This combined Form 10-Q is separately filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota), Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin), Public Service Co. of Colorado (PSCo) and Southwestern Public Service ~~Co. (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are all wholly owned subsidiaries of Xcel Energy Inc. Xcel Energy is a registered holding company under~~Company meets the ~~Public Utility Holding Company Act (PUHCA). Additional information on Xcel Energy is available on various filings with the SEC.~~

Information contained in this report relating to any individual company is filed by such company on its own behalf. Each registrant makes representations only as to itself and makes no other representations whatsoever as to information relating to the other registrants.

~~This report should be read in its entirety. No one section of the report deals with all aspects of the subject matter.~~

In the opinion of management, the accompanying unaudited consolidated and stand-alone financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS (collectively referred to as the Utility Subsidiaries of Xcel Energy) as of June 30, 2002, and Dec. 31, 2001, the results of their operations for the three and six months ended June 30, 2002 and 2001, and their cash flows for the three and six months ended June 30, 2002 and 2001. Due to the seasonality of electric and gas sales of Xcel Energy’s Utility Subsidiaries, quarterly results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are set forth in Note 1 to the financial statements in their respective Annual Reports on Form 10-K for the year ended Dec. 31, 2001. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K’s.

Certain items in the 2001 income statement have been reclassified from amounts previously reported to conform to the 2002 presentation. These reclassifications had no effect on stockholders’ equity or net income as previously reported. The reclassifications were primarily to conform the presentation of all consolidated Xcel Energy subsidiaries to a standard corporate presentation.

~~Intangible Assets —~~During the first quarter of 2002, the Utility Subsidiaries of Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 142 — “Goodwill and Other Intangible Assets” (SFAS No. 142), which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives are being amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value.

~~The Utility Subsidiaries of Xcel Energy have no intangible assets with indefinite lives.~~

Aggregate amortization expense recognized in the six months ended June 30, 2002 was approximately $122,000. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $240,000. Intangible assets subject to amortization at June 30, 2002, consisting primarily of deferred employment agreement costs, were as follows:

~~Asset Valuation —~~On Jan. 1, 2002, the Utility Subsidiaries adopted SFAS No. 144 — “Accounting for the Impairment or Disposal of Long-Lived Assets,” which supercedes previous guidance for measurement of asset impairments. The Utility Subsidiaries did not recognize any asset impairments as a result of the adoption. The method used in determining fair value was based on a number of valuation techniques, including present value of future cash flows.

~~2002 Regulatory Recovery Adjustment —~~In late 2001, SPS filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, SPS entered into a settlement agreement with interveners regarding the recovery of

~~restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.~~

~~2002/2001 Restaffing —~~During the fourth quarter of 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. Approximately $36 million of these restaffing costs were allocated to Xcel Energy’s Utility Subsidiaries consistent with service company cost allocation methodologies utilized under the requirements of the PUHCA. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations. Approximately $5 million of these restaffing costs were allocated to Xcel Energy’s Utility Subsidiaries. As of June 30, 2002, all 564 of accrued staff terminations had occurred.

~~The following table summarizes the activity related to accrued special charges (reported in other current liabilities) for the first six months of 2002.~~

~~2001 Postemployment Benefits —~~PSCO’s earnings for the second quarter of 2001 were reduced due to a Colorado Supreme Court decision that resulted in a 2001 pretax write-off of $23 million of regulatory assets related to deferred postemployment benefit costs at PSCo.

~~TRANSLink Transmission Company, LLC (TRANSLink) —~~In September 2001, Xcel Energy and several other electric utilities applied to the Federal Energy Regulatory Commission (FERC) to integrate operations of their electric transmission systems into a single system through the formation of TRANSLink, a for-profit, transmission-only company. The utilities will participate in TRANSLink through a combination of divestiture, leases and operating agreements. The applicants are: Alliant Energy’s Iowa company (Interstate Power and Light Co.), Corn Belt Power Cooperative, MidAmerican Energy Co., Nebraska Public Power District, Omaha Public Power District and Xcel Energy. The participants believe TRANSLink is the most cost-efficient option available to manage transmission and to comply with regulations issued by the FERC in 1999 (known as Order No. 2000) that require investor-owned electric utilities to transfer operational control of their transmission system to an independent regional transmission organization (RTO).

Under the proposal, TRANSLink will be responsible for planning, managing and operating both local and regional transmission assets. TRANSLink will also construct and own new transmission system additions. TRANSLink will collect the revenue for the use of Xcel Energy’s transmission assets through a FERC-approved, regulated cost-of-service tariff and will collect its administrative costs through transmission rate surcharges. Transmission service pricing will continue to be regulated by the FERC, but construction and permitting approvals will continue to rest with regulators in the states served by TRANSLink. The participants also have entered into a memorandum of understanding with the Midwest Independent Transmission Operator, Inc. (MISO) in which they agree that TRANSLink will contract with the MISO for certain other required RTO functions and services. In May 2002, the partners formed TRANSLink Development Company, LLC., which is responsible for pursuing the actions necessary to complete the regulatory approval of TRANSLink Transmission Company, LLC.

In April 2002, the FERC gave conditional approval for the applicants to transfer ownership or operations of their transmission systems to TRANSLink and to form TRANSLink as an independent transmission company operating under the umbrella organization of MISO and a separate RTO in the west (once it is formed) for PSCo’s assets. The FERC conditioned TRANSLink’s approval on the resubmission of its tariff as a separate schedule to be administered by the MISO. TRANSLink Development Company anticipates making this filing during the third quarter of 2002. Several state approvals also would be required to implement the proposal, as well as SEC approval. Subject to receipt of required regulatory approvals, TRANSLink is expected to begin operations in early 2003.

~~Merger Agreements —~~Under the Stipulation and Agreement approved by the Colorado Public Utilities Commission (CPUC) in connection with the Xcel Energy merger, PSCo agreed to 1) file a combined electric, gas and steam rate case in 2002 with new rates effective in January 2003, 2) extend its incentive cost adjustment (ICA) mechanism for one more year through Dec. 31, 2002 with an increase in the ICA base rate from $12.78 per megawatt hour to a rate based on the 2001 actual costs, 3) continue the Performance Based Regulatory Plan and the Quality Service Plan through 2006 with an electric department earnings cap of 10.5 percent return on equity for 2002, 4) reduce electric rates annually by $11 million for the period August 2000 to July 2002 and 5) cap merger costs associated with electric operations at $30 million and amortize such costs through 2002.

~~Incentive Cost Adjustment —~~In early 2002, PSCo filed to increase rates under the ICA to recover the undercollection of costs through the period ended Dec. 31, 2001 (approximately $14.5 million, which went into effect on April 15, 2002) and to increase the ICA base rate for the recovery of 2002 costs which are projected to be substantially higher than the $12.78 per megawatt hour currently being recovered. PSCo’s actual ICA base costs for 2001 were approximately $19 per megawatt hour. PSCo proposed to increase the ICA base in 2002 to avoid the significant deferral of costs and a large rate increase in 2003, although the Stipulation and Agreement provided for a rate recovery period of April 1, 2003, to March 31, 2004.

On May 10, 2002, the CPUC approved a Settlement Agreement between PSCo and other parties to increase the ICA base rate to $14.88 per megawatt hour, providing for recovery of the deferred 2001 costs and the projected higher 2002 costs over a 34-month period from June 1, 2002, to March 31, 2005. The review and approval of actual costs incurred and recoverable under the ICA for 2001 and 2002 will be conducted in future rate proceedings by the CPUC for consideration of further increases in the ICA base rate to $19.00 per megawatt hour. PSCo is currently projecting its costs for 2002 to be approximately $38 million less than the ICA base allowed using the 2001 test year, resulting in an equal sharing of such lower costs between retail customers and PSCo. The mechanism for recovering fuel and energy costs for 2003 and later will be addressed in the 2002 rate case.

~~General Rate Case —~~In May 2002, Xcel Energy filed a combined general rate case with the CPUC to address increased costs for providing energy to Colorado customers. The net impact of the filings would increase electric revenue by approximately $220 million and decrease gas revenue by approximately $13 million. The rates are expected to be effective in early 2003. Xcel Energy also asked to increase its authorized rate of return on equity to 12 percent for electricity and to 12.25 percent for natural gas.

The CPUC staff and the Office of Consumer Counsel (OCC) filed a joint motion requesting the CPUC permanently suspend PSCo’s rate case alleging PSCo did not show (in the form that Staff is familiar with) the appropriate direct and indirect accounting for costs of non-regulated services. On Aug. 2, 2002, Xcel Energy, the CPUC and the OCC (the parties) filed a joint motion to request the CPUC delay their decision on the original motion for two weeks until August 19th. PSCo is currently working resolve the allegations. It is possible the parties could request the CPUC delay the effective date of the rate case.

~~Gas Cost Prudence Review —~~In May 2002, the staff of the CPUC filed testimony in PSCo’s gas cost prudence review case, recommending $6.1 million in disallowances of gas costs for the July 2000 through June 2001 gas purchase year. Hearings were held in July 2002. A decision is expected in late 2002.

~~SPS Texas Transition to Competition Cost Recovery Application —~~In December 2001, SPS filed an application with the Public Utility Commission of Texas (PUCT) to recover $20.3 million in costs related to transition to retail competition from the Texas retail customers. These costs were incurred to position SPS for retail competition, which was eventually delayed for SPS. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which were associated with over-earnings for the calendar year 1999. The PUCT approved SPS using the 1999 over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT was received in May 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

~~Metro Emissions Reduction Program —~~On July 26, 2002, 2002, NSP-Minnesota filed for approval by the Minnesota Public Utilities Commission (MPUC) a proposal to invest in existing NSP-Minnesota generation facilities (A S King, High Bridge, Riverside) to reduce emissions under the terms of legislation adopted by the 2001 Minnesota Legislature. The proposal includes the installation of state-of-the-area pollution control equipment at the AS King plant and conversion to natural gas at the High Bridge and Riverside plants. Under the terms of the statute, the filing concurrently seeks approval of a rate recovery mechanism for the costs of the proposal, estimated to be a total of $1.1 billion with major expenditures anticipated to begin in 2005 and continuing through 2009. The rate recovery would be through an annual automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective at the expiration of the NSP-Minnesota merger rate freeze, which extends through 2005 unless certain exemptions are triggered. The rate recovery proposed by NSP-Minnesota would allow recovery of financing costs of capital expenditures prior to the in-service date of each plant. The proposal is pending comments by interested parties. Other regulatory approvals, such as environmental permitting, are needed before the proposal can be implemented.

~~Renewable Cost Recovery Tariff —~~In April 2002, NSP-Minnesota also filed for MPUC authorization to recover in retail rates the costs of electric transmission facilities constructed to provide transmission service for renewable energy. The rate recovery would be through an automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective Jan. 1, 2003. In July 2002, the Minnesota Department of Commerce filed comments supporting approval of the tariff mechanism, subject to certain modifications that are generally acceptable to Xcel Energy.

~~Retail Electric Fuel Rates —~~In August 2002, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW), requesting a decrease in Wisconsin retail electric rates for fuel costs. The amount of the proposed rate decrease is approximately $6.3 million on an annual basis. The reasons for the decrease include moderate weather, lower than forecast market power costs, and optimal plant availability. On Aug. 7, 2002, the PSCW issued an order approving the fuel rate credit. The rate credit will be effective on Aug. 12, 2002.

~~Standard Market Design Rulemaking —~~In July 2002 the FERC issued a Notice of Proposed Rulemaking on Standard Market Design rulemaking for regulated utilities. If implemented as proposed, the Rulemaking will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid based system for buying and selling energy in wholesale markets. The market will be administered by RTOs or Independent Transmission Providers. RTOs will also be responsible for putting together regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the Rule envisions the development of Regional Market Monitors responsible for ensuring that individual participants do not exercise unlawful market power. Comments to the rules are due in the fourth quarter of 2002. The FERC anticipates that the final rules will be in place in early 2003 and the contemplated market changes will take place in 2003 and 2004.

~~Cash Management Regulation —~~On Aug. 1, 2002, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new rules governing corporate “money pools,” which include jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The proposed rules would require documentation of transactions within such money pools, a proprietary capital account of the jurisdictional utility of 30 percent, and would require the nonregulated parent company to have an investment grade rating. Comments on the proposed rules are due Aug. 22, 2002. Xcel Energy is reviewing the proposed rules and their interaction with similar money pool regulations of the SEC.

~~Standards of Conduct Rulemaking —~~In October 2001, FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of the Utility Subsidiaries and the rules governing the natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and would materially increase operating costs of the Utility Subsidiaries. In April 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. Final rules are expected by year-end 2002.

~~FERC Investigation —~~On May 8, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator or Power Exchange, including PSCo, to respond to data requests, including requests for admissions with respect to certain trading strategies in which the companies may have engaged. The investigation is in response to memoranda prepared by Enron Corporation that detail certain trading strategies engaged in 2000 and 2001, which may have violated market rules. On May 22, 2002, Xcel Energy reported to the FERC that it had not engaged directly in any of the trading strategies identified in the May 8th inquiry.

On May 13, 2002, Xcel Energy, independently and not in direct response to any regulatory inquiry, announced that PSCo had engaged in certain trading transactions, initiated by Reliant Resources, that had immaterial income effects in 1999 and 2000.

To supplement the May 8th request, on May 21, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services in the United States portion of the Western Systems Coordinating Council during 2000 and 2001 to report whether they had engaged in activities referred to as “wash,” “round trip” or “sell/buyback” trading. On May 31, 2002, Xcel Energy reported to the FERC that it had not engaged in so-called round trip electricity trading identified in the May 21st inquiry.

Xcel Energy did report, as previously announced on May 13, 2002, that PSCo had engaged in a group of transactions in 1999 and 2000 with the trading arm of Reliant Resources in which PSCo bought a quantity of power from Reliant and simultaneously sold the same quantity back to Reliant. For doing this, PSCo normally received a small profit. PSCo made a total pretax profit of approximately $110,000 on these transactions. Also, PSCo engaged in one trade with Reliant in which PSCo simultaneously bought and sold power at the same price without realizing any profit. The purpose of this nonprofit transaction was in consideration of future for-profit transactions. PSCo engaged in these transactions with Reliant for the proper commercial objective of making a profit. It did not do these transactions to inflate volumes or revenues.

Xcel Energy and PSCo have received subpoenas from the Commodity Futures Trading Commission for documents and other information concerning these so-called “round trip trades” and other trading in electricity and natural gas for the period Jan. 1, 1999 to the present involving Xcel Energy or any of its subsidiaries.

Xcel Energy also has received a subpoena from the SEC for documents concerning “round trip trades,” as defined in the SEC subpoena, in electricity and natural gas with Reliant Resources, Inc. for the period Jan. 1, 1999, to the present. The SEC subpoena is issued pursuant to a formal order of private investigation that does not name Xcel Energy. Based upon accounts in the public press, management believes that similar subpoenas in the same investigations have been served on other industry participants. Xcel Energy and PSCo are cooperating with the regulators and taking steps to assure satisfactory compliance with the subpoenas.

~~5. Commitments and Contingent Liabilities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)~~

~~Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them.~~

Xcel Energy’s Utility Subsidiaries have been or are currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, Xcel Energy’s Utility Subsidiaries are pursuing, or intend to pursue, insurance claims and believe they will recover some portion of these costs through such claims. Additionally, where applicable, Xcel Energy’s Utility Subsidiaries are pursuing, or intend to pursue, recovery from other potentially responsible parties and through the rate regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy’s Utility Subsidiaries would be required to recognize an expense for such unrecoverable amounts.

The circumstances set forth in Notes 13 and 14 to the financial statements in NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ Annual Reports on Form 10-K for the year ended Dec. 31, 2001, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. Following are unresolved contingencies, which are material to the financial position of Xcel Energy’s Utility Subsidiaries:


	•	~~Tax Matters — Tax deductibility of corporate owned life insurance loan interest~~

~~PSCo Notice of Violation —~~On July 1, 2002, PSCo received a Notice of Violation (NOV) from the United States Environmental Protection Agency (EPA) alleging violations of the New Source Review (NSR) requirements of the Clean Air Act at the Comanche and Pawnee Stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR policy announced by the EPA administrator on June 22, 2002. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its information requests, it could require PSCo to install additional emission control equipment at the facilities and pay civil penalties. Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation. The ultimate financial impact to PSCo is not determinable at this time.

~~6. Short-Term Borrowings and Financing Activities (NSP-Minnesota, PSCo and SPS)~~

~~At June 30, 2002, NSP-Minnesota had approximately $419 million of short-term debt outstanding at a weighted average interest rate of 3.690 percent.~~

As disclosed in the 2001 Form 10-K, NSP-Minnesota’s 2019 series bonds (totaling $127.9 million at June 30, 2002) were previously reported in the current portion of long-term debt due to a feature that allowed bondholders to tender their bonds for purchase to NSP-Minnesota. Based on financing agreements in place at August 14, 2002, NSP-Minnesota intends to convert these bonds to a fixed rate, with principal still maturing in 2019. As a result of the conversion to a fixed rate, bondholders will no longer be permitted to tender their bonds for purchase by the company. Accordingly, these bonds are now included in the noncurrent portion of long-term debt in the accompanying June 30, 2002 balance sheet.

~~At June 30, 2002, PSCo had approximately $561 million of short-term debt outstanding at a weighted average interest rate of 3.598 percent.~~

~~At June 30, 2002, SPS had approximately $15 million of short-term debt outstanding at a weighted average interest rate of 2.590 percent.~~

~~7. Derivative Valuation and Financial Impacts (NSP-Minnesota, PSCo and SPS)~~

Xcel Energy’s Utility Subsidiaries analyze derivative financial instruments in accordance with SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). This statement requires that all derivative financial instruments be recorded on the balance sheet at fair value unless exempted. Changes in a derivative instrument’s fair value must be recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the income statement, to the extent effective. SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

~~The components of SFAS No. 133 impacts on Other Comprehensive Income, included in stockholders’ equity, are detailed in the following table:~~

PSCo recorded pretax gains in Electric Fuel and Purchased Power of $0.9 million and pretax loss of $0.9 million for the three months ended June 30, 2002 and 2001, respectively, due to the effects of SFAS No. 133. PSCo recorded pretax gains in Electric Fuel and Purchased Power of $1.0 million and $0.2 million for the six months ended June 30, 2002 and 2001, respectively, due to the effects of SFAS No. 133. NSP-Minnesota and SPS did not realize any impact to earnings related to SFAS No. 133 during these periods.

Xcel Energy’s Utility Subsidiaries enter into fixed price contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented as normal and exempted from the accounting and reporting requirements of SFAS No. 133.

Xcel Energy’s Utility Subsidiaries evaluate all of their contracts when such contracts are entered into to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the trading operations are considered normal under the provisions of SFAS No. 133.

~~Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.~~

NSP-Minnesota, PSCo and SPS enter into derivative instruments to manage their respective exposure to changes in commodity prices. These derivative instruments take the form of fixed price, floating price or index sales or purchases and options, such as puts, calls and swaps. These derivative instruments are designated as cash flow hedges for accounting purposes and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At June 30, 2002, NSP-Minnesota, PSCo and SPS had various commodity related contracts through the next 12 months. Earnings on these cash flow hedges are recorded as the hedged purchase or sales transaction is completed. This could include the physical sale of electric energy or the usage of natural gas to generate electric energy. As of June 30, 2002, NSP-Minnesota, PSCo and SPS expect to reclassify into earnings through June 2003 net gains(losses) from Other Comprehensive Income of approximately $0.4 million, $(0.3) million and $0.7 million, respectively.

As required by SFAS No. 133, PSCo recorded gains of $0.9 million and losses of $1.3 million related to ineffectiveness on commodity cash flow hedges during the three months ended June 30, 2002 and 2001, respectively. PSCo recorded gains of $1.0 million and losses of $1.0 million related to ineffectiveness on

commodity cash flow hedges during the six months ended June 30, 2002 and 2001, respectively. PSCo recorded losses of $0.2 million for the three months ended June 30, 2001, and gains of $1.2 million for the six months ended June 30, 2001, related to derivative financial instruments excluded from the assessment of effectiveness. In 2001, an immaterial amount related to cash flow hedges that were discontinued because the hedged transactions were no longer probable.

SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS expects to reclassify into earnings through June 2003 net losses from Other Comprehensive Income of approximately $0.7 million.

Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs and hedging transactions for interest rate swaps are recorded as a component of interest expense.

NSP-Minnesota and PSCo have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in their respective Consolidated Statements of Income. All financial derivative instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Income.

Xcel Energy’s Utility Subsidiaries each have two reportable segments, Electric Utility and Gas Utility, with the exception of SPS, which has only an Electric Utility reportable segment. Trading operations are not a reportable segment; electric trading results are included in the Electric Utility segment.

SPS operates in the regulated electric utility industry, providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $266.9 million and $371.7 million for the three months ended June 30, 2002 and 2001, respectively. Revenues from external customers were $478.6 million and $701 million for the six months ended June 30, 2002 and 2001, respectively.

The accumulated comprehensive income in stockholder’s equity at June 30, 2002, relates to valuation adjustments on derivative financial instruments and hedging activities and the mark-to-market components of our marketable securities.

~~For NSP-Wisconsin, comprehensive income equals net income for the quarter and six months ended June 30, 2002 and 2001.~~

The accumulated comprehensive income in stockholder’s equity at June 30, 2002 and 2001, relates to valuation adjustments on derivative financial instruments and hedging activities and the mark-to-market component of our marketable securities.

~~The accumulated comprehensive loss in stockholder’s equity at June 30, 2002 and 2001, relates to valuation adjustments on derivative financial instruments and hedging activities.~~

~~Except for the supplemental discussion of NRG credit impacts provided below, discussion of financial condition and liquidity for the Utility Subsidiaries of Xcel Energy are omitted per~~ conditions set forth in ~~general instructions~~General Instruction H (1)(a) and (b) of Form 10-Q ~~for wholly owned subsidiaries. It~~and is ~~replaced~~therefore filing this Form 10-Q with ~~management’s narrative analysis and~~ the ~~results of operations set forth~~reduced disclosure format specified in ~~general instructions~~General Instruction H (2) ~~(a) of~~to such Form 10-Q.

NSP-Minnesota currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in accumulated depreciation. At Dec. 31, 2001, NSP-Minnesota recorded and recovered in rates $623 million of decommissioning obligations and had estimated discounted decommissioning cost obligations of $878 million.

If NSP-Minnesota adopted the standard on Jan. 1, 2002, the initial value of the liability, including cumulative interest expense through that date, would have been approximately $757 million, with a corresponding increase to net plant assets of approximately $625 million. The resulting cumulative effect adjustment for unrecognized depreciation and other expenses under the new standard is approximately $132 million. Management expects that the entire transition amount would be recoverable in rates and, therefore, would recognize an additional regulatory asset upon adoption of SFAS No. 143 rather than incur a cumulative effect charge against earnings.

SFAS No. 143 also will affect accrued plant removal costs for other generation, transmission and distribution facilities for all of the Utility Subsidiaries. Xcel Energy expects that these costs, which have yet to be estimated, are expected to be reclassified from accumulated depreciation to regulatory liabilities based on the treatment of these costs in rates. Xcel Energy expects to adopt SFAS 143 as required on Jan. 1, 2003.

~~SFAS No. 145 —~~In April 2002, the FASB issued SFAS No. 145 — “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” that supercedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. The impact of SFAS No. 145 is not expected to be material to any of the Utility Subsidiaries of Xcel Energy.

~~SFAS No. 146 —~~In July 2002, the FASB issued SFAS No. 146 — “Accounting for Exit or Disposal Activities,” addressing recognition, measurement and reporting of costs associated with exit and disposal activities, including restructuring activities. The impact of SFAS No. 146 is not expected to be material to any of the Utility Subsidiaries of Xcel Energy.

~~EITF No. 02-3~~— In June the Emerging Issues Task Force of the FASB (EITF) issued a consensus decision for EITF Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issue 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’.” EITF No. 02-3 requires that all gains and losses related to energy trading activities within the scope of EITF 98-10 (whether or not settled physically) be shown net in the statement of income. The decision requires reclassification of comparable prior periods reported and is applicable for financial statement periods ending after July 15, 2002. Xcel Energy’s Utility Subsidiaries will continue to record gains and losses on energy trading contracts in accordance with SFAS No. 133.

~~NRG Credit Impacts on Liquidity and Capital Resources of Utility Subsidiaries~~

~~Capital Sources — Short-Term Funding Sources —~~ Since the fourth quarter of 2001, various rating agencies have tightened credit standards for Xcel Energy and its subsidiaries, including NRG Energy Inc. (NRG). While NRG’s liquidity and capital requirements have been the focus of the agencies’ concerns, there have been secondary impacts on the credit ratings and capital market access of Xcel Energy’s Utility Subsidiaries.

Short-term borrowings as a source of short-term funding is affected by access to reasonably priced capital markets. This access is dependent in part on credit agency reviews. In the past year, credit ratings for Xcel Energy’s Utility Subsidiaries have been adversely affected by NRG’s credit contingencies, despite what management believes is a reasonable separation of NRG’s operations and credit risk from Xcel Energy’s utility

In June 2002, the access of Xcel Energy’s Utility Subsidiaries to commercial paper markets was reduced due to lowered credit ratings (shown above). Management believes these lower credit ratings are unwarranted given the separation of NRG’s operations and credit risk from Xcel Energy’s utility operations and financing activities. However, until the ratings are raised, Xcel Energy’s Utility Subsidiaries continue to seek sources of financing (both short-and long-term) other than commercial paper. Xcel Energy’s Utility Subsidiaries used cash or existing credit facilities to repay outstanding commercial paper obligations in July 2002. As of July 31, 2002, Xcel Energy’s Utility Subsidiaries had access to cash (including available capacity under existing credit lines) as follows: $279 million at SPS; $150 million at PSCo; $95 million at NSP-Minnesota. NSP-Minnesota recently terminated a $70 million bridge facility and is in the process of replacing this facility.

On August 14, 2002 NSP-Minnesota obtained a commitment for an amended and restated credit facility that will replace its $300 million, 364-day fully drawn credit facility scheduled to expire August 15, 2002. This credit line will be structured as a senior revolving facility and will be secured by a new series on bonds issued under its First Mortgage Trust Indenture. The new bonds will be secured with all other bonds outstanding under the Trust Agreement. The facility renewal is scheduled to be completed August 15, 2002. Xcel Energy’s Utility Subsidiaries intend to continue to take additional steps to enhance their liquidity position.

Xcel Energy’s board of directors regularly reviews its dividend policy, and is expected to do so again in the third quarter of 2002. Future dividend levels of Xcel Energy, and correspondingly of its Utility Subsidiaries to the extent a relationship in dividend levels continues, are subject to the evaluation and recommendation of Xcel Energy’s board of directors based on financial performance, cash requirements, and other factors to be considered. It is not known at this time what actions the board may take on Xcel Energy dividend levels in the future, and what impact such actions may have on the cash dividend requirements of the Utility Subsidiaries.

SIGNATURES

~~NSP-MINNESOTA’S MANAGEMENT’S DISCUSSION AND ANALYSIS~~

~~Results of Operations~~

NSP-Minnesota’s net income was approximately $75.5 million for the first six months of 2002, compared with approximately $98.6 million for the first six months of 2001. Most of the decrease is due to an unusual income item in 2001 related to conservation recovery.

~~Conservation Incentive Recovery~~

~~Operating income and income before income taxes in the first six months of 2001 were increased by $41 million (before tax) due to the reversal of a MPUC decision.~~

In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 incentives associated with state-mandated programs for electric energy conservation. NSP-Minnesota recorded a $35-million charge in 1999 based on this action. NSP-Minnesota appealed the MPUC decision and in December 2000, the Minnesota Court of Appeals reversed the MPUC decision. In January 2001, the MPUC appealed the lower court decision to the Minnesota Supreme Court. On Feb. 23, 2001, the Minnesota Supreme Court declined to hear the MPUC’s appeal. During the second quarter of 2001, NSP-Minnesota filed with the MPUC a plan that carried out, among other things, the court’s decision.

On June 28, 2001, the MPUC approved the plan and issued an order to that effect shortly thereafter. As a result, the previously recorded liabilities of approximately $41 million (including carrying charges) for potential refunds to customers were no longer required. The plan approved by the MPUC increased revenue by approximately $34 million and increased allowance for funds used during construction (AFDC) by approximately $7 million for the second quarter of 2001.

~~Based on the new MPUC policy and less uncertainty regarding conservation incentives to be approved, conservation incentives for 2002 are now being recorded on a current basis.~~

~~Electric Utility and Commodity Trading Margins~~

Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers, most fluctuations in energy costs do not affect electric utility margin.

Some electric commodity trading activity, initially recorded at NSP-Minnesota and PSCo, is partially redistributed between NSP-Minnesota, PSCo and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. Trading revenue and costs do not include the revenue and production costs associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Margins from these generating assets for utility operations (excluding sales to retail and municipal

~~customers) are included in short-term wholesale amounts, detailed below. The following table details electric utility, short-term wholesale and electric commodity trading revenue and margin:~~

Electric
Electric Short-term Commodity Consolidated
Utility Wholesale Trading Total
(Millions of dollars)
Six months ended 6/30/2002
Electric utility revenue $ 1,053 $ 49 $ — $ 1,102
Electric trading revenue — — 18 18
Electric fuel and purchased power-utility (343 ) (34 ) — (377 )
Electric trading costs — — (17 ) (17 )

Gross margin before operating expenses $ 710 $ 15 $ 1 $ 726

Margin as a percentage of revenue 67.4 % 30.6 % 5.6 % 64.8 %
Six months ended 6/30/2001
Electric utility revenue $ 1,179 $ 89 $ — $ 1,268
Electric trading revenue — — — —
Electric fuel and purchased power-utility (423 ) (62 ) — (485 )
Electric trading costs — — — —

Gross margin before operating expenses $ 756 $ 27 $ — $ 783

Margin as a percentage of revenue 64.1 % 30.3 % — 61.8 %

Electric utility revenues decreased by $126 million, or 10.7 percent, in the first six months of 2002, compared with the same period in 2001. This decrease is due largely to lower purchased power costs recovered through electric rates and the recovery of conservation incentives in 2001. Electric utility margins decreased by $46 million, or 6.1 percent in the first six months of 2002 when compared with 2001. The decrease in margins largely reflect lower shared trading margins recorded through the JOA and the recovery of conservation incentives in 2001. As discussed previously, the reversal of the MPUC decision to deny NSP-Minnesota recovery of conservation incentives increased retail revenue and margin by $35 million in the first six months of 2001. These decreases in revenues and margin were partially offset by sales growth.

~~Short-term wholesale margins decreased in the first six months of 2002, compared with the first six months of 2001, due to lower power pool prices and other market conditions.~~

~~Gas Utility Margins~~

The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. However, due to purchased gas cost recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on gas margin.

Six months ended
June 30
2002 2001
(Millions of dollars)
Gas revenue $ 277 $ 446
Cost of gas sold and transported (188 ) (355 )

Gas utility margin $ 89 $ 91

Gas revenue decreased by approximately $169 million, or 37.9 percent, in the first six months of 2002, compared with the same period in 2001, primarily due to decreases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses. Gas margin for the first six months of 2002 decreased by $2 million, or 2.2 percent, compared with the first six months of 2001, primarily

~~due to less favorable weather and a revision in 2002 to purchased gas cost recovery accruals which related to a prior period. These decreases were partially offset by retail sales growth.~~

~~Other Revenue~~

Other revenue decreased in 2002 compared to 2001 due to the transfer of refuse-derived fuel operations to NRG and the sale of First Midwest Auto Park in March 2002. The sale resulted in a gain, as discussed later. The other results of operations from these two businesses were not material to NSP-Minnesota’s net income.

~~Non-Fuel Operating Expense and Other Items~~

Other Operating and Maintenance Expense decreased by approximately $11.9 million, or 2.8 percent, for the first six months of 2002, compared with the first six months of 2001. The decreased costs reflect lower operating costs in the power delivery system and lower incentive compensation and benefit costs, partially offset by higher property insurance premiums.

Depreciation and Amortization Expense increased by approximately $6.4 million, or 3.8 percent, for the first six months of 2002, compared with the first six months of 2001, primarily due to capital additions to utility plant.

As discussed in Note 2 to the Financial Statements, during the fourth quarter of 2001 NSP-Minnesota expensed pretax special charges for planned staff consolidation costs. In the first quarter of 2002, additional pretax special charges of $4.3 million were expensed for the final costs of staff consolidations. The charges related to severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Other Income (Expense) — net increased by $10.8 million, due primarily to a gain on the sale of property by a subsidiary of NSP-Minnesota, First Midwest Auto Park, in March 2002. In addition, interest income increased due to a Minnesota income tax settlement and higher Allowance for Funds Used During Construction from the reversal of the MPUC decision related to recovery of conservation incentives discussed previously.

Interest charges and financing costs decreased by approximately $9.7 million, or 21.9 percent, for the first six months of 2002, compared with the first six months of 2001. The change is largely due to lower average debt levels and lower short-term interest rates and higher Allowance for Funds Used During Construction from the reversal of the MPUC decision related to recovery of conservation incentives discussed previously.

Taxes (other than income taxes) decreased by $15.4 million, or 15.2%, for the first six months of 2002, compared with the same period in 2001. The decline was largely due to a legislative change in Minnesota that reduced annual property taxes by approximately $30 million in September 2001 that related proportionately to the first nine months of 2001. Approximately 50 percent of this reduction in property taxes will be returned to NSP-Minnesota customers through a rate refund in 2002.

~~NSP-WISCONSIN’S MANAGEMENT’S DISCUSSION AND ANALYSIS~~

~~Results of Operations~~

~~NSP-Wisconsin’s net income was $30.4 million for the first six months of 2002, compared with $16.5 million for the first six months of 2001.~~

~~Electric Utility Margins~~

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with the quantity of electricity required and changes in the unit costs of fuel and purchased power. The fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction does not allow for recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.

Six months ended
June 30
2002 2001
(Millions of dollars)
Total electric utility revenue $ 227 $ 218
Electric fuel and purchased power (105 ) (120 )

Total electric utility margin $ 122 $ 98

Electric utility revenue increased by approximately $9 million, or 4.1 percent, in the first six months of 2002, compared with the first six months of 2001. Electric utility margin increased by approximately $24 million, or 24.5 percent, in the first six months of 2002, compared with the first six months of 2001. The revenue and margin increase reflect sales growth and an increase in base rates for Wisconsin retail customers effective Oct. 18, 2001. These increases were partially offset by the impact of warmer winter weather. Electric margin was also increased by lower fuel and purchased power costs in 2002.

~~Gas Utility Margins~~

The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. However, due to purchase gas cost recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on gas margin.

Six months ended
June 30
2002 2001
(Millions of dollars)
Gas revenue $ 59 $ 88
Cost of gas purchased and transported (43 ) (70 )

Gas margin $ 16 $ 18

Gas revenue for the first six months of 2002 decreased by $29 million, or 33.0 percent, compared with the first six months of 2001, due to warmer winter temperatures, lower sales, and decreases in the cost of gas, which is recovered in Wisconsin through the purchased gas adjustment clause mechanism. Gas margin for the first six months of 2002 decreased by $2 million, or 11.1 percent, compared with the first six months of 2001, also due to less favorable winter temperatures and lower sales in 2002.

~~Non-Fuel Operating Expense and Other Items~~

Other Operating and Maintenance Expense for the first six months of 2002 decreased by $2.2 million, or 4.3 percent, compared with the first six months of 2001, primarily due to lower incentive compensation and conservation costs.

Depreciation and Amortization Expense increased by $1.3 million, or 6.4 percent, for the first six months of 2002, compared with the first six months of 2001, due largely to increased capital additions to utility plant.

Special charges of $0.5 million were expensed for the first six months of 2002. As discussed in Note 2 to the Financial Statements, during the fourth quarter of 2001, NSP-Wisconsin expensed pretax special charges for planned staff consolidation costs. In the first quarter of 2002, additional pretax special charges were expensed for the final costs of staff consolidations. The charges related to severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Interest expense increased by $0.7 million, or 6.8 percent, for the first six months of 2002, compared with the first six months of 2001, due largely to regulatory amortization of an interest refund in 2001 that did not recur in 2002.

~~PSCo’S MANAGEMENT’S DISCUSSION AND ANALYSIS~~

~~Results of Operations~~

PSCo’s net income was approximately $129.1 million for the first six months of 2002, compared with approximately $173.7 million for the first six months of 2001. The decrease is largely due to lower margins from trading and wholesale sales.

~~Electric Utility and Commodity Trading Margins~~

Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in Colorado, most fluctuations in energy costs do not materially affect electric margin. Electric margins reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt hour and certain trading margins under the Incentive Cost Adjustment (ICA) mechanism. In addition to the ICA, PSCo has other adjustment clauses that allow certain costs to be passed through to retail customers. The Qualifying Facilities Capacity Cost Adjustment (QFCCA) provides for recovery of purchased capacity costs from certain Qualifying Facilities projects not otherwise reflected in base electric rates. The fuel clause cost recovery does not allow for complete recovery of all variable production expenses and higher costs can adversely affect earnings.

Some electric commodity trading activity, initially recorded at PSCo, is partially redistributed to NSP-Minnesota and SPS pursuant to the JOA approved by the FERC. Trading revenue and costs do not include the revenue and production costs associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Margins from these generating assets for utility operations are included in short-term wholesale amounts, discussed later. Trading margins reflect the impact of sharing certain trading margins under the ICA. The following table details electric utility, short-term wholesale and electric trading revenue and margin.

Electric
Electric Short-term Commodity Consolidated
Utility Wholesale Trading Total
(Millions of dollars)
Six months ended June 30, 2002
Electric utility revenue $ 860 $ 30 $ — $ 890
Electric trading revenue — — 790 790
Electric fuel and purchased power-utility (375 ) (31 ) — (406 )
Electric trading costs — — (792 ) (792 )

Gross margin before operating expenses $ 485 $ (1 ) $ (2 ) $ 482

Margin as a percentage of revenue 56.4 % (3.3 )% (0.3 )% 28.7 %
Six months ended June 30, 2001
Electric utility revenue $ 812 $ 388 $ — $ 1,200
Electric trading revenue — — 720 720
Electric fuel and purchased power-utility (394 ) (294 ) — (688 )
Electric trading costs — — (690 ) (690 )

Gross margin before operating expenses $ 418 $ 94 $ 30 $ 542

Margin as a percentage of revenue 51.5 % 24.2 % 4.2 % 28.2 %

Electric utility revenue increased by $48 million, or 5.9 percent, in the first six months of 2002, compared with the first six months of 2001. Electric utility margin increased by approximately $67 million, or 16.0 percent, in the first six months of 2002, compared with the first six months of 2001. The higher electric margins reflect lower unrecovered costs, due in part to resetting the base-cost recovery factor through the ICA

~~in January 2002. Electric revenues and margin also increased due to sales growth and more favorable temperatures.~~

Short-term wholesale margins and electric commodity trading margins decreased substantially in the first six months of 2002, compared with the first six months of 2001. The decrease is due to lower power pool prices and other market conditions.

~~Gas Utility Margins~~

The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. PSCo has a Gas Cost Adjustment mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of gas purchased for resale and adjusts revenues to reflect such changes in costs on a timely basis. Therefore, fluctuations in the cost of gas have little effect on gas margin.

Six months ended
June 30
2002 2001
(Millions of dollars)
Gas revenue $ 432 $ 833
Cost of gas purchased and transported (262 ) (665 )

Gas margin $ 170 $ 168

Gas revenue for the first six months of 2002 decreased by approximately $401 million, or 48.1 percent, compared with the first six months of 2001, largely due to lower gas costs recovered through rates. Gas margin for the first six months of 2002 increased by approximately $2 million, or 1.2 percent, compared with the first six months of 2001, primarily due to higher rates from a 2000 rate case, effective Feb. 1, 2001.

~~Non-Fuel Operating Expense and Other Items~~

Other Operation and Maintenance Expense increased by approximately $9.5 million, or 4.5 percent, for the first six months of 2002, compared with the first six months of 2001. The change is largely due to higher generation maintenance overhaul costs and higher property insurance premiums, partially offset by lower incentive compensation and other benefit costs.

Depreciation and Amortization Expense increased by approximately $12.4 million, or 10.6 percent, for the first six months of 2002, compared with the first six months of 2001, primarily due to increased amortization costs of software and increased depreciation resulting from capital additions to utility plant.

Special charges decreased in 2002 compared to 2001 as discussed in Note 2. Charges in 2002 related to first quarter restaffing costs. The second quarter of 2001 included special charges related to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred postemployment benefit costs at PSCo.

~~Other Income (Expense) — net for the first six months of 2001 included an $11 million pretax gain on the sale of the Boulder Hydro facility recorded in March 2001.~~

~~SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS~~

~~Results of Operations~~

~~SPS’ net income was approximately $28.2 million for the first six months of 2002, compared with approximately $46.4 million for the first six months of 2001.~~

~~Electric Utility Margins~~

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Fuel and purchased power costs are recoverable in SPS’ Texas jurisdiction through a fixed fuel factor, which is included in rates. In the New Mexico retail jurisdiction, SPS was authorized by the NMPRC to implement a monthly adjustment factor to recover fuel and purchased energy costs through a fuel clause. This change was effective with the February 2002 billing cycle. In all other jurisdictions, SPS currently recovers substantially all increases and refunds substantially all decreases in fuel and purchased power costs pursuant to monthly adjustment clauses. Due to these fuel clause recovery mechanisms for retail customers and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, the fuel clause cost recovery does not allow for complete recovery of all variable production expenses and, therefore, higher costs can adversely affect earnings.

Electric
Electric Short-term Commodity Consolidated
Utility Wholesale Trading Total
(Millions of dollars)
Six months ended 6/30/2002
Electric utility revenue $ 476 $ 3 $ — $ 479
Electric trading revenue — — — —
Electric fuel and purchased power-utility (253 ) (3 ) — (256 )
Electric trading costs — — — —

Gross margin before operating expenses $ 223 $ — $ — $ 223

Margin as a percentage of revenue 46.8 % — — 46.8 %
Six months ended 6/30/2001
Electric utility revenue $ 699 $ 2 $ — $ 701
Electric trading revenue — — — —
Electric fuel and purchased power-utility (465 ) (1 ) — (466 )
Electric trading costs — — — —

Gross margin before operating expenses $ 234 $ 1 $ — $ 235

Margin as a percentage of revenue 33.5 % 50.0 % — 33.5 %

Electric revenue decreased by approximately $222 million, or 31.7 percent, for the first six months of 2002, compared with the first six months of 2001. Electric margin decreased by approximately $12 million, or 5 percent, for the first six months of 2002, compared with the first six months of 2001. Electric revenues decreased for the first six months of 2002, compared with the first six months of 2001, largely due to decreased recovery of fuel and purchased power costs driven by declining fuel costs in 2002, and minor customer attrition. Electric revenue and margin declined for the first six months of 2002, compared with the first six months of 2001, due to lower shared trading margins recorded through the JOA and lower capacity sales.

~~Non-Fuel Operating Expense and Other Costs~~

Other Operation and Maintenance Expense increased by approximately $4.6 million, or 6.3 percent, for the first six months of 2002, compared with the first six months of 2001. The change is largely due to higher plant overhead costs and higher plant insurance premiums, partially offset by lower incentive compensation and employee benefit costs.

Depreciation and Amortization Expense increased by approximately $2.5 million, or 6 percent, for the first six months of 2002, compared with the first six months of 2001, primarily due to increased capital additions to utility plant.

~~Special charges were incurred in 2002, mainly due to a regulatory recovery adjustment and also due to restaffing costs, as discussed in Note 2.~~

Interest expense decreased by approximately $2 million, or 8.4 percent, for the first six months of 2002, compared with the first six months of 2001, due largely to lower average debt balances outstanding and declining interest rates.

~~Part II. OTHER INFORMATION~~

~~Item 1.~~ ~~Legal Proceedings~~

In the normal course of business, various lawsuits and claims have arisen against the Utility Subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4 and 5 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ 2001 Form 10-K and Item 1 of Part II of their Form 10-Q for the quarter ended March 31, 2002, for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Utility Subsidiaries of Xcel Energy and there have been no notable changes in the previously reported proceedings, except as set forth below.

~~NSP-Minnesota~~

~~Light Rail Lawsuit —~~In February 2001, NSP-Minnesota filed a lawsuit in the federal district court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail transit (LRT) line in downtown Minneapolis. In May 2001, the Minnesota Department of Transportation and the Metropolitan Council (Defendants) obtained a preliminary injunction requiring NSP-Minnesota to move certain facilities. NSP-Minnesota has complied with the preliminary injunction and utility line relocation has commenced. NSP-Minnesota is capitalizing its costs incurred as construction work in progress. In April 2002, Defendants brought motions for summary judgment before the federal district court. The court has not yet ruled on these motions and no trial date will be established until such ruling is made. The decision as to who must pay the cost of relocation will be made after trial. In collateral matters regarding LRT construction, NSP-Minnesota has commenced a mandamus action in state court seeking an order requiring Defendants to commence condemnation proceedings concerning an underground substation, access to which is blocked by LRT. NSP-Minnesota also has commenced an action in state court alleging that LRT construction violates the Minnesota Environmental Rights Act and a separate action in federal district court alleging that the Federal Transit Administration’s failure to evaluate certain environmental effects of LRT violates the National Environmental Policy Act.

~~NSP-Wisconsin~~

~~Stray Voltage —~~On March 1, 2002, NSP-Wisconsin was served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by NSP-Wisconsin harmed their dairy herd and caused them personal injury. The Gumz’s complaint alleges negligence, strict liability, nuisance, trespass, and statutory violations and seeks compensatory, punitive and treble damages. The complaint does not specify the amount of damages sought by the plaintiffs.

~~PSCo~~

~~PSCo Notice of Violation —~~On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act’s New Source Review (NSR) requirements related to alleged modifications of electric generating stations located in the South and Midwest. Subsequently, the United States Environmental Protection Agency (EPA) also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to EPA’s initial information requests related to Xcel Energy plants in Colorado.

On July 1, 2002, Xcel Energy received a Notice of Violation (NOV) from the United States Environmental Protection Agency (EPA) alleging violations of the New Source Review (NSR) requirements of the Clean Air Act at the Comanche and Pawnee Stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s

should have required a permit under the NSR process. Xcel Energy believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. Xcel Energy also believes that the projects would be expressly authorized under the EPA’s NSR policy announced by the EPA administrator on June 22, 2002. Xcel Energy disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its information requests, it could require Xcel Energy to install additional emission control equipment at the facilities and pay civil penalties. Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation. The ultimate financial impact to Xcel Energy is not determinable at this time.

~~Item 6.~~ ~~Exhibits and Reports on Form 8-K~~

~~(a) Exhibits~~

~~The following Exhibits are filed with this report:~~

~~99.01 Statement pursuant to Private Securities Litigation Reform Act.~~

~~(b) Reports on Form 8-K~~

~~The following reports on Form 8-K were filed either during the three months ended June 30, 2002, or between June 30, 2002, and the date of this report:~~

~~NSP-Minnesota, NSP-Wisconsin, PSCo and SPS~~

~~May 13, 2002, (filed May 13, 2002) Item 5. Other Events. Re: Xcel Energy (PSCo) transaction with Reliant Energy.~~

~~May 22, 2002, (filed May 24, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy (PSCo) response to FERC inquiry.~~

~~May 28, 2002, (filed May 31, 2002) Item 4. Changes in Independent Accountants.~~

~~July 1, 2002, (filed July 8, 2002) Item 5. Other Events. Re: PSCo receipt of Notice of Violation from the Environmental Protection Agency.~~

~~July 8, 2002, (filed July 10, 2002) Item 5 and 7. Other Events and Exhibits. Re: NSP-MN Underwriting Agreement.~~

~~July 16, 2002, (filed July 18, 2002) Item 5 and 7. Other Events and Exhibits. Re: NSP-MN Underwriting Agreement overallotment exercise.~~

~~July 25, 2002, (filed Aug. 1, 2002) Item 5 and 7. Other Events and Exhibits. Re: Rating Agency actions and other events.~~

~~NORTHERN STATES POWER CO. (A MINNESOTA CORPORATION) SIGNATURES~~

~~NORTHERN STATES POWER CO.~~
~~(a Minnesota corporation)~~
~~(Registrant)~~
~~/s/ DAVID E. RIPKA~~
~~David E. Ripka~~
~~Vice President and Controller~~

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. In addition each of the undersigned hereby certifies in his capacity as an officer of NSP-MN that the Quarterly Report on Form 10-Q/ A for the quarter ended June 30, 2002 fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934 and that information contained in such report fairly presents, in all material respects, the financial condition and results of operations of the issuer.



¨		~~For the quarterly period ended June 30, 2002~~

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

	~~Exact name of registrant as specified in its charter, State or other~~
~~Commission~~	~~jurisdiction of incorporation or organization, Address of principal~~		~~IRS Employer~~
~~File Number~~	~~executive offices and Registrant’s Telephone Number, including area code~~		~~Identification No.~~

~~000-31709~~	~~NORTHERN STATES POWER COMPANY~~ ~~(a Minnesota Corporation)~~ ~~414 Nicollet Mall, Minneapolis, Minn. 55401~~ ~~Telephone (612) 330-5500~~Tyler at Sixth			~~41-1967505~~
~~001-3140~~Amarillo, Texas	~~NORTHERN STATES POWER COMPANY~~ 79101
(~~a Wisconsin Corporation)~~ ~~1414 W. Hamilton Ave., Eau Claire, Wis. 54701~~ ~~Telephone (715) 839-2621~~Address of principal executive offices)		~~39-0508315~~
~~001-3280~~	~~PUBLIC SERVICE COMPANY OF COLORADO~~ (~~a Colorado Corporation)~~ ~~1225 17~~^th~~Street, Denver, Colo. 80202~~ ~~Telephone (303) 571-7511~~			~~84-0296600~~
~~001-3789~~	~~SOUTHWESTERN PUBLIC SERVICE COMPANY~~ ~~(a New Mexico Corporation)~~ ~~Tyler at Sixth, Amarillo, Texas 79101~~ ~~Telephone (303) 571-7511~~			~~75-0575400~~	Zip Code)



Large accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer x		Smaller reporting company ¨
(Do not check if smaller reporting company)



Class		Outstanding at Oct. 28, 2013
~~Northern States Power Co. (a Minnesota Corporation)~~	~~Common Stock, $0.01 par value~~	~~1,000,000 Shares~~
~~Northern States Power Co. (a Wisconsin Corporation)~~	~~Common Stock, $100 par value~~	~~933,000 Shares~~
~~Public Service Co. of Colorado~~	~~Common Stock, $0.01 par value~~	~~100 Shares~~
~~Southwestern Public Service Co.~~	Common Stock, $1 par value	100 ~~Shares~~shares


~~PART 1. FINANCIAL INFORMATION~~
~~CONSOLIDATED STATEMENTS OF INCOME~~
~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~
~~CONSOLIDATED BALANCE SHEETS~~
~~STATEMENTS OF INCOME~~
~~STATEMENTS OF CASH FLOWS~~
~~BALANCE SHEETS~~
~~CONSOLIDATED STATEMENTS OF INCOME~~
~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~
~~CONSOLIDATED BALANCE SHEETS~~
~~STATEMENTS OF INCOME~~
~~STATEMENTS OF CASH FLOWS~~
~~BALANCE SHEETS~~
~~NOTES TO FINANCIAL STATEMENTS~~
~~NSP-MINNESOTA’S MANAGEMENT’S DISCUSSION AND ANALYSIS~~
~~NSP-WISCONSIN’S MANAGEMENT’S DISCUSSION AND ANALYSIS~~
~~PSCo’S MANAGEMENT’S DISCUSSION AND ANALYSIS~~
~~SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS~~
~~Part II. OTHER INFORMATION~~
~~NORTHERN STATES POWER CO. (A MINNESOTA CORPORATION) SIGNATURES~~
~~NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) SIGNATURES~~
~~PUBLIC SERVICE CO. OF COLORADO SIGNATURES~~
~~SOUTHWESTERN PUBLIC SERVICE CO. SIGNATURES~~
~~EX-99.01 Statement Pursuant to Private Securities~~


~~(Mark One)~~
þx		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



New Mexico		~~For the transition period from to~~75-0575400


~~PART I — FINANCIAL INFORMATION~~
~~Item 1.~~	~~Financial Statements~~	2
~~Item 2.~~	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~	29
~~PART II — OTHER INFORMATION~~
~~Item 1.~~	~~Legal Proceedings~~	41
~~Item 6.~~	~~Exhibits and Reports on Form 8-K~~	42



			Three Months Ended
			June 30				Six Months Ended June 30

			2002		2001		2002		2001


			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	563,918	$	654,359	$	1,101,800	$	1,268,474
	Gas utility			89,782		92,932		277,318		445,670
	Electric trading			5,368		—		18,436		—
	Other			5,231		11,924		11,964		27,144

		Total operating revenues		664,299		759,215		1,409,518		1,741,288
Operating expenses:
	Electric fuel and purchased power			192,908		241,812		377,353		484,859
	Cost of gas sold and transported			59,390		66,123		187,878		354,515
	Electric trading costs			7,326		—		17,294		—
	Other operating and maintenance expenses			188,228		206,259		410,102		422,036
	Depreciation and amortization			87,556		83,415		172,989		166,594
	Taxes (other than income taxes)			42,612		49,493		85,929		101,341
	Special charges (see Note 2)			—		—		4,324		—

		Total operating expenses		578,020		647,102		1,255,869		1,529,345

Operating income				86,279		112,113		153,649		211,943
Other income — net of other expenses				5,896		4,037		14,560		3,808
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			17,041		19,224		34,617		44,338
	Distributions on redeemable preferred securities of subsidiary trust			3,938		3,937		7,875		7,875

		Total interest charges and financing costs		20,979		23,161		42,492		52,213

Income before income taxes				71,196		92,989		125,717		163,538
Income taxes				28,772		36,588		50,260		64,965

Net income			$	42,424	$	56,401	$	75,457	$	98,573


				June 30			Dec. 31
				2002			2001


				(Unaudited)

				(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents			$	24,911		$	17,169
	Accounts receivable — net of allowance for bad debts: $5,378 and $5,452, respectively				209,223			227,007
	Accounts receivable from affiliates				8,911			31,528
	Accrued unbilled revenues				106,096			125,770
	Materials and supplies inventories at average cost				107,226			103,934
	Fuel inventory at average cost				34,789			31,945
	Gas inventory at average cost				15,675			25,122
	Derivative instruments valuation				925			204
	Prepayments and other				51,371			48,285

			Total current assets		559,127			610,964

Property, plant and equipment, at cost:
	Electric utility plant				6,716,199			6,582,337
	Gas utility plant				696,112			695,338
	Construction work in progress				361,447			316,468
	Other				361,207			368,513

			Total property, plant and equipment		8,134,965			7,962,656
	Less accumulated depreciation				(4,460,447	)		(4,310,214	)
	Nuclear fuel — net of accumulated amortization: $1,034,441 and $1,009,855, respectively				69,428			96,315

			Net property, plant and equipment		3,743,946			3,748,757

Other assets:
	Nuclear decommissioning fund investments				595,051			596,113
	Other investments				23,882			22,542
	Regulatory assets				210,489			226,088
	Prepaid pension asset				226,817			188,287
	Other				67,218			64,278

		Total other assets			1,123,457			1,097,308

		Total assets		$	5,426,530		$	5,457,029

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt			$	231,478		$	153,134
	Short-term debt				419,180			381,184
	Accounts payable				188,040			235,930
	Accounts payable to affiliates				56,592			42,550
	Taxes accrued				127,663			168,491
	Dividends payable to parent				51,049			44,332
	Derivative instruments valuation				321			—
	Prepayments and other				63,039			76,004

			Total current liabilities		1,137,362			1,101,625

Deferred credits and other liabilities:
	Deferred income taxes				679,326			697,605
	Deferred investment tax credits				78,175			82,598
	Regulatory liabilities				474,798			468,051
	Benefit obligations and other				147,471			133,771

			Total deferred credits and other liabilities		1,379,770			1,382,025

Long-term debt					954,832			1,039,220
Mandatorily redeemable preferred securities of subsidiary trust					200,000			200,000
	Common stock — authorized 5,000,000 shares of $0.01 par value, outstanding 1,000,000 shares				10			10
Premium on common stock					804,586			762,155
Retained earnings					966,496			990,435
Leveraged ESOP					(16,881	)		(18,564	)
Accumulated other comprehensive income					355			123

	Total common stockholder’s equity				1,754,566			1,734,159
Commitments and contingencies (See Note 5)
			Total liabilities and equity	$	5,426,530		$	5,457,029



			Three Months Ended				Six Months Ended
			June 30				June 30

			2002		2001		2002		2001


			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	110,189	$	103,943	$	227,111	$	217,835
	Gas utility			18,845		17,976		59,239		87,526
	Other			25		86		111		211

		Total operating revenues		129,059		122,005		286,461		305,572
Operating expenses:
	Electric fuel and purchased power			50,115		58,993		104,646		119,516
	Cost of gas sold and transported			13,523		12,912		42,757		69,944
	Other operating and maintenance expenses			25,303		25,922		48,891		51,064
	Depreciation and amortization			11,084		10,278		21,839		20,521
	Taxes (other than income taxes)			4,117		3,972		8,217		8,034
	Special charges (see Note 2)			—		—		512		—

		Total operating expenses		104,142		112,077		226,862		269,079
Operating income				24,917		9,928		59,599		36,493
Other income (expense) — net				171		441		993		735
Interest charges				5,740		5,302		11,573		10,841

Income before income taxes				19,348		5,067		49,019		26,387
Income taxes				6,930		1,653		18,650		9,881

Net income			$	12,418	$	3,414	$	30,369	$	16,506



			Three Months Ended June 30					Six Months Ended June 30

			2002		2001			2002			2001


			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	451,880	$	610,135		$	889,529		$	1,199,817
	Electric trading			490,177		421,848			790,436			720,280
	Gas utility			115,563		284,734			432,428			832,534
	Steam and other			5,213		6,784			12,978			19,068

		Total operating revenues		1,062,833		1,323,501			2,125,371			2,771,699
Operating expenses:
	Electric fuel and purchased power			196,775		347,568			405,943			688,326
	Electric trading costs			488,894		413,014			792,753			690,156
	Cost of gas sold and transported			50,862		217,088			261,706			665,384
	Cost of sales — steam and other			2,275		2,137			3,800			7,612
	Other operating and maintenance expenses			105,460		110,954			222,778			213,243
	Depreciation and amortization			64,094		58,185			128,658			116,281
	Taxes (other than income taxes)			20,440		22,029			42,711			43,878
	Special charges (see Note 2)			—		23,018			131			23,018

		Total operating expenses		928,800		1,193,993			1,858,480			2,447,898

Operating income				134,033		129,508			266,891			323,801
Other income (expense) — net				980		(2,488	)		(112	)		7,241
Interest charges and financing costs:
	Interest charges — net of amount capitalized			32,459		29,006			60,114			59,171
	Distributions on redeemable preferred securities of subsidiary trust			3,572		3,800			7,372			7,600

		Total interest charges and financing costs		36,031		32,806			67,486			66,771

Income before income taxes				98,982		94,214			199,293			264,271
Income taxes				36,621		27,912			70,240			90,579

Net income			$	62,361	$	66,302		$	129,053		$	173,692



	June 30, 2002				Dec. 31, 2001

	Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amount		Amortization		Amount		Amortization


	(Thousands of dollars)
NSP-Minnesota	$	4,867	$	426	$	4,867	$	324
NSP-Wisconsin		—		—		—		—
PSCo		—		—		—		—
SPS		—		—		—		—


			Accrued
	Dec. 31, 2001		Special					June 30, 2002
	Liability		Charges		Payments			Liability


	(Millions of Dollars)
Utility and corporate employee severance	$	37	$	9	$	(21	)	$	25
Special charge activities for Utility Subsidiaries:
NSP-Minnesota	$	5	$	4	$	(4	)	$	5
NSP-Wisconsin		2		1		(2	)		1
PSCo.		2		—		(1	)		1
SPS		1		—		—			1



	Six months ended June 30, 2002

	NSP-Minnesota			PSCo			SPS


	(Millions of dollars)
Accumulated other comprehensive income (loss) related to SFAS No. 133 — Jan. 1, 2002	$	0.1		$	(4.3	)	$	(4.4	)
After-tax net unrealized gains related to derivatives accounted for as hedges		0.6			9.0			0.9
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(0.3	)		(5.0	)		0.1

Accumulated other comprehensive income (loss) related to SFAS No. 133 — June 30, 2002	$	0.4		$	(0.3	)	$	(3.4	)


	*~~PSCo~~*


	*~~SPS~~*


	*~~NSP-Minnesota~~*



	Six months ended June 30, 2001

	NSP-Minnesota		PSCo			SPS


	(Millions of dollars)
Net unrealized transition gain (loss) at adoption, Jan. 1, 2001	$	—	$	1.6		$	(2.6	)
After-tax net unrealized losses related to derivatives accounted for as hedges		—		(17.5	)		(2.4	)
After-tax net realized losses on derivative transactions reclassified into earnings		—		15.8			0.2

Accumulated other comprehensive loss related to SFAS No. 133 — June 30, 2001	$	—	$	(0.1	)	$	(4.8	)


		Electric		Gas						Consolidated
		Utility		Utility			All Other			Total


		(Thousands of dollars)
Three months ended June 30, 2002
Revenues from:
External customers		$	569,154	$	90,076		$	5,231		$	664,461
Internal customers			132		(294	)		—			(162	)

	Total revenue		569,286		89,782			5,231			664,299
Segment net income		$	38,638	$	3,575		$	211		$	42,424
June 30, 2001
Revenues from:
External customers		$	654,192	$	94,360		$	11,924		$	760,476
Internal customers			167		(1,428	)		—			(1,261	)

	Total revenue		654,359		92,932			11,924			759,215
Segment net income (loss)		$	54,628	$	1,901		$	(128	)	$	56,401
Six months ended June 30, 2002
Revenues from:
External customers		$	1,119,941	$	277,289		$	11,964		$	1,409,194
Internal customers			295		29			—			324

	Total revenue	$	1,120,236		277,318			11,964			1,409,518
Segment net income		$	66,700	$	8,222		$	535		$	75,457
June 30, 2001
Revenues from:
External customers		$	1,268,128	$	445,526		$	27,144		$	1,740,798
Internal customers			346		144			—			490

	Total revenue		1,268,474		445,670			27,144			1,741,288
Segment net income (loss)		$	80,790	$	18,034		$	(251	)	$	98,573



*	•	~~general economic conditions, including their impact on capital expenditures and the ability of Xcel Energy’s Utility Subsidiaries to obtain financing on favorable terms;~~Indicates incorporation by reference
#	This exhibit is filed or furnished herewith
##	• This exhibit has been previously filed or furnished

~~business conditions in the energy industry;~~

##3.01*	• Amended and Restated Articles of Incorporation of SPS dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
#3.02	~~competitive factors, including the extent~~ By-Laws of SPS as Amended and ~~timing~~Restated on Sept. 26, 2013.
#31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the ~~entry~~Sarbanes-Oxley Act of ~~additional competition in the markets served by the Utility Subsidiaries of Xcel Energy;~~2002.
#31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
##32.01	•	~~unusual weather;~~Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
##99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
##101	•	state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and gas markets;

	•	~~risks associated with the California and other western power markets; and~~

	•	~~the other risk factors listed~~The following materials from ~~time to time by the Utility Subsidiaries of Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this~~SPS’ Quarterly Report on Form 10-Q for the quarter ended ~~June~~Sept. 30, ~~2002.~~2013 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of Comprehensive Income (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) Notes to Condensed Financial Statements, and (vi) document and entity information.


							Electric
	Electric			Short-term			Commodity			Consolidated
	Utility			Wholesale			Trading			Total


	(Millions of dollars)
Six months ended 6/30/2002
Electric utility revenue	$	1,053		$	49		$	—		$	1,102
Electric trading revenue		—			—			18			18
Electric fuel and purchased power-utility		(343	)		(34	)		—			(377	)
Electric trading costs		—			—			(17	)		(17	)

Gross margin before operating expenses	$	710		$	15		$	1		$	726

Margin as a percentage of revenue		67.4	%		30.6	%		5.6	%		64.8	%
Six months ended 6/30/2001
Electric utility revenue	$	1,179		$	89		$	—		$	1,268
Electric trading revenue		—			—			—			—
Electric fuel and purchased power-utility		(423	)		(62	)		—			(485	)
Electric trading costs		—			—			—			—

Gross margin before operating expenses	$	756		$	27		$	—		$	783

Margin as a percentage of revenue		64.1	%		30.3	%		—			61.8	%


	~~NORTHERN STATES POWER CO.~~
	~~(a Minnesota corporation)~~
	~~(Registrant)~~

	~~/s/ DAVID E. RIPKA~~

	~~David E. Ripka~~
	~~Vice President and Controller~~



	~~/s/ RICHARD C. KELLY~~



	~~Richard C. Kelly~~

	~~Vice President and Chief Financial Officer~~

	~~/s/ WAYNE H. BRUNETTI~~

	~~Wayne H. Brunetti~~
	~~Chairman, President and Chief Executive Officer~~


	~~NORTHERN STATES POWER CO.~~	Southwestern Public Service Company
	~~(a Wisconsin corporation)~~
Nov. 8, 2013	By:	/s/ JEFFREY S. SAVAGE
	~~(Registrant)~~	Jeffrey S. Savage
		Vice President and Controller

		/s/ ~~DAVID E. RIPKA~~TERESA S. MADDEN
		Teresa S. Madden
	~~David E. Ripka~~
	Senior Vice President, ~~and Controller~~


	~~/s/ EDWARD J. MCINTYRE~~

	~~Edward J. McIntyre~~
	~~Vice President and~~ Chief Financial Officer

	~~/s/ WAYNE H. BRUNETTI~~

	~~Wayne H. Brunetti~~
	~~Chairman, President~~ and ~~Chief Executive Officer~~Director