI. Conclusion 13SchedulesResume Schedule 1Planned Major Maintenance – Nuclear Refueling Outage Schedule 2PolicyInformation Request OAG-120 Schedule 3i Docket No. E002/GR-10-971Everson Rebuttal

1I. INTRODUCTION AND QUALIFICATIONS234567Q. PLEASE STATE YOUR NAME AND OCCUPATION.A. My name is Karen L. Everson. I am employed by Xcel Energy Services Inc.(“XES”), which provides services to Northern States Power Company, aMinnesota corporation (“Xcel Energy” or the “Company”). I am theDirector, Utility Accounting for Xcel Energy Services Inc. (“XES”).891011Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE.A. I have more than seventeen years of employment experience with Xcel EnergyServices and Northern States Power Company. I have been the Director,121314Utility Accounting since March 2010.Exhibit___(KLE-1), Schedule 1.My resume is included as151617181920212223242526Q. HAVE YOU PREVIOUSLY PROVIDED TESTIMONY IN THIS PROCEEDING?A. No, I have not filed previous testimony in this proceeding.Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?A. I will explain the accounting for nuclear outage costs under the deferral andamortization method approved by the Minnesota Public Utilities Commission(“Commission”) in Docket No. E002/M-07-1489 and reaffirmed in our lastelectric rate case, Docket No. E002/GR-08-1065. I will also discuss thenuclear outage amortization expense included in the 2011 test year and theincrease in outage expense for 2012 and respond to issues raised by Mr. JohnLindell, witness for the Residential and Small Business Utilities Division of theMinnesota Office of the Attorney General (“OAG”).1 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627II. DEFERRAL AND AMORTIZATION ACCOUNTING METHODQ. PLEASE EXPLAIN THE DEFERRAL AND AMORTIZATION METHOD FOR NUCLEAROUTAGE COSTS.A. In Docket No. E002/M-07-1489, the Company filed a petition to change theaccounting method for costs associated with routine nuclear refueling outagesat its nuclear plants from the direct expense method to the deferral andamortization method. Under the deferral and amortization method, therefueling outage costs are deferred and amortized during the period betweenrefueling outages as opposed to expensing the costs as incurred. TheCommission approved the Company’s request effective January 1, 2008 in itsOrder dated September 16, 2008. The Company made similar filings with theNorth Dakota Public Service Commission and the South Dakota PublicUtilities Commission and received similar approvals to change its accounting.Q. WHAT COSTS ARE DEFERED UNDER THE DEFERRAL AND AMORTIZAITONACCOUNTING METHOD?A. The deferral and amortization method of accounting only includes those costsdirectly associated with a planned refueling outage. All other non-outageactivities, albeit done at the time of the outage, are directly charged to theappropriate Operating and Maintenance (“O&M”) or Capital account as hasbeen traditionally done. The deferral and amortization method does notinclude costs incurred during unplanned outages and such costs continue to beexpensed as incurred. An accounting policy document was created to ensurecorrect and consistent accounting and application of the deferral andamortization method.2 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627Q. HOW ARE THE COSTS TO BE AMORTIZED EACH YEAR UNDER THE DEFERRALAND AMORTIZATION METHOD CALCULATED?A. Refueling outage costs are deferred and amortized in accordance with theuniform policy “Planned Major Maintenance – Nuclear Refueling Outage”filed with the Commission in Docket No. E002/M-07-1489, included asExhibit___(KLE-1), Schedule 2. Refueling outage costs meeting the criteriafor deferral are identified in the month-end general ledger close process andaccounting entries are made to remove the costs from the applicable nuclearFERC O&M account and to record those costs to a Regulatory Asset accounton the balance sheet. As all outage costs are not known at the time the unitcomes back on-line from the outage, the policy provides for a three-monthperiod to finalize the costs to be deferred, and no additional amounts aredeferred after that three-month period. Once the unit returns on-line, theamortization period is determined by the expected time between refuelingoutages. The period will vary based on the refueling outage schedules, but willgenerally range between 18 – 24 months. Typically, the duration will be closerto 22 – 24 months for Monticello and 18 – 20 months for Prairie Island. Inthe unusual event that the outage schedules are changed after beingestablished and it causes the outage to cross into another month, theamortization period will be adjusted prospectively so that all costs for theoutage are fully amortized the month prior to the unit coming back on-linefrom the next outage.Q. WHAT ARE THE BENEFFITS OF THE DEFERRAL AND AMORTIZATIONACCOUNTING METHOD?A. The deferral and amortization method of accounting for refueling outage costsprovides several benefits over the direct expense method. Significant dollar3 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627amounts are incurred during a refueling outage. Instead of expensing thesecosts over the one- or two-month outage period, the costs are spread over theperiod that the customers receive the benefits of the expenses. Includingthese levelized costs in ratemaking better matches the customer benefit withthe rates being paid. These refueling outage costs also continue to be subjectto review for reasonableness during rate proceedings.Q. IS THIS AN ACCEPTED METHOD TO RECOVER COSTS?A. Yes. The Uniform System of Accounts establishes the general standard thatexpenses should be recorded in the year in which they are experienced andMinn. R. 7825.0300, subp. 4 provides that the Company can petition theCommission for approval of an exception and that the exception shall begranted for good cause shown. The Commission found the Company hadadequately demonstrated good cause for deferral in Docket No. E002/M-07-1428.Q. DOES THE COMPANY EARN A RETURN ON OUTAGE COSTS UNDER THEDEFERRAL AND AMORTIZATION METHOD?A. The Company applies a return to the unamortized balance net of accumulateddeferred income taxes. We believe that it is reasonable to include nuclearoutage revenues and expenses in rate base to either compensate customers forthe use of their money or compensate the Company for expending funds andamortizing the cost over the 18- to 24-month period, similar to capitalizedprojects. In the case of the revenues, the Commission, in its NuclearRefueling Outage Accounting Order, required the Company to defer from2008 and amortize in the 2009 test year rate case the difference between theamount of outage expense included in base rates ($25,139,022) and the post4 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627implementation 2008 outage cost amortization level ($11,376,130). TheCompany had use of the funds collected in revenues and believed it wasappropriate to calculate a return on the unamortized test year balance to returnto customers a credit for the use of the money collected.In the case of the outage expense, the Company incurs the cost at the time ofthe outage. This cost is capitalized like plant, and amortized over the 18- to24-month period until the next outage. As the Company has alreadyexpended the funds for the outage, similar to purchasing nuclear fuel or acapital addition, the Company should earn a return on the unamortizedbalance net of accumulated deferred income taxes. In the case of accumulateddeferred taxes, the Company claims a tax deduction as the outage costs areincurred. The Company also records a deferred tax expense, based on thedifference between outage costs incurred and the recorded amortizationexpense. As the Company has use of the value of the deduction in advance ofrecording the book expense, customers are entitled to a rate base offset,provided the Company is earning a return on this difference.III. 2011 TEST YEAR NUCLEAR OUTAGE AMORTIZATIONEXPENSEQ. DID THE COMPANY MAKE AN ADJUSTMENT TO OUTAGE AMORTIZATIONEXPENSE AS PART OF ITS REBUTTAL TESTIMONY?A. Yes, as discussed in the Rebuttal Testimony of Company witness Ms. Anne E.Heuer, outage costs for the 2010 bridge year have been adjusted to remove$477,000 of costs related to a reactor cavity leakage issue at Prairie Island Unit2 that was subsequently moved from O&M to capital. This adjustment had5 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627the effect of reducing total nuclear outage amortization expense in the 2011test year from $59.2 million to $59.0 million. Because only two months ofamortization expense occurs in 2012 for the 2010 Prairie Island Unit 2 outage,nuclear outage amortization expense for 2012 remained approximately $64.5millionQ. PLEASE EXPLAIN THE 2011 TEST YEAR NUCLEAR OUTAGE AMORTIZATIONEXPENSE.A. Total adjusted nuclear outage amortization expense is $59.0 million in the2011 test year, which is made up of $20.0 million amortization expense atPrairie Island Unit 1, $19.8 million amortization expense at Prairie Island Unit2, and $19.2 million amortization expense at Monticello. The $20.0 millionamortization expense at Prairie Island Unit 1 represents the remaining fivemonths of amortization from the outage completed November 2009 andseven months of amortization for the outage that will be completed June 2011.The $19.8 million amortization expense at Prairie Island Unit 2 representstwelve months of amortization from the outage completed May 2010. Finally,the $19.2 million amortization expense at Monticello represents the remainingfour months of amortization from the outage completed May 2009 and eightmonths of amortization from the outage that will be completed May 2011.The above amortization expense amounts are on a total NSPM companybasis. The test year revenue requirements associated with these expenses arereflected in the Direct Testimony of Ms. Heuer, Exhibit___(AEH-1),Schedule 3b.Q. WHAT ARE THE PRIMARY DRIVERS OF THE INCREASE IN THE 2011 TEST YEAROUTAGE AMORTIZATION EXPENSE?6 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627A. The primary driver of the increase in the 2011 test year outage amortizationexpense over the 2009 test year amount relates to a higher cost per outageused to calculate the 2011 amortization expense over the 2009 test year costper outage. The drivers of the increased outage costs for 2011 are explainedby Company witness Mr. Dennis L. Koehl on pages 12-13 of his DirectTestimony.IV. RESPONSE TO OAG RECOMMENDATIONSQ. HAS ANY OTHER PARTY PRESENTED ANOTHER ACCOUNTING TREATMENT FOROUTAGE COSTS IN THIS PROCEEDING?A. Yes. OAG witness Mr. Lindell presented an alternative accounting treatmentfor nuclear outage costs. Mr. Lindell recommends incorporating a four-yearaverage of outage costs from 2008 – 2011 in the test year for purposes ofsetting rates.Q. DO YOU AGREE WITH MR. LINDELL’S PROPOSAL?A. No. While providing a method to smooth the outage costs, Mr. Lindell’shistoric approach does not match the costs incurred with the period thatcustomers benefit from the costs – specifically, the period during which theplants produce energy from the reloaded fuel. Further, Mr. Lindell’s methoddoes not address instances where outage costs may be directionally trendingupward or downward. In cases where outage costs are rising due to moreextensive refueling outages related to life extension and power uprates at theunits, Mr. Lindell’s method will result in the Company not recovering its costs.Similarly, Mr. Lindell’s method will result in the Company over-recovering itscosts should the outage costs be declining.7 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627Q. HOW DOES MR. LINDELL’S PROPOSAL COMPARE TO THE COMPANY’SPROPOSAL TO CONTINUE TO USE THE DEFERRAL AND AMORTIZATIONMETHOD?A. On page 21 of his Direct Testimony, Mr. Lindell offers a comparison of theoutage costs proposed to be included in the test year under the OAGhistorical average method and the deferral and amortization method. Mr.Lindell’s method results in a $1.2 million lower revenue requirement than theCompany’s recommendation.Q. DO YOU AGREE WITH MR. LINDELL’S DISCUSSION OF HOW THE DEFERRAL ANDAMORTIZATION METHOD WORKS?A. No. Mr. Lindell’s statement on page 21 of his Direct Testimony that theCompany uses a four-year amortization period for an 18-month refueling cycleis incorrect. Mr. Lindell makes a similar reference on page 17 to the deferraland amortization method incorporating expenses over a four-year historicalperiod. In the Company’s 2009 test year electric rate case, the Commissionhad directed a four-year amortization period of the 2008 revenues that werecollected from customers in excess of the 2008 transition year amortizationexpense, as discussed by Ms. Heuer in her Direct Testimony,Exhibit___(AEH-1) on page 151. The last of the revenue amortization costsare included in 2012. Since inception, the amortization period for outageexpenses has been determined by the time between refueling outages, whichgenerally ranges between 18 – 24 months.Q. HOW DO THE 2011 TEST YEAR AND 2012 OUTAGE EXPENSES AS CALCULATEDUNDER THE DEFERRAL AND AMORTIZATION METHOD COMPARE TO THE8 Docket No. E002/GR-10-971Everson Rebuttal

1234567891011121314151617181920212223242526EXPENSE THAT WOULD OCCUR IF THE COMPANY RETURNED TO THE DIRECTEXPENSE METHOD?A. Costs under the deferral and amortization method for 2011 and 2012 arelower than total costs under the direct expense method. A comparison ofthese methods for the Minnesota jurisdiction was provided in our response toInformation Request (“IR”) OAG-120, attached as Exhibit___(KLE-1),Schedule 3. On a total company basis, outage costs under the direct expensemethod would be $65.4 million in 2011 and $83.8 million in 2012. Nuclearoutage amortization expense under the deferral and amortization method in2011 is $59.0 million and in 2012 is $64.5 million.Mr. Lindell’s recommendation to use a four-year average based on three yearsof historical costs and one year of forecast cost is not logical when it is knownthat costs will be increasing, especially when 2012 costs are forecasted toincrease well beyond the 2011 outage cost amount. Additionally, should theCompany be required to revert back to the direct expense method, therewould still be a need to amortize existing deferred amounts as the Companywas recording this regulatory asset pursuant to a Commission approved orderand amortization of these deferred amounts, in addition to recovery of currentyear outage costs, would significantly increase the test year deficiency.While overall nuclear outage costs have increased, the deferral andamortization method levels the costs over time instead of being fully reflectedin expense in the year of the outage. Also for ratemaking, the amount ofnuclear outage amortization expense under the deferral and amortizationmethod is more stable than costs under the direct expense method which can9 Docket No. E002/GR-10-971Everson Rebuttal

1234567891011121314151617181920212223242526fluctuate greatly depending on the number of outages planned for the year andthe scope of outage work.Q. DOES MR. LINDELL ALSO COMPARE THE DEFERRAL AND AMORTIZATIONMETHOD TO THE DIRECT EXPENSE METHOD?A. Yes. Mr. Lindell, on page 16 of his Direct Testimony, states that once thecosts are deferred and then amortized, there is a presumption that the costsare prudent and will be recovered. Mr. Lindell explains that in a rate casesetting under the direct expense method, the refueling costs would bereviewed for reasonableness and prudence.Q. WHAT IS YOUR REPLY TO MR. LINDELL’S COMPARISON?A. While deferral creates a regulatory asset, we have no greater expectation thatthese costs will be found prudent for recovery in a rate case than under thedirect expense approach. If anything, deferral has resulted in additionalscrutiny of these costs. In compliance with the Commission’s September 16,2008 Order Approving Change In Accounting Methodology With Conditionsin Docket E002/M-07-1489 (“Nuclear Refueling Outage Accounting Order”),we are now required to make an annual compliance filing that provides ouroutage costs and compares those costs using the direct expense method ofaccounting to the deferral and amortization method of accounting.Compliance also requires that we engage our external auditor, Deloitte, toreview the Company’s compliance with the deferral and amortization methodfor our nuclear refueling outage costs. We included this compliance reporting,including the Deloitte report, in our Electric Jurisdictional Annual Report tothe Office of Energy Security (“OES”) for the calendar year 2008 filed May 1,10 Docket No. E002/GR-10-971Everson Rebuttal

1234567891011121314151617181920212223242526272009, for the calendar year 2009 filed May 28, 2010, and for the calendar year2010 filed May 2, 2011.Q. ARE THESE AMOUNTS EASILY UNDERSTOOD AND VERIFIABLE?A. We appreciate the OAG’s statement that the amounts to be calculated arecomplicated. However, because we file these costs each year, we are able toprovide an additional level of transparency and review that would nototherwise occur. The deferral and amortization amounts in the attachment toIR OAG-120 for the years 2008 – 2010 agree back to the Company’s annualcompliance filing prior to the application of the jurisdictional allocators. Thecalculation on the attachment to IR OAG-120 follows the standard revenuerequirements calculation and is in the same format as was included in our lastrate case.Mr. Lindell notes that the calculation of the revenue requirement for 2009 inour response to IR OAG-120 does not match the revenue requirement for2009 as provided in the last case, Docket No. E002/GR-08-1065. Thecalculations should not match for two basic reasons. First, the informationused in the 2009 rate case application was a projected test year, and the 2009information presented in our response to IR OAG-120 is based on 12 monthsof actual information. Second, the information provided in our response toIR OAG-120 uses the 2011 jurisdictional factors to illustrate how the balancesaccumulate to form the basis for the 2011 test year revenue requirement.V. 2012 STEP-IN NUCLEAR OUTAGE AMORTIZATION EXPENSEQ. PLEASE EXPLAIN THE 2012 NUCLEAR OUTAGE AMORTIZATION EXPENSE.11 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021222324252627A. Total nuclear outage amortization expense is $64.5 million in 2012, which ismade of $20.3 million amortization expense at Prairie Island Unit 1, $23.4million amortization expense at Prairie Island Unit 2, and $20.8 millionamortization expense at Monticello. The $20.3 million amortization expenseat Prairie Island Unit 1 represents the final ten months of amortization fromthe outage that will be completed June 2011 and two months of amortizationfor the outage that will be completed November 2012. The $23.4 millionamortization expense at Prairie Island Unit 2 represents the final two monthsof amortization from the outage completed May 2010 and ten months ofamortization from the outage that will be completed March 2012. Finally, the$20.8 million amortization expense at Monticello represents twelve months ofamortization from the outage that will be completed May 2011.Q. PLEASE EXPLAIN THE INCREASE IN THE 2012 STEP-IN FOR THESE AMORTIZEDCOSTS.A. Total nuclear outage amortization expense in 2012 increased $5.5 million over2011 levels on a total company basis. The increase is primarily due to higheramortization expense at Prairie Island Unit 2 and Monticello. Amortizationexpense at Prairie Island Unit 2 increased $3.6 million due to higher costs forthe February 2012 refueling outage and a 20 month amortization period ascompared to a 22 month amortization period used in the previous outage.Amortization expense at Monticello increased $1.6 million due to higher costsassociated with the March 2011 refueling outage. The 2012 step-in adjustmentfor these costs on a Minnesota jurisdictional basis is addressed in the DirectTestimony and Rebuttal Testimony of Company witness Mr. Richard A.Ostberg.12 Docket No. E002/GR-10-971Everson Rebuttal

123456789101112131415161718192021VI. CONCLUSIONQ. PLEASE SUMMARIZE YOUR TESTIMONY.A. We have correctly applied the deferral and amortization method approved bythe Minnesota Public Utilities Commission. The application of the deferraland amortization method follows appropriate regulatory principles to arrive atthe correct revenue requirement in this case by including the accuratelyamortized outage expenses. This method continues to benefit Minnesotaratepayers because it provides less volatility in rates than if the direct expensemethod had been used and provides a better matching of the costs to theperiods that the customers benefit from the expense. The deferral andamortization method is also a superior rate recovery method in periods whenoutage costs are trending upward or downward than using an average ofhistorical costs because it better matches the actual costs and benefits that willbe incurred during the period in which rates are in effect. Finally, whilesomewhat more complicated, the Company’s revenue requirement calculationfor nuclear outage costs is no different than other revenue requirementcalculations included in this rate case.Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?A. Yes, it does.13 Docket No. E002/GR-10-971Everson Rebuttal

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 1Page 1 of 1Karen L. EversonDirector, Utility AccountingXcel Energy1414 West Hamilton Avenue, Eau Claire, WisconsinCurrent Responsibilities (Xcel Energy Services Inc.)Director, Utility AccountingMarch, 2010-currentAs the Director of Utility Accounting, I provide senior financial and technicalaccounting leadership for the NSPM and NSPW operating utilities. I amresponsible for all facets of accounting from energy procurement & trading, costanalysis, clause and rider mechanisms, retail and wholesale revenue, and overallmargin analysis.Previous Roles with Xcel Energy Services Inc.Manager, Regulatory Accounting. 2003 to 2010As the Manager of Regulatory Accounting, I was responsible for all regulatoryaccounting for the NSPM and NSPW operating utilities, which included theaccounting for our clause and rider mechanisms, Interchange Agreement,regulatory reporting, and margin analysis.Accounting/Financial Consultant 2000 to 2003Previous Roles with Northern States Power Company WisconsinInterim Finance Team Leader 2000Senior Accountant 1996 to 2000Accountant 1994 to 1996Education & Certifications• University of Wisconsin – Eau Claire; Bachelor of Business Administration,Comprehensive Accounting Major; 1994

Planned Major Maintenance – Nuclear Refueling Outage(Uniform Policy)Last Updated: November 28, 2007Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 1 of 13

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 2 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)Statement of Purpose .......................................................................................... 3Applicability ........................................................................................................ 3Summary ............................................................................................................. 3Definitions........................................................................................................... 4Content................................................................................................................ 4Characterization .......................................................................................................................................4Definition.................................................................................................................................................5Pre-outage Costs .....................................................................................................................................6Post-outage Costs ...................................................................................................................................7Non-outage Costs ...................................................................................................................................7Unplanned Outage Costs.......................................................................................................................8Accounting.................................................................................................................................................8Deferred Work Order ............................................................................................................................8Other Regulatory Assets ........................................................................................................................8Various Jurisdictions...............................................................................................................................8Amortization............................................................................................................................................9Direct Expensing ..................................................................................................................................10Tax Treatment.......................................................................................................................................11Policy Application.................................................................................................................................11Regulatory.................................................................................................................................................11Interchange Agreement........................................................................................................................11Internal Controls ...................................................................................................................................11Accountabilities..................................................................................................12Business Unit Personnel.....................................................................................................................12Regulatory Accounting........................................................................................................................12References ..........................................................................................................13Supercedure........................................................................................................13Appendices.........................................................................................................13Regulatory AccountingPage 2

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 3 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)Statement of PurposeThis accounting policy addresses the operations and maintenance (O&M) expenditures that areassociated with the routine refueling of a nuclear unit and are categorized as planned majormaintenance activities. Please refer to the attached list of definitions for any terminology used in thispolicy. Xcel Energy’s utility subsidiaries are subject to regulation by the Federal Energy RegulatoryCommission (FERC) and by various state commissions. All of the utility subsidiaries’ accountingrecords must conform to the FERC Uniform System of Accounts. Additionally, Xcel Energy issubject to regulation by the Securities and Exchange Commission (SEC).The overall goal of this document is to achieve a consistent policy that defines common proceduresto ensure correct and consistent accounting that complies with FERC guidelines and SEC regulationsfor the proper handling of planned major maintenance activities associated with routine nuclearrefueling across all applicable entities. It is common practice across the industry to allowexpenditures to be charged to a deferred work order associated with a routine nuclear refueling inorder to amortize the costs over the next fuel cycle. Due to the magnitude of this issue, it is necessarythat the proper accounting be defined to assure accurate books and records of the Company.Currently, Northern States Power Company, a Minnesota corporation (NSPM) is the only XcelEnergy operating company with nuclear facilities, but the policy would apply to any subsidiary withsuch facilities.ApplicabilityThis Uniform Policy is effective on the date stated below and on that date, this policy becameeffective for all utility subsidiary companies. This Uniform Policy is applicable to all Xcel Energyutility subsidiaries that deal with nuclear facilities.SummaryBecause Xcel Energy is regulated by various government entities, the Corporate Controller isresponsible for accounting policies for Xcel Energy within the framework of the SEC, FASB, FERC,and state regulatory requirements. These policies will include establishing and maintaining effectiveinternal controls as it relates to the books and records of Xcel Energy and the preparation of allconsolidated external reports as required by the SEC, FERC, and the state regulators.Within this framework, Regulatory Accounting will establish appropriate accounting policies in orderto meet the FERC and GAAP/SEC accounting requirements. At the end of each month, in order torecognize the regulatory assets correctly on the Company’s balance sheet and to provide for theproper amortization to the income statement, only those refueling O&M expenditures that satisfy thecriteria defined herein should be recognized to the appropriate deferred work orders.Regulatory AccountingPage 3

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 4 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)This policy defines the expectations surrounding treatment of routine refueling O&M expenditures asplanned major maintenance activities that should be charged to deferred work orders to assure properinternal controls are in place and a proper audit trail exists. Where allowed by a regulatoryjurisdiction, the deferral and subsequent amortization of these expenditures meet the guidance issuedunder FASB Staff Position No. AUG AIR-1 (FSP AUG AIR-1), Accounting for Planned MajorMaintenance Activities. It is Regulatory Accounting’s responsibility to maintain this policy and to ensure,in conjunction with the business unit personnel, consistent application of the procedures contained inthe policy. Regulatory Accounting will monitor FERC regulations and other accounting rules thatimpact this policy and make changes as necessary to maintain accounting compliance. Thus, businessareas are responsible to understand and to adhere to the policy. Regulatory Accounting will assistbusiness areas to appropriately apply the policy.DefinitionsCapital – The purchase or construction of a retirement unit that will be recorded on the balance sheetas an asset after meeting the GAAP criteria for being an assetFASB – Financial Accounting Standards BoardFERC – Federal Energy Regulatory CommissionFSP – FASB Staff PositionGAAP – Generally Accepted Accounting PrinciplesO&M Expenditure – Expenditure incurred in the normal operations of the assets or restores the fixedasset to operating status and assists in assuring that the fixed assets achieve useful lifeexpectationsSEC – Securities and Exchange CommissionWork Order – An account numbering system used to group costs (often referred to as a subledger inthe JD Edwards general ledger system)ContentCharacterizationThis policy is based on the FSP AUG AIR-1 that modifies certain positions of AICPA Industry AuditGuide, Audits of Airlines, which defines three allowable treatments for planned major maintenanceactivities: direct expense, built-in overhaul, or deferral. Xcel Energy uses two methods: directexpensing and deferral with an amortization, often referred to as a “deferral-and-amortizationmethod”. The deferral-and-amortization method is used only when authorized by a specificregulatory jurisdiction. Thus, if no approval exists for a specific jurisdiction, the jurisdiction must usethe direct expense method. As the costs for planned major maintenance activities provide value tothe constructed asset over the next cycle to which the refueling relates (typically the next 18 to 24months), the deferral-and-amortization method has the benefit of better matching costs to the periodin which it relates. These costs include, but are not limited to; contract labor, company labor andRegulatory AccountingPage 4

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 5 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)benefits, materials and supplies, transportation, machine equipment, tool usage, permits, equipmentrental, taxes, and various incurred for planned major maintenance activities such as cleaning,servicing, replacement, or repair, as well as costs of replacement components, minor parts, andinteractive agents (such as certain fluids or elements).In general, those nuclear refueling outage costs that are properly includable to a regulatory asset underthe deferral-and-amortization method should be charged to the appropriate reload-specific set ofdeferred work orders. A series of deferred work orders will be established for each reload to alignwith the applicable FERC Account to which the O&M cost would have been charged if it had beenexpensed, such that the amortization is expensed to those same O&M FERC Accounts. Any workdone during a refueling outage that meets the requirements for capitalization is not includable in thedeferred work orders. In addition, costs for standard maintenance or normal operations, which occurduring a refueling outage and which are not listed in the definition of includable expenses shownbelow, are to be expensed to the appropriate O&M accounts. This policy defines the expensesallowed to the deferred work orders established for refueling outage costs and helps one understandthe limits in the use of these deferred work orders.DefinitionNuclear reactors are typically shut down once every 18 to 24 months to refuel approximately onethird of the reactor core. There are many costs associated with a refueling outage. These include thefollowing O&M costs:• Replacement of approximately one third of the nuclear fuel assemblies in the reactorcore;• Numerous inspections on equipment to ensure safety and compliance withrequirements;• Test and maintenance jobs that can be performed only when the reactor is shut down;and• Repairs and refurbishment of major nuclear and non-nuclear components of the plant(e.g., control rods, main coolant pumps, steam generators, turbine valves and blading,main electric generator).This is a general list of items. However, other costs arise during a refueling outage that may beappropriate for deferral and amortization. Such costs may only be deferred following a review of thenew charges for compliance with this policy and, upon compliance, approval by the outage managerand the site accounting manager (with retention of the appropriate documentation). If work beginson these activities prior to receiving approval, the expenditures will be treated as an O&M expense.However, certain costs occurring before and after the actual period when the unit is off-line areallowable to deferred work orders. Descriptions of allowed pre-outage costs and post-outage costsare included below.In addition to the work performed in a “base” refueling outage, more extensive work is requiredduring refueling outages, usually staggered over a 10-year period, to comply with periodic NuclearRegulatory AccountingPage 5

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 6 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)Regulatory Commission (NRC) and insurance requirements. In addition, it is anticipated that moreextensive refueling outages occasionally will be needed as larger projects are completed. These moreextensive outages will require longer periods and higher costs than typical refueling outages, but areone-time expenses not anticipated to be repeated over the license renewal period. Because each unithas different operating characteristics and parameters, each has its own fuel cycle, ranging from 18 toup to 24 months. Thus, the number of refueling outages scheduled in any given year will vary, withtwo outages occurring in most years, one in others, and the potential for even three refueling outagesoccurring in some years. Extensive planning goes into the preparation and execution of these outageschedules.The deferral-and-amortization method of accounting will include only costs directly associated with aplanned refueling outage. All other work, albeit done at the time of the outage, will be directlycharged to the appropriate O&M or capital accounts as has been traditionally done. Planned outagecosts for the next refueling can begin soon after the unit returns to service as contracts are being setand material is being ordered. However, most of the costs associated with planned outage workoccur within the actual outage period. An activity or work order is considered planned outage work ifone of the following conditions applies:• The plant impact of the work scope requires an outage to complete;• The work scope is required by Technical Specifications, license-based provisions, orother regulatory requirements to be performed during the outage timeframe;• The work scope duration required exceeds greater than 75% limited conditionoperations (“LCO”) duration;• The work scope requires a preventative maintenance test (“PMT”) or a test that canonly be performed during an outage, and the work that is required ensures unitreliability for the next cycle.Pre-outage CostsAs with any large project, capital or maintenance, there is considerable planning that occurs in orderfor the outage to be as efficient as possible. These planning costs are allowed as part of the deferredwork order even if the costs occur in a prior year. The earliest that outage costs can occur is shortlyafter the unit comes on-line from the last outage. Costs cannot be deferred that occur any earlier thanthe beginning of the operating cycle immediately before the outage being planned.Allowable costs during the pre-outage period include the following:• Outage milestone planning to develop a systematic approach for preparing for anoutage;• Surveillance and special testing of equipment;• Any work issues identified for performance prior to a planned outage.Regulatory AccountingPage 6

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 7 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)As with all the costs, proper documentation must exist to support the appropriateness of the chargeto the FERC specific deferred work order. Any charge that does not meet the above requirementsshould be charged directly, in the current period, to the appropriate O&M account.Post-outage CostsTypically, costs continue to come in throughout the month following the return to service. This isexpected, however any costs that are known and measurable in the month when the unit returns toservice should be recorded as an unvouchered liability in that month. The month when the bill isreceived will then contain a reversal of the unvouchered liability and recognition of the actualexpense. This true up from estimate to actual is often referred to as a “pick up”.Allowable costs during the post-outage period include the following:• Resolution of disputed outage contractor issues;• Delay charges;• Costs associated with the removal of equipment to support outage activities.As with all the costs, proper documentation must exist to support the appropriateness of the chargeto the FERC specific deferred work order. Any charge that does not meet the above requirementsshould be charged directly, in the current period, to the appropriate O&M account.Non-outage CostsNon-outage activities may be added to the outage schedule based on work benefits that can be gainedby delaying the work until the outage. Although this work is performed at the same time as therefueling outage, it is not included in the deferral and amortization. This includes the following, but isnot limited to these examples:• Personnel exposure to radiation that can be measurably reduced by performing thework when the unit is shutdown rather than at power assuming the work can bedeferred to a planned outage;• Regular maintenance work on the same component that is scheduled for work duringthe outage and the work can be safely delayed until the outage;• Work based on economic considerations and surveillance or preventative maintenancetasks that are scheduled during the outage period and cannot be rescheduled outside ofthe outage period.Regulatory AccountingPage 7

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 8 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)Unplanned Outage CostsUnplanned outages includes the work that cannot be delayed until the next planned outage andrequires the unit to be shutdown in order for the work to be completed. Also included in unplannedoutages is any work done when the unit is brought off line for safety reasons. Costs related to theseunplanned outages, as well as all non-outage activity costs, are not eligible for the deferral-andamortizationmethod of accounting, and will continue to use the direct expense accounting method.AccountingDeferred Work OrderEach outage for each unit is assigned a separate set of FERC specific deferred work orders. Beforethe first refueling outage charge is anticipated, the business area will request a series of deferred workorders be issued. The set of deferred work orders will include one work order for each nuclearproduction FERC O&M account anticipated to be charged (the same FERC accounts used to recordthe refueling outage costs to expense). As costs are incurred during the outage, the FERC specificdeferred work order will accumulate costs previously charged to the specific FERC O&M account.The use of work orders facilitates the accumulation of charges, but it also facilitates review for auditpurposes.Other Regulatory AssetsThe accumulation of refueling outage costs for those jurisdictions allowing the deferral-andamortizationmethod will be cleared from the deferred work order to FERC Account 182.3, OtherRegulatory Assets. The subsequent amortization of each balance reduces the regulatory asset to zeroover the period the plant is operating until the next reload outage. The regulatory asset account willbe maintained separate for each reload at each unit and also by each applicable nuclear productionFERC O&M account. It is anticipated that this information will be segregated via a work order tag inthe regulatory asset account.Various JurisdictionsFor any rate jurisdiction that has not approved the use of the deferral-and-amortization method fornuclear refueling outage costs, that jurisdiction will continue to use the direct expensing method forits portion of the nuclear refueling outage costs. Therefore, unless all rate jurisdictions authorize useof the deferral-and-amortization method, the accounting will be maintained by rate jurisdiction.Assuming there are some rate jurisdictions that will allow the use of the deferral-and-amortizationmethod and others that will not, the following steps generally will occur:1. The nuclear plant personnel identify the refueling expenses that are appropriate to bedeferred. Plant personnel do not allocate jurisdictional costs and thus gather total companycharges only under this policy.Regulatory AccountingPage 8

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 9 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)2. The plant personnel assign the identified costs in step 1 to a deferred work order, with eachwork order being specific to a FERC account and a particular reload.3. The charges in the deferred work order are allocated to the various rate jurisdictions eachmonth (based on the appropriate jurisdictional allocation factor in use at the time for eachnuclear production FERC O&M account).4. For those jurisdictions using the deferral-and-amortization method, the jurisdictional workorder will set up the regulatory asset for amortization.5. For those jurisdictions using the direct expense method, the costs in the jurisdictional workorder are expensed in the month incurred.6. The regulatory asset is maintained by each reload and by each applicable FERC O&Maccount such that the amortization is charged to the appropriate FERC O&M account eachmonthAmortizationThe monthly amortization is calculated for each nuclear production FERC account for each reloadfor each unit separately. The amortization is a straight-line calculation derived by dividing the amountaccumulated for the refueling outage by the number of months in the amortization period. Thefollowing method is used to calculate the amortization period.Amortization PeriodThe amortization begins with the month the unit comes on-line, and continues through the monthbefore it comes back on-line with the next refueled core. The intent behind using this period is to beassured that the previous deferral finishes the month prior to the next one beginning, leaving nomonths without an amortization or having amortizations from the previous and current reloadoverlapping. For example, the unit comes off line in February 2008 to refuel and comes back on-lineMarch 2008. The plant operates through the rest of 2008, all of 2009, and comes off-line in February2010 for the next refueling. This refueling is complete in March 2010. The amortization period is thenumber of months from March 2008 to February 2010, or 24 months in this example.The number of months in the amortization is set based on the expected future refueling date for thenext outage. The date, although a forecast, is a fairly certain date that will usually only fluctuate byone or two months on either side of the forecast date. When it is known that the next reload date hasmoved, the amortization period is adjusted. The amortization is adjusted for the remaining monthsby dividing the current balance by the remaining months in the amortization period. Continuing theabove example, if the refueling date is revised from February 2010 to April 2010 in January 2010, thenthe remaining amortization period is lengthened by two months. In January 2010, the remainingamortization was 2 months and is lengthened to 4 months based on the revised date for refueling.FERC O&M AccountsBased on accumulating the charges to a FERC specific deferred work order, the amortization iscalculated for the month for each applicable O&M account. Each refueling operation may have adifferent spread of the costs incurred across the various nuclear O&M accounts; therefore, there mayRegulatory AccountingPage 9

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 10 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)be many amortizations being calculated for each reload to effectively charge the correct FERC O&Maccount. The amortization is charged to the same nuclear production O&M expense account aswould be used for direct expensing. The amortization period is the same across all FERC O&Maccount amortizations.Applicable FERC O&M Accounts to Nuclear Refueling OutagesFERCAccountAccount TitleOperations517 Operation Supervision and Engineering519 Coolants and Water520 Steam Expenses523 Electric Expenses524 Miscellaneous Nuclear Power ExpensesMaintenance528 Maintenance Supervision and Engineering529 Maintenance of Structures530 Maintenance of Reactor Plant Equipment531 Maintenance of Electric Plant532 Maintenance of Miscellaneous Nuclear PlantPick-upsThe term “pick-ups” is used to refer to the trailing costs that occur subsequent to the completion ofthe work. Business unit personnel are expected to book all known or estimable costs in the finalmonth of the outage work. By recognizing an estimate of work completed to date, the amortizationcan begin with a very close approximation of total costs in the deferred work orders. The costsincurred in the “post-outage” phase are recognized in the deferred work orders with a debit offset bya credit to account payable or unvouchered liabilities. When the final costs are determined, the entireestimate is reversed with the actual payment being recognized to the appropriate deferred work order.There is a time limit on this process. Costs not finalized within three months after the unit beginsoperating are settled to expense.Direct ExpensingAssuming a jurisdiction may not adopt this change of accounting for its customers, their portion ofthe O&M costs will be expensed when incurred. The jurisdictional split is determined at the time theset of FERC specific deferred work orders is requested for the outage. Every charge booked to thedeferred work order will be allocated between jurisdictions that allowed the deferral-and-amortizationmethod of accounting and those jurisdictions using the direct expense method. For example, if 75%Regulatory AccountingPage 10

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 11 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)of the jurisdictions allow deferred accounting and 25% do not, for every dollar incurred, 25 cents isexpensed immediately and 75 cents is deferred and amortized. See steps defined under the “VariousJurisdictions” section above.Tax TreatmentThe treatment described to this point deals with the financial treatment of these costs for bookpurposes. The treatment of these costs for tax purposes is not impacted by whether the costs aredeferred and amortized or expensed as incurred. The amount spent in a given year on refueling costsis what is deducted for income tax purposes. Therefore, choosing to defer some of the O&M costsfor the books creates a timing difference between the book and tax recognition for these refuelingcosts. To recognize this difference, a deferred tax liability is created, setting up when the costs areexpensed for taxes and flowing back when the amortization is complete.Policy ApplicationMaking the decision of where a particular cost should be charged may not always be clear and conciseand interpretations will have to be made. Nuclear refueling costs meeting the above criteria fordeferral can be charged to a deferred work order while all routine maintenance and standard operatingcosts should be charged to the appropriate O&M expense accounts. Any uncertainty about thispolicy should be directed to Regulatory Accounting for resolution.RegulatoryInterchange AgreementCosts incurred in the nuclear production O&M FERC accounts are shared between the two NorthernState Power companies through the FERC jurisdictional “Restated Agreement to CoordinatePlanning and Operations and Interchange Power and Energy between Northern States PowerCompany (Minnesota) and Northern States Power Company (Wisconsin)” (Interchange Agreement).Costs are shared based on assignment to specific FERC accounts using a ratio of either the 36 monthcoincident peak demand or current year energy requirements. Through the Interchange Agreement,NSPM bills a proportionate share of the nuclear production O&M expense to NSPW. The use of thedeferral-and-amortization method of accounting for nuclear production O&M costs will change thepattern of expensing, however, the content of what is being expensed as well as the FERC accountsused to record those same expenses has not changed. Therefore, there is no impact to theInterchange Agreement resulting from this use of the deferral-and-amortization method.Internal ControlsRegulatory Accounting has initiated the following tasks to assure that a valid work order for theregulatory assets resulting from this process exists from month to month:Regulatory AccountingPage 11

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 12 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)• Working with the nuclear plant personnel to assure that proper documentation of costassignment is being maintained;• Periodically reviewing deferred work orders to assure that only proper costs are beingincluded;• Establishing the appropriate jurisdictional allocations for each deferred work order;• Communicating this policy and its implications for the budgeting process for departmentaloperating expenses to all business unit personnel responsible for departmental budgets;• Providing forecast information for the future amortizations applicable to this method basedon the business area’s budget of deferred costs.AccountabilitiesBusiness Unit PersonnelBusiness unit personnel are responsible for the following:• Requesting set of deferred work orders prior to the first refueling outage charge;• Making sure all costs are being appropriately tracked based on the rules stated above;• Assuring unvouchered liabilities are booked timely;• Providing all supporting documentation for the costs contained in any deferred workorder;• Keeping Regulatory Accounting aware of any changes to the refueling schedule in timeto affect the monthly amortization.Regulatory AccountingRegulatory Accounting is responsible for the following:• Performing the compliance accounting associated with this deferral;• Providing the appropriate jurisdictional allocators for the various accumulating workorders;• Calculating and documenting the monthly amortization;• Providing all relevant deferral related information for the amortization for the forecastand for rate case preparations;• Periodically reviewing work orders for the appropriateness of charges and working withthe business unit personnel to resolve any issues.Regulatory AccountingPage 12

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 2Page 13 of 13Planned Major Maintenance – Nuclear Refueling Outage (Uniform Policy)ReferencesFASB Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance Activities, September2006SupercedureThis is the first issuance of this policy.AppendicesThere are no appendices to this policyRegulatory AccountingPage 13

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 1 of 9Non Public Document – Contains Trade Secret DataPublic Document – Trade Secret Data ExcisedPublic DocumentXcel EnergyDocket No.: E002/GR-10-971Response To: Office of Attorney General Information Request No. 120Requestor: Ronald GiteckDate Received: February 25, 2011__________________________________________________________________Question:Regarding the new nuclear outage cost accounting methodology provide thecalculation of the test year revenue requirement under this accounting method by yearfrom inception of this new accounting method. Include deferred accountingcalculations that support the revenue requirement from the beginning of the newaccounting methodology adopted in 2008. By year, as it relates to the nuclear outagecost accounting, show actual costs, deferred outage costs, deferred taxes, amortizedcosts, deferred revenues, actual revenues, amortized revenues, rate base and return onrate base that support the test year revenue requirement for this item.Response:Attached are the year-by-year revenue requirements associated with the nuclear outagechange of accounting for years 2009 through the 2012 step adjustment. Page 7 ofAttachment A to this response shows the deferred revenues by year. For deferredrevenues, the calculations represent the four-year amortization of an original balanceof $13,762,892 established in 2008 and amortized over a four-year period beginning in2009. This is consistent with the information included in the Company’s 2009 ratecase test year as well as the current 2011 test year and 2012 step adjustment.For outage cost deferrals and amortizations, 2008 and 2009 represent thejurisdictional allocation of total company actual results. 2010 represents the bridgeyear information included in the present rate case. 2011 and 2012 are consistent withthe 2011 test year and 2012 step adjustment. To illustrate how the information buildsup to the 2011 test year as requested, all balances, except for the deferred revenuesthat are direct assigned to the Minnesota jurisdiction, reflect the jurisdictionalallocation factors used in the case. Actual 2008 and 2009 capital structures were usedto determine each year’s associated revenue requirement. The 2010-2012 capitalstructures are consistent with the information provided in the case.

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 2 of 9The calculations in Pages 1 through 6 of Attachment A illustrate the resulting revenuerequirements for years 2008-2012. For ease of comparison, these calculations wereperformed using the same analysis layout included in Exhibit___(AEH-1), Schedule17 of Ms. Anne Heuer's Direct Testimony. The 2011 revenue requirement as shownon Attachment A, page 5 of 8 replicates the amounts shown on Exhibit___(AEH-1),Schedule 17. Attachment A, page 7 provides a summary of the total company annualamounts and balances as allocated to the various jurisdictions for years 2008 through2012. Attachment A, Page 8 provides the deferred revenue initial amount establishedin 2008 and the four-year amortization from 2009 through 2012, including relateddeferred tax expenses and balances.__________________________________________________________________Witness: Anne E. HeuerPreparer: Jeffrey C. RobinsonTitle: Regulatory ConsultantDepartment: Revenue Requirements NorthTelephone: 612-330-5912Date: March 16, 20112

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 3 of 9Northern States Power Company, a Minnesota corporationDocket No. E002/GR-10-971Electric Utility - State of MinnesotaOAG-120 Attachment ANuclear Outage Accounting Page 1 of 72008 Amortization, Unamortized Balancesand Test Year Revenue Requirements2008 ActualCapital Structure Rate Ratio CostLong Term Debt 6.6443% 47.9431% 3.1900%Short Term Debt 4.5341% 1.2922% 0.0600%Composite IA Factor 0.838526581 Preferred Stock 0.0000% 0.0000% 0.0000%Composite Tax Rate 0.408568 Common Equity 10.5400% 50.7647% 5.3500%MN Composite Tax Rate 0.4137 Required Rate of Return 8.6000%BOY 4 Yr Amort New EOY BOY/EOYDeferred Revenues Balance Expense Deferral Balance AverageDeferred Revenues - - (13,762,892) (13,762,892) (6,881,446)Deferred Taxes - - 5,623,077 5,623,077 2,811,539Rate Base - - (8,139,815) (8,139,815) (4,069,907)Annualized CostsDeferred Outage Costs - (13,772,636) 49,650,570 35,877,934 17,938,967Deferred Taxes - 5,627,059 (20,285,634) (14,658,576) (7,329,288)Rate Base - (8,145,578) 29,364,936 21,219,358 10,609,679Total Rate Base 6,539,772Return Requirement 562,420RR Tax on Equity Return 246,878Rate Base Revenue Requirement 809,298Expense Amortization 13,772,636Revenue Amortization -Deferred Taxes 14,658,576Current Taxes (14,972,622)Income Statement Revenue Requirement 13,458,590Total Test Year Revenue Requirement before IA 14,267,888Interchange Agreement Revenue Offset (2,303,885)Net Test Year Revenue Requirement 11,964,003Previous Expense Method Total Test Year Revenue Req before IA 49,650,570Interchange Agreement Revenue Offset (8,017,247)Net Previous Expense Method Total Test Year Revenue Req 41,633,323Difference (29,669,320)

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 4 of 9Northern States Power Company, a Minnesota corporationDocket No. E002/GR-10-971Electric Utility - State of MinnesotaOAG-120 Attachment ANuclear Outage Accounting Page 2 of 72009 Amortization, Unamortized Balancesand Test Year Revenue Requirements2009 ActualCapital Structure Rate Ratio CostLong Term Debt 6.5714% 46.3727% 3.0500%Short Term Debt 0.9669% 1.3932% 0.0100%Composite IA Factor 0.838526581 Preferred Stock 0.0000% 0.0000% 0.0000%Composite Tax Rate 0.408568 Common Equity 10.8800% 52.2341% 5.6800%MN Composite Tax Rate 0.4137 Required Rate of Return 8.7400%BOY 4 Yr Amort New EOY BOY/EOYDeferred Revenues Balance Expense Deferral Balance AverageDeferred Revenues (13,762,892) 3,440,723 - (10,322,169) (12,042,530)Deferred Taxes 5,623,077 (1,405,769) - 4,217,308 4,920,192Rate Base (8,139,815) 2,034,954 - (6,104,861) (7,122,338)Annualized CostsDeferred Outage Costs 35,877,934 (41,039,376) 58,741,819 53,580,376 44,729,155Deferred Taxes (14,658,576) 16,767,376 (24,000,027) (21,891,227) (18,274,901)Rate Base 21,219,358 (24,272,000) 34,741,791 31,689,149 26,454,254Total Rate Base 19,331,916Return Requirement 1,689,609RR Tax on Equity Return 774,799Rate Base Revenue Requirement 2,464,408Expense Amortization 41,039,376Revenue Amortization (3,440,723)Deferred Taxes 8,638,421Current Taxes (8,823,491)Income Statement Revenue Requirement 37,413,583Total Test Year Revenue Requirement before IA 39,877,991Interchange Agreement Revenue Offset (6,439,236)Net Test Year Revenue Requirement 33,438,756Previous Expense Method Total Test Year Revenue Req before IA 58,741,819Interchange Agreement Revenue Offset (9,485,242)Net Previous Expense Method Total Test Year Revenue Req 49,256,577Difference (15,817,821)

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 5 of 9Northern States Power Company, a Minnesota corporationDocket No. E002/GR-10-971Electric Utility - State of MinnesotaOAG-120 Attachment ANuclear Outage Accounting Page 3 of 72010 Amortization, Unamortized Balancesand Test Year Revenue Requirements2010 Bridge YearCapital Structure Rate Ratio CostLong Term Debt 6.0700% 46.3000% 2.8100%Short Term Debt 2.0600% 1.1400% 0.0200%Composite IA Factor 0.838526581 Preferred Stock 0.0000% 0.0000% 0.0000%Composite Tax Rate 0.40863 Common Equity 11.2500% 52.5600% 5.9100%MN Composite Tax Rate 0.4137 Required Rate of Return 8.7400%BOY 4 Yr Amort New EOY BOY/EOYDeferred Revenues Balance Expense Deferral Balance AverageDeferred Revenues (10,322,169) 3,440,723 - (6,881,446) (8,601,807)Deferred Taxes 4,217,308 (1,405,769) - 2,811,539 3,514,423Rate Base (6,104,861) 2,034,954 - (4,069,907) (5,087,384)Annualized CostsDeferred Outage Costs 53,580,376 (51,112,454) 34,341,005 36,808,928 45,194,652Deferred Taxes (21,891,227) 20,886,082 (14,032,765) (15,037,910) (18,464,569)Rate Base 31,689,149 (30,226,372) 20,308,240 21,771,018 26,730,083Total Rate Base 21,642,699Return Requirement 1,891,572RR Tax on Equity Return 902,536Rate Base Revenue Requirement 2,794,108Expense Amortization 51,112,454Revenue Amortization (3,440,723)Deferred Taxes (5,447,548)Current Taxes 5,562,461Income Statement Revenue Requirement 47,786,644Total Test Year Revenue Requirement before IA 50,580,752Interchange Agreement Revenue Offset (8,167,447)Net Test Year Revenue Requirement 42,413,305Previous Expense Method Total Test Year Revenue Req before IA 34,341,005Interchange Agreement Revenue Offset (5,545,160)Net Previous Expense Method Total Test Year Revenue Req 28,795,846Difference 13,617,459

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 6 of 9Northern States Power Company, a Minnesota corporationDocket No. E002/GR-10-971Electric Utility - State of MinnesotaOAG-120 Attachment ANuclear Outage Accounting Page 4 of 72011 Amortization, Unamortized Balancesand Test Year Revenue Requirements2011 Rate Case TYCapital Structure Rate Ratio CostLong Term Debt 6.0700% 46.3000% 2.8100%Short Term Debt 2.0600% 1.1400% 0.0200%Composite IA Factor 0.838526581 Preferred Stock 0.0000% 0.0000% 0.0000%Composite Tax Rate 0.408568 Common Equity 11.2500% 52.5600% 5.9100%MN Composite Tax Rate 0.4137 Required Rate of Return 8.7400%BOY 4 Yr Amort New EOY BOY/EOYDeferred Revenues Balance Expense Deferral Balance AverageDeferred Revenues (6,881,446) 3,440,723 - (3,440,723) (5,161,084)Deferred Taxes 2,811,539 (1,405,769) - 1,405,769 2,108,654Rate Base (4,069,907) 2,034,954 - (2,034,954) (3,052,430)Annualized CostsDeferred Outage Costs 36,808,928 (52,249,534) 57,748,879 42,308,273 39,558,600Deferred Taxes (15,038,950) 21,347,488 (23,594,344) (17,285,807) (16,162,378)Rate Base 21,769,978 (30,902,046) 34,154,535 25,022,467 23,396,222Total Rate Base 20,343,792Return Requirement 1,778,047RR Tax on Equity Return 848,369Rate Base Revenue Requirement 2,626,417Expense Amortization 52,249,534Revenue Amortization (3,440,723)Deferred Taxes 3,652,626Current Taxes (3,730,880)Income Statement Revenue Requirement 48,730,557Total Test Year Revenue Requirement before IA 51,356,974Interchange Agreement Revenue Offset (8,292,786)Net Test Year Revenue Requirement 43,064,187Previous Expense Method Total Test Year Revenue Req before IA 57,748,879Interchange Agreement Revenue Offset (9,324,909)Net Previous Expense Method Total Test Year Revenue Req 48,423,970Difference (5,359,783)

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 7 of 9Northern States Power Company, a Minnesota corporationDocket No. E002/GR-10-971Electric Utility - State of MinnesotaOAG-120 Attachment ANuclear Outage Accounting Page 5 of 72012 Amortization, Unamortized Balancesand Test Year Revenue Requirements2012 StepCapital Structure Rate Ratio CostLong Term Debt 6.0700% 46.3000% 2.8100%Short Term Debt 2.0600% 1.1400% 0.0200%Composite IA Factor 0.838526581 Preferred Stock 0.0000% 0.0000% 0.0000%Composite Tax Rate 0.408568 Common Equity 11.2500% 52.5600% 5.9100%MN Composite Tax Rate 0.4137 Required Rate of Return 8.7400%BOY 4 Yr Amort New EOY BOY/EOYDeferred Revenues Balance Expense Deferral Balance AverageDeferred Revenues (3,440,723) 3,440,723 - (0) (1,720,361)Deferred Taxes 1,405,769 (1,405,769) - 0 702,885Rate Base (2,034,954) 2,034,954 - (0) (1,017,477)Annualized CostsDeferred Outage Costs 42,308,273 (56,889,939) 73,836,875 59,255,209 50,781,741Deferred Taxes (17,285,807) 23,243,409 (30,167,384) (24,209,782) (20,747,794)Rate Base 25,022,467 (33,646,531) 43,669,490 35,045,426 30,033,947Total Rate Base 29,016,470Return Requirement 2,536,039RR Tax on Equity Return 1,210,034Rate Base Revenue Requirement 3,746,074Expense Amortization 56,889,939Revenue Amortization (3,440,723)Deferred Taxes 8,329,745Current Taxes (8,508,202)Income Statement Revenue Requirement 53,270,759Total Test Year Revenue Requirement before IA 57,016,833Interchange Agreement Revenue Offset (9,206,703)Net Test Year Revenue Requirement 47,810,130Previous Expense Method Total Test Year Revenue Req before IA 73,836,875Interchange Agreement Revenue Offset (11,922,693)Net Previous Expense Method Total Test Year Revenue Req 61,914,182Difference (14,104,052)

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 8 of 9Xcel Energy (MN)Docket No. E002/GR-10-971Electric Utility - Northern States Power Co (MN)OAG-120 Attachment ADeferred Accounting - Nuclear Outage Costs Change Of Accounting Page 6 of 7Deferred Outage Amortization per MPUC Decision Composite Tax Rate = 0.4085682008 - 2011Total Company Minnesota North Dakota South DakotaWholesaleDeferred Outage Costs Deferred Outage Costs Deferred Outage Costs Deferred Outage Costs Deferred Outage CostsYear BOY Outage Costs EOY Year BOY Outage Costs EOY Year BOY Outage Costs EOY Year BOY Outage Costs EOY Year BOY Outage Costs EOY2008 - 56,309,171 56,309,171 2008 - 49,650,570 49,650,570 2008 - 3,410,235 3,410,235 2008 - 3,182,858 3,182,858 2008 - 65,507 65,5072009 56,309,171 66,590,795 122,899,966 2009 49,650,570 58,741,819 108,392,389 2009 3,410,235 4,013,244 7,423,480 2009 3,182,858 3,758,050 6,940,908 2009 65,507 77,682 143,1892010 122,899,966 38,967,665 161,867,630 2010 108,392,389 34,341,005 142,733,394 2010 7,423,480 2,374,455 9,797,935 2010 6,940,908 2,207,028 9,147,936 2010 143,189 45,176 188,3652011 161,867,630 65,443,417 227,311,047 2011 142,733,394 57,748,879 200,482,274 2011 9,797,935 3,929,245 13,727,180 2011 9,147,936 3,688,788 12,836,724 2011 188,365 76,505 264,8702012 227,311,047 83,802,611 311,113,658 2012 200,482,274 73,836,875 274,319,148 2012 13,727,180 5,118,642 18,845,822 2012 12,836,724 4,750,073 17,586,797 2012 264,870 97,021 361,891Adjustment to O&M Amortization of Nuclear Outage Costs Adjustment to O&M Amortization of Nuclear Outage Costs Adjustment to O&M Amortization of Nuclear Outage Costs Adjustment to O&M Amortization of Nuclear Outage Costs Adjustment to O&M Amortization of Nuclear Outage CostsYear BOY Current (2) EOY Year BOY Current (2) EOY Year BOY Current (2) EOY Year BOY Current (2) EOY Year BOY Current (2) EOY2008 - 15,619,523 15,619,523 2008 - 13,772,636 13,772,636 2008 - 945,857 945,857 2008 - 882,857 882,857 2008 - 18,172 18,1722009 15,619,523 46,533,324 62,152,847 2009 13,772,636 41,039,376 54,812,013 2009 945,857 2,811,491 3,757,348 2009 882,857 2,628,249 3,511,106 2009 18,172 54,207 72,3792010 62,152,847 57,958,059 120,110,906 2010 54,812,013 51,112,454 105,924,467 2010 3,757,348 3,503,926 7,261,274 2010 3,511,106 3,274,187 6,785,294 2010 72,379 67,492 139,8722011 120,110,906 59,245,108 179,356,014 2011 105,924,467 52,249,534 158,174,001 2011 7,261,274 3,580,151 10,841,425 2011 6,785,294 3,346,414 10,131,708 2011 139,872 69,008 208,8802012 179,356,014 64,513,126 243,869,140 2012 158,174,001 56,889,939 215,063,940 2012 10,841,425 3,902,806 14,744,231 2012 10,131,708 3,645,283 13,776,991 2012 208,880 75,098 283,978Net Plant Net Plant Net Plant Net Unamortized Balance Net PlantYear BOY (3) Current EOY (4) Year BOY (3) Current EOY (4) Year BOY (3) Current EOY (4) Year BOY (3) Current EOY (4) Year BOY (3) Current EOY (4)2008 - 40,689,648 40,689,648 2008 - 35,877,934 35,877,934 2008 - 2,464,378 2,464,378 2008 - 2,300,001 2,300,001 2008 - 47,335 47,3352009 40,689,648 20,057,471 60,747,119 2009 35,877,934 17,702,442 53,580,376 2009 2,464,378 1,201,753 3,666,132 2009 2,300,001 1,129,800 3,429,801 2009 47,335 23,475 70,8102010 60,747,119 (18,990,395) 41,756,724 2010 53,580,376 (16,771,448) 36,808,928 2010 3,666,132 (1,129,471) 2,536,661 2010 3,429,801 (1,067,159) 2,362,642 2010 70,810 (22,316) 48,4932011 41,756,724 6,198,309 47,955,033 2011 36,808,928 5,499,345 42,308,273 2011 2,536,661 349,094 2,885,755 2011 2,362,642 342,374 2,705,016 2011 48,493 7,496 55,9902012 47,955,033 19,289,485 67,244,518 2012 42,308,273 16,946,935 59,255,209 2012 2,885,755 1,215,836 4,101,591 2012 2,705,016 1,104,790 3,809,806 2012 55,990 21,924 77,913Amortization of Deferred Taxes Amortization of Deferred Taxes Amortization of Deferred Taxes Amortization of Deferred Taxes Amortization of Deferred TaxesYear BOY (5) Current (7) EOY (6) Year BOY (5) Current (7) EOY (6) Year BOY (5) Current (7) EOY (6) Year BOY (5) Current (7) EOY (6) Year BOY (5) Current (7) EOY (6)2008 - 16,624,488 16,624,488 2008 - 14,658,576 14,658,576 2008 - 1,006,866 1,006,866 2008 - 939,707 939,707 2008 - 19,340 19,3402009 16,624,488 8,194,841 24,819,329 2009 14,658,576 7,232,652 21,891,227 2009 1,006,866 490,998 1,497,864 2009 939,707 461,600 1,401,307 2009 19,340 9,591 28,9312010 24,819,329 (7,758,868) 17,060,461 2010 21,891,227 (6,852,277) 15,038,950 2010 1,497,864 (461,466) 1,036,399 2010 1,401,307 (436,007) 965,300 2010 28,931 (9,118) 19,8132011 17,060,461 2,532,431 19,592,892 2011 15,038,950 2,246,857 17,285,807 2011 1,036,399 142,629 1,179,027 2011 965,300 139,883 1,105,183 2011 19,813 3,063 22,8762012 19,592,892 7,881,066 27,473,958 2012 17,285,807 6,923,975 24,209,782 2012 1,179,027 496,752 1,675,779 2012 1,105,183 451,382 1,556,565 2012 22,876 8,957 31,8333/16/2011 S:\General-Offices-GO-01\RATE\10_Elec_Rate_Case_MN 10-971\_Information Requests\OAG\OAG-0120 Attachment Filed.xls[Summary by Jurisdiction]

Docket No. E002/GR-10-971Exhibit___(KLE-1), Schedule 3Page 9 of 9Xcel Energy (MN)Docket No. E002/GR-10-971Electric Utility - MN JurisdictionOAG-120 Attachment ADeferred Accounting - Nuclear Outage Costs Change Of Accounting Page 7 of 7Deferred Revenues per MPUC Decision2011 Budget2011 Composite Tax Rate 0.408568Initial Deferred RevenueYear BOY Current (1) EOY2008 - (13,762,892) (13,762,892)2009 (13,762,892) - (13,762,892)2010 (13,762,892) - (13,762,892)2011 (13,762,892) - (13,762,892)2012 (13,762,892) - (13,762,892)AmortizationYear BOY Current (2) EOY2008 - - -2009 - (3,440,723) (3,440,723)2010 (3,440,723) (3,440,723) (6,881,446)2011 (6,881,446) (3,440,723) (10,322,169)2012 (10,322,169) (3,440,723) (13,762,892)Net Unamortized BalanceYear BOY (3) Current EOY (4)2008 - (13,762,892) (13,762,892)2009 (13,762,892) 3,440,723 (10,322,169)2010 (10,322,169) 3,440,723 (6,881,446)2011 (6,881,446) 3,440,723 (3,440,723)2012 (3,440,723) 3,440,723 (0)Amortization of Deferred Taxes(A)Year BOY (5) Current (7) EOY (6)2008 - (5,623,077) (5,623,077)2009 (5,623,077) 1,405,769 (4,217,308)2010 (4,217,308) 1,405,769 (2,811,539)2011 (2,811,539) 1,405,769 (1,405,769)2012 (1,405,769) 1,405,769 (0)