-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Pa7eaeRMkPBGG2LjJineW8l5BE9RfbVe9cvQ0OGUcUKvfQ1fwxK1wgeqDpao630u f7G2O7rsZB7K3KHK2ULmSQ== 0000072909-97-000001.txt : 19970401 0000072909-97-000001.hdr.sgml : 19970401 ACCESSION NUMBER: 0000072909-97-000001 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970331 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO /WI/ CENTRAL INDEX KEY: 0000072909 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 390508315 STATE OF INCORPORATION: WI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03140 FILM NUMBER: 97571017 BUSINESS ADDRESS: STREET 1: 100 N BARSTOW ST CITY: EAU CLAIRE STATE: WI ZIP: 54702 BUSINESS PHONE: 7158392621 MAIL ADDRESS: STREET 1: P O BOX 8 CITY: EAU CLAIRE STATE: WI ZIP: 54702-008 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) X Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (fee required) or Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (no fee required) For the fiscal year ended December 31, 1996 Commission file number: 10-3140 Northern States Power Company, a Wisconsin corporation, meets the conditions set forth in general instruction J (1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format. (In general instruction J(2)) Northern States Power Company (Exact name of registrant as specified in its charter) Wisconsin 39-0508315 (State or other jurisdiction of (I.R.S. employer identification number) incorporation or organization) 100 North Barstow Street 54703 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code (715) 839-2592 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ ___ Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date. Class Outstanding at March 24, 1997 Common Stock, $100 Par Value 862,000 Shares All outstanding common stock is owned beneficially and of record by Northern States Power Company, a Minnesota corporation. Documents Incorporated by Reference None INDEX Page No. PART I Item 1 Business 1 PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION 1 REGULATION AND RATES Utility Industry Restructuring in Wisconsin & Michigan 5 Construction Authorization 6 Ratemaking Principles in Wisconsin 6 Fuel and Purchased Gas Adjustment Clauses 7 Rate Matters by Jurisdiction 8 Electric Transmission Tariffs and Settlement (FERC) 9 Minnesota Company Jurisdictions' Proposed Merger Transaction Proceedings 11 ELECTRIC OPERATIONS Competition 12 NSP System 13 Capability and Demand 13 Demand Side Management 14 Interchange Agreement 14 Electric Power Pooling Agreements 15 Fuel Supply 15 Electric Operating Statistics 16 GAS OPERATIONS 16 ENVIRONMENTAL MATTERS 18 CONSTRUCTION AND FINANCING 20 EMPLOYEES AND EMPLOYEE BENEFITS 20 Item 2 Properties 21 Item 3 Legal Proceedings 22 Item 4 Submission of Matters to a Vote of Security Holders 22 PART II Item 5 Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters 23 Item 6 Selected Financial Data 23 Item 7 Management's Discussion and Analysis 23 Item 8 Financial Statements and Supplementary Data 25 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 41 PART III Item 10 Directors and Executive Officers of the Registrant 42 Item 11 Executive Compensation 42 Item 12 Security Ownership of Certain Beneficial Owners and Management 42 Item 13 Certain Relationships and Related Transactions 42 PART IV Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 43 SIGNATURES 46 EXHIBITS (EXCERPT) Statement pursuant to Private Securities Litigation Reform Act of 1995 47 Unaudited Pro Forma Financial Information 49 PART I Item 1. Business Northern States Power Company (the Company), incorporated in 1901 under the laws of Wisconsin as the La Crosse Gas and Electric Company, is an operating public utility company with executive offices at 100 North Barstow Street, Eau Claire, Wisconsin 54703 (Phone: (715) 839-2592). The Company is a wholly- owned subsidiary of Northern States Power Company, a Minnesota corporation (the Minnesota Company). The Minnesota Company and its subsidiaries collectively are referred to herein as NSP. The Company is engaged in the generation, transmission, and distribution of electricity to approximately 211,400 retail customers in an area of approximately 18,900 square miles in northwestern Wisconsin, to approximately 9,600 electric retail customers in an area of approximately 300 square miles in the western portion of the Upper Peninsula of Michigan, and to ten wholesale customers in the same general area. The Company is also engaged in the distribution and sale of natural gas in the same service territory to approximately 69,000 customers in Wisconsin and 4,800 customers in Michigan. In Wisconsin, some of the larger communities the Company provides natural gas to are Eau Claire, Chippewa Falls, La Crosse, Hudson, Menomonie and Ashland. In the Upper Peninsula of Michigan, the largest community to which the Company provides natural gas is Ironwood. In 1996, the Company derived 81 percent of its total operating revenues from electric utility operations and 19 percent from gas utility operations. As of December 31, 1996, the Company had 861 full-time equivalent employees including 763 full-time employees. Except for the historical information contained herein, the matters discussed in this form 10-K, including the statements regarding the anticipated impact of the proposed merger, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including their impact on capital expenditures; business conditions in the energy industry; competitive factors; unusual weather; changes in federal or state legislation; regulatory decisions regarding the proposed combination of NSP and WEC, and the other risk factors listed from time to time by the Company in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this report on Form 10-K. PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION Description of the Merger Transaction As initially announced in the Company's Current Report on Form 8-K dated April 28, 1995 and filed on May 8, 1995 (the Company's 4/28/95 8-K), the Minnesota Company, Wisconsin Energy Corporation, a Wisconsin corporation (WEC), Northern Power Wisconsin Corp., a Wisconsin corporation and wholly-owned subsidiary of the Minnesota Company (New NSP) and WEC Sub Corp., a Wisconsin corporation and wholly owned subsidiary of WEC (WEC Sub), have entered into an Amended and Restated Agreement and Plan of Merger, dated as of April 28, 1995, as amended and restated as of July 26, 1995 (the Merger Agreement), which provides for a business combination of the Minnesota Company and WEC in a "merger-of-equals" transaction (the Merger Transaction). On September 13, 1995, the merger plan was approved by more than 95 percent of the respective shareholders of the Minnesota Company and WEC voting at their respective shareholder meetings. The agreement to merge is subject to a number of conditions, including approval by applicable regulatory authorities. NSP continues to work with WEC to complete the merger. However, since numerous conditions are beyond its control, NSP cannot state whether the merger will occur. See discussion of the regulatory proceedings under the caption "Regulation and Rates - Rate Matters by Jurisdiction" herein. Additional information regarding the merger is included in Item 8, Note 11 of the Notes to Financial Statements and unaudited pro forma financial statements are included in exhibits listed in Item 14. In the Merger Transaction, Primergy Corporation (Primergy), which will be registered under the Public Utility Holding Company Act of 1935, as amended, will be the parent company of both the Minnesota Company (which for regulatory reasons, will reincorporate in Wisconsin) and WEC's current principal utility subsidiary, Wisconsin Electric Power Company (WEPCO), which will be renamed "Wisconsin Energy Company." It is anticipated that, at the time of the Transaction, except for certain gas distribution properties transferred to the Minnesota Company, the Company will be merged into Wisconsin Energy Company and the subsidiaries of the Company will become direct Primergy subsidiaries. The Merger Agreement, and the press release issued in connection therewith, and the related Stock Option Agreements (defined below) are filed as exhibits to this report and are incorporated herein by reference. The descriptions of the Merger Agreement and the Stock Option Agreements set forth herein do not purport to be complete and are qualified in their entirety by the provisions of the Merger Agreement and the Stock Option Agreements, as the case may be, and the other exhibits filed with this report. Under the terms of the Merger Agreement, the Minnesota Company is to be merged with and into New NSP and immediately thereafter WEC Sub will be merged with and into New NSP, with New NSP being the surviving corporation. Each outstanding share of the Minnesota Company's common stock, par value $2.50 per share (NSP Common Stock), will be canceled and converted into the right to receive 1.626 shares of common stock, par value $.01 per share, of Primergy (Primergy Common Stock). The outstanding shares of WEC common stock, par value $.01 per share (WEC Common Stock), will remain outstanding, unchanged, as shares of Primergy Common Stock. Each outstanding share of the Minnesota Company's cumulative preferred stock, par value $100.00 per share, will be canceled and converted into the right to receive one share of cumulative preferred stock, par value $100.00 per share, of New NSP with identical rights (including dividend rights) and designations. Following the merger of the Company into Wisconsin Energy Company, the Company's outstanding first mortgage bonds will become obligations of Wisconsin Energy Company, but will continue to be secured under the Company's Supplemental and Restated Trust Indenture only to the extent of the mortgaged and pledged property that is acquired by Wisconsin Energy Company, and will not be secured by any other assets of Wisconsin Energy Company. WEPCO's outstanding preferred stock will remain outstanding and be unchanged in the Merger Transaction. It is anticipated that Primergy will adopt the Minnesota Company's dividend payment level adjusted for the exchange ratio. The Minnesota Company currently pays $2.76 per share annually, and WEC's annual dividend rate is currently $1.52 per share. Based on the 1.626 stock exchange ratio and the Company's current dividend rate, the pro forma dividend rate for Primergy Common Stock would be $1.70 per share as of December 31, 1996. However, the amount, declaration, and timing of dividends on Primergy Common Stock will be a business decision to be made by the Primergy Board of Directors from time to time based upon the results of operations and financial condition of Primergy and its subsidiaries and such other business considerations as the Primergy Board considers relevant in accordance with applicable laws. Merger Consummation Conditions The Merger Transaction is subject to numerous closing conditions, including, without limitation, the receipt of all necessary governmental approvals without materially adverse terms and the making of all necessary governmental filings, including approvals of state utility regulators in Wisconsin, Minnesota and certain other states, the approval of the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission (NRC), and the filing of the requisite notification with the Federal Trade Commission and the Department of Justice under the Hart-Scott- Rodino Antitrust Improvements Act of 1976, as amended, and the expiration of the applicable waiting period thereunder. (See discussion of the utility regulation proceedings under the caption "Regulation and Rates - Rate Matters by Jurisdiction" herein.) The Merger Transaction is also subject to receipt of assurances from the parties' independent accountants that the Merger Transaction will qualify as a pooling of interests for accounting purposes under generally accepted accounting principles. In addition, the consummation of the Merger Transaction is conditioned upon the approval for listing of such shares on the New York Stock Exchange. During 1995, in addition to shareholder and Board of Directors approval, the Minnesota Company and WEC took the following steps toward fulfilling the conditions to closing: - Registration statements filed by the Minnesota Company and WEC with the SEC with respect to the Primergy Common Stock to be issued in the Merger Transaction and New NSP Preferred Stock became effective. - The Minnesota Company and WEC received a ruling from the Internal Revenue Service indicating that the proposed merger transactions would qualify as independent tax-free reorganizations under applicable tax law. - The Minnesota Company and WEC filed for regulatory approval of the Merger Transaction with the FERC and state commissions. (See "Regulation and Rates - Rate Matters by Jurisdiction" for further discussion of the status of these filings.) - The Minnesota Company filed for NRC approval of the transfer of nuclear operating licenses from the Minnesota Company to New NSP. During 1996 the Minnesota Company and WEC made the following filings as part of the regulatory approval process of the Merger Transaction: - An Application was filed for SEC approval of the Registration of Primergy under the Public Utility Holding Company Act of 1935, as amended. - Notification under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, was filed with the United States Department of Justice. During 1997, the United States Department of Justice served its second request for information and documents. NSP and WEC anticipated responding to the second request in March 1997. As noted above, completion of the merger is subject to numerous conditions under the Merger Agreement that, unless waived by the affected party, must be met, including but not limited to the prior receipt of all necessary regulatory approvals without the imposition of materially adverse terms; the accuracy of each party's representations and warranties in the Merger Agreement at closing, other than representations and warranties whose inaccuracy does not result in a material adverse effect on the business, assets, financial condition, results of operations or prospects of such party and its subsidiaries taken as a whole; and no such material adverse effect having occurred, or being reasonably likely to occur, with respect to either party, at the time of the closing. NSP continues to work with WEC to complete the merger. However, since numerous conditions are beyond its control, NSP cannot state whether all necessary conditions for completion of the merger will occur. The Merger Agreement The Merger Agreement contains certain covenants of the parties pending the consummation of the Merger Transaction. Generally, the parties must carry on their businesses in the ordinary course consistent with past practice, may not increase dividends on common stock beyond specified levels, and may not issue capital stock beyond certain limits. The Merger Agreement also contains restrictions on, among other things, charter and bylaw amendments, capital expenditures, acquisitions, dispositions, incurrence of indebtedness, certain increases in employee compensation and benefits, and affiliate transactions. In accordance with the Merger Agreement, upon the consummation of the Merger Transaction, James J. Howard, Chairman, President, and Chief Executive Officer of the Minnesota Company will initially serve as the Chairman and Chief Executive Officer of Primergy for a minimum of 16 months after the effectiveness of the Merger Transaction and will thereafter serve only as Chairman of the Board of Primergy for a minimum of two years. Also, Richard A. Abdoo, Chairman, President and Chief Executive Officer of WEC shall initially hold the positions of Vice Chairman of the Board, President and Chief Operating Officer of Primergy and thereafter shall be entitled to hold the additional position of Chief Executive Officer when Mr. Howard ceases to be Chief Executive Officer. Mr. Abdoo will assume the position of Chairman when Mr. Howard ceases to be Chairman. The Merger Agreement may be terminated under certain circumstances, including (1) by mutual consent of the parties; (2) by any party if the Merger Transaction is not consummated by April 30, 1997 (provided, however, that such termination date shall be extended to October 31, 1997 if all conditions to closing the Merger Transaction, other than the receipt of certain consents and/or statutory approvals by any of the parties, have been or are capable of being fulfilled at April 30, 1997); (3) by any party if either the Minnesota Company's or WEC's shareholders vote against the Merger Transaction or if any state or federal law or court order prohibits the Merger Transaction; (4) by a non- breaching party if there exist breaches of any representations or warranties made in the Merger Agreement as of the date thereof which breaches, individually or in the aggregate, would result in a material adverse effect on the breaching party and which is not cured within 20 days after notice; (5) by a non-breaching party if there occur breaches of specified covenants or material breaches of any covenant or agreement which are not cured within 20 days after notice; (6) by either party if the Board of Directors of the other party shall withdraw or adversely modify its recommendation of the Merger Transaction or shall approve any competing transaction; or (7) by either party, under certain circumstances, as a result of a third-party tender offer or business combination proposal which such party's board of directors determines in good faith that their fiduciary duties require be accepted, after the other party has first been given an opportunity to make concessions and adjustments in the terms of the Merger Agreement. In addition, the Merger Agreement provides for the payment of certain termination fees by one party to the other in the event of a willful breach or acceptance of a third-party tender offer or business combination. Concurrently with the Merger Agreement, the Minnesota Company and WEC have entered into reciprocal stock option agreements (the "Stock Option Agreements") each granting the other an irrevocable option to purchase up to that number of shares of Common Stock of the other company which equals 19.9 percent of the number of shares of common stock of the other company outstanding on April 28, 1995 at an exercise price of $44.075 per share, in the case of Minnesota Company Common Stock, or $27.675 per share, in the case of WEC Common Stock, under certain circumstances if the Merger Agreement becomes terminable by one party as a result of the other party's breach or as a result of the other party becoming the subject of a third-party proposal for a business combination. Any party whose option becomes exercisable (the "Exercising Party") may request the other party to repurchase from it all or any portion of the Exercising Party's option at the price specified in the Stock Option Agreements. Results of the Merger Transaction Assuming the merger is completed, a transition to a new organization would begin. At the time that the Merger Agreement was signed, anticipated cost savings of the new organization (compared with the continued independent operation of NSP and WEC) were estimated to be approximately $2 billion over a 10-year period, net of transaction costs (about $30 million) and costs to achieve the merger savings (about $122 million). The actual realization of these savings will be dependent on numerous factors. It is anticipated that the proposed merger will allow the companies to implement a modest reduction in electric retail rates as described below followed by a rate freeze for electric and gas retail customers. This rate plan is currently being considered by various regulatory agencies. The Company and WEPCO have proposed an average retail electric rate reduction of 1.5 percent and a four-year-rate freeze in the electric retail jurisdiction for customers of Wisconsin Energy Company. The electric rate reduction of 1.5 percent would be implemented as soon as reasonably possible following the receipt of the necessary approvals and closing of the Merger Transaction. This proposed rate reduction is made in conjunction with the proposal to recover deferred Merger Transaction costs and costs incurred to achieve merger savings through amortization over the same period. In addition, the companies agreed to provide a four-year freeze in wholesale electric rates effective once the merger is completed. The Company has proposed a $0.6 million rate decrease and a four-year freeze for retail natural gas rates in its Wisconsin jurisdiction. In addition, any net purchased gas cost savings would be reflected in gas rates for customers in Wisconsin automatically through the purchased gas adjustment clause mechanism. The remaining benefits will support the rate freeze, as well as offset a portion of the rising gas utility costs other than the purchased cost of gas. The total savings identified as a result of the Merger Transaction represent aggressive goals which the Minnesota Company and WEC intend to achieve, but the rate freeze will result in some risk to the Minnesota Company's shareholders if the anticipated cost savings are not realized. There is uncertainty regarding the timing and levels of the savings and costs associated with the Merger Transaction. The proposal to unilaterally reduce rates and institute a rate freeze is designed to shield customers from these uncertainties. This proposal permits customers the opportunity to immediately begin realizing benefits of the Merger Transaction notwithstanding these uncertainties. Further, the four-year rate freeze permits the companies a reasonable time period to implement the changes necessary to achieve the contemplated savings. The commitment not to increase electric rates does not prohibit tariff amendments and rate design changes which would not increase electric net income during the moratorium. Finally, as part of this proposal, Primergy's operating utility subsidiaries will work with regulatory commissions to develop a plan for managing merger benefits for the year 2001 and beyond. The Company and WEPCO recognize that during the four-year rate freeze period, it may experience certain significant but uncontrollable events which necessitate rate changes. Accordingly, as part of the rate plan proposal, the Company and WEPCO have identified certain events (large increases in taxes and government-mandated costs, and extraordinary events) which it believes should be excepted from the rate freeze. The exceptions are necessary in order to protect Wisconsin Energy Company from major cost increases or events which are beyond its control. The Company and WEPCO propose that for these uncontrollable events it be allowed to file with the PSCW during the rate freeze period for recovery of the costs related to these events. The Company, the Minnesota Company and WEC recognize that the divestiture of their existing gas operations and certain non- utility operations is a possibility under the new registered holding company structure, but have been working with the SEC to retain such businesses. Based on prior decisions and other actions by the SEC, the retention of both the gas and non- regulated businesses seems possible after consummation of the Merger Transaction. If divestiture is ultimately required, the SEC has historically allowed companies sufficient time to accomplish divestitures in a manner that protects shareholder value. Also, regulatory authorities may require the use of an independent transmission system operator (ISO) or divestiture of certain transmission and/or generation assets. The Company currently cannot determine if such divestitures would be required by regulators. In addition, Wisconsin state law limits the total assets of non-utility affiliates of Primergy, which, depending on interpretations of the law, may limit growth of nonregulated operations. REGULATION AND RATES Utility Industry Restructuring in Wisconsin & Michigan Because of the increased focus on competition in the electric and natural gas utility industries, the Public Service Commission of Wisconsin (PSCW) is investigating changes in the structure and regulation of both industries. The Company has actively participated in these proceedings. In 1994, the PSCW asked each utility in the state for comments regarding retail competition. In response to the request, the Company filed the following recommendations: (1) competition should be phased in for retail markets by customer classes, with all customers having choice of supplier by 2001, (2) the generation segment of the industry should be deregulated by 2001, (3) prudent stranded costs should be recovered prior to the advent of retail wheeling and (4) utilities and other competitors should have a level playing field for issues such as obligation to serve, eminent domain, requirements for demand side management, funding of social programs, opening of retail markets to competition and other issues. Also, as an outcome of the responses to the PSCW, a task force was formed by the PSCW to analyze the industry restructuring necessary in the state of Wisconsin. To date, after reviewing a set of proposals developed by its working group, the PSCW has set a target date of 2001 for implementing competition in retail electric markets, established prerequisites for retail competition and defined a work plan for achieving the prerequisites. The work plan includes unbundling the components of the integrated utility, setting service standards and establishing methods for the continued promotion of energy conservation and renewable resources. In February 1996, the PSCW issued its report to the state legislature on restructuring the electric industry. The report was the culmination of over a year of work by representatives from a wide range of interests, including low income advocates, environmental groups, consumer groups, regulators and the utilities. The Company played an active role in the efforts. Key elements of the report include: (1) unbundling the vertically- integrated utility functions into generation, transmission, distribution and energy services; (2) improving competition in electric generation while insuring consumer access to the low costs associated with existing power plants; (3) preventing the exercise of market power by large companies; (4) revising Wisconsin's regulatory processes while protecting the environment; (5) working to transform the transmission system into a common carrier; (6) developing distribution and retail service requirements and (7) developing alternative means for funding and providing social benefits to customers. The report included a 32 step plan to achieve these elements with the ultimate goal of opening the retail market to competition by the year 2001. The PSCW began implementing the 32 step plan in 1996. As of the end of the year, parties have filed plans with the PSCW to unbundle utility functions; completed hearings on revising the State's Advance Plan and Certificate of Public Convenience and Necessity processes; developed proposals regarding the funding and delivery of low income, energy efficiency, renewable resource and environmental research services; and began work on an initial distribution and retail service requirements. In addition, the PSCW issued an order in September that set minimum standards for creating an ISO that differs from the Company's and WEC's proposal for an ISO related to the proposed merger to form Primergy. In Michigan, the Michigan Public Service Commission (MPSC) recently released a report setting out their proposal for instituting retail access. In their report, the MPSC endorsed two fundamental principles: (1) all customers should be eligible to participate in the emerging competitive market, and (2) rates should not be increased for any customers and should be reduced where possible. The MPSC's plan calls for utilities to open up 2 1/2% of their loads each year beginning in 1997, with full retail access in effect by the year 2007. Also, the plan calls for stranded costs to be recovered through the use of rate reduction bonds; the institution of performance based rates for transmission and distribution service, the requirement that originating suppliers in any retail access transaction provide reciprocal rights to the utility providing the retail direct access service, distribution utility provision of service to customers who do not choose to participate or who cannot participate in the program, and unbundling of rates into separate functions. Parties were asked to comment by January 21, 1997. The Company filed comments generally recommending that the MPSC permit utilities whose operations are primarily in Wisconsin to follow retail competition approved in Wisconsin with respect to consumer choice. During 1995, the PSCW decided that, as competition increases in natural gas markets, distribution service will need to be totally separated from unregulated activities. To further that objective, during 1996, the PSCW adopted standards of conduct to govern transactions between utilities and their gas marketing affiliates. They also examined the issue of how to determine when specific markets are competitive and ready for deregulation. This is the point at which natural gas utilities will need to stop offering unregulated services. An order is expected in this docket this year. In 1997, the PSCW will determine how utility consumer protection services, such as the winter moratorium and supplier of last resort, and utility public benefit programs, such as low income and energy efficiency services, should be implemented in the future. As part of the gas restructuring efforts in Michigan, the MPSC issued an order on October 7, 1996, authorizing Michigan utilities to file customer choice pilot programs. Under these pilots, customers would be free to choose their gas supplier. The order did not mandate such pilots, but left it up to the individual utilities. The Company has no immediate plans to file for such a pilot. Construction Authorization Prior to the construction of a major electric project, the Company is required to obtain various licenses and permits, including either a certificate of authority (CA) or a certificate of public convenience and necessity (CPCN), from the PSCW. In 1995, the Wisconsin legislature passed statutory changes raising the minimum project expenditure requiring a CA generally from $1,000,000 to $3,000,000. Any transmission projects costing less than $3,000,000, and less than 10 miles in length, no longer require PSCW approval. Before a major electric project can receive a CPCN, it must have received PSCW planning approval through the Advance Plan process. In this process, Wisconsin utilities' twenty year generation and transmission construction plans are reviewed. In 1995, the Company received approval of its most recent Advance Plan filing. Ratemaking Principles in Wisconsin The PSCW and MPSC regulate the rates and service of the Company with respect to retail sales within the State of Wisconsin and the State of Michigan, respectively, and various other aspects of the Company's operations. The PSCW also exercises jurisdiction over the construction of certain electric and gas facilities and the issuance of new securities. The Company is also subject to the jurisdiction of the FERC with respect to its sales to wholesale electric customers and certain other aspects of its operations, including the licensing and operation of hydro projects and the Company's Interchange Agreement (see Electric Operations-Interchange Agreement). Approximately 92.0 percent of the Company's 1996 revenues from sales were subject to PSCW jurisdiction. Of the 92.0 percent, 70.8 percent was generated from electric retail revenues and the remaining 21.2 percent from retail gas revenues. The Company's wholesale revenues from sales subject to FERC jurisdiction were approximately 4.5 percent of the Company's 1996 revenues from sales with the remaining 3.5 percent of revenues from sales subject to MPSC jurisdiction. For the purpose of rate regulation, all three of the regulatory jurisdictions allow a "forward looking" test year corresponding to the time that rates are to be put into effect. The PSCW has a biennial filing requirement for processing rate cases and monitoring utilities' rates. By June 1 of each odd-numbered year, the Company must submit filings for calendar test years beginning the following January 1. The filing procedure and subsequent review generally allow the PSCW sufficient time to issue an order effective with the start of the test year. The PSCW can deviate from requirements for special circumstances as noted below. The PSCW reviews each utility's cash position to determine if a current return on Construction Work in Progress (CWIP) will be allowed. The PSCW will allow either a return on CWIP or capitalization of Allowance for Funds Used during Construction (AFC) at the adjusted overall cost of capital. The Company currently capitalizes AFC on production and transmission CWIP at the FERC formula rate and on all other CWIP at the adjusted overall cost of capital. Fuel and Purchased Gas Adjustment Clauses Wisconsin The Wisconsin automatic retail electric fuel adjustment clause was eliminated for the Company in the electric retail rate order issued by the PSCW in 1986. The electric fuel adjustment clause was replaced by a procedure which compares actual monthly and anticipated annual fuel costs with those costs which were included in the latest retail electric rates approved by the PSCW. If the comparison results in a difference outside a range of eight percent for the first month, five percent for the second month, or two percent for the remainder of the year, the PSCW may hold hearings limited to fuel costs and revise rates. This is subject to two year approval under the biennial rate case process. Effective January 1, 1996, the fuel costs that are monitored include demand costs for sales, purchased power costs, and transmission wheeling expenses, which had been excluded prior to that date. The PSCW conducted a generic hearing in March 1996 under Docket No. 05-GI-106 to consider alternative incentive-based gas cost recovery mechanisms to replace the current purchased gas adjustment clause. In its November 5, 1996 order, the PSCW issued general guidelines for incentive-based gas cost recovery mechanisms as well as "modified one-for-one" gas cost recovery mechanisms. The order required all major gas utilities in Wisconsin to file a proposal to replace their current purchased gas adjustment clause, but allowed individual utilities discretion in choosing which type of gas cost recovery mechanism to file. The Company plans to file a proposal for a modified one- for-one gas cost recovery mechanism by July 1, 1997, according to the schedule established by the PSCW. Under a modified one-for- one gas cost recovery mechanism (GCRM), the allowable gas commodity cost recovery would be based on a benchmark index, which in turn is based on the market price of gas. The allowable cost recovery of the remaining components of the cost of gas (for example, interstate pipeline transportation) would be based on actual costs incurred, as is now the case with the purchased gas adjustment clause. Michigan The Company's Michigan retail gas and electric rate schedules include Gas Cost Recovery Factors and Power Supply Cost Recovery Factors, respectively, which are based on a twelve-month projection of costs. The MPSC conducts formal hearings because approval must be obtained before implementation of the factors. After each twelve-month period is completed, a reconciliation is submitted whereby over-revenues are refunded and any under- revenues are collected, including interest. For 1997 the Gas Cost Recovery Factor is in place, however, due to the pending merger with WEPCO, the Company has received approval of a waiver of the Power Supply Cost Recovery Factor. The waiver has been challenged by the Michigan Attorney General. Wholesale For the eight wholesale customers on the W-1 Wholesale rate, the Company calculates the fuel adjustment factor for the current month based on estimated electric fuel costs for that month. The fuel adjustment factor is adjusted for over or under collected fuel costs allocable to wholesale customer sales from the prior month's actual operations which provide an ongoing true-up mechanism. Rate Matters by Jurisdiction Wisconsin On June 1, 1995, the Company filed an application with the PSCW requesting no change in the electric utility rates for 1996 and a $2.7 million (3.6%) increase in gas utility rates for 1996. On October 6, 1995, the PSCW directed the Company to decrease electric rates by $4.8 million (1.7%). On December 21, 1995, the PSCW issued an order approving a $2.5 million gas rate increase (3.4%). An effective date of January 1, 1996, was authorized for both of these rate changes. In its orders, the PSCW deviated from its normal biennial rate case filing requirements and directed the Company to file complete electric and gas rate cases in early 1996 for the test year beginning January 1, 1997, as discussed below. This special filing was requested by the PSCW to facilitate its review of the Company's pending application to merge with WEPCO. On March 15, 1996, the Company filed a full rate case for the 1997 test year on a stand-alone basis as requested by the PSCW. The Company's filing described revenue deficiencies for both the electric and gas utilities. However, no rate increases were requested. Technical hearings for the Company's electric and gas rate cases were held before the PSCW on July 8, 1996. On November 26, 1996, the PSCW issued an order approving the Company's application for no change in rates. However, certain classes of customers will experience small changes in rates as a result of rate design revisions requested by the Company. These changes to electric rates for certain customers classes have an offsetting effect on overall revenues. There were no significant changes to gas rates. In its order, the PSCW approved a capital structure composed of 45% debt and 55% common equity, and granted an 11.3% return on common equity. The Company, WEC and WEPCO filed for approval of the proposed Merger Transaction on August 4, 1995. The merger application requested deferred accounting treatment and rate recovery of costs incurred associated with the proposed merger. Electric and gas rate plans were filed that proposed a 1.5% reduction in electric rates and a $4.2 million reduction in gas rates (of which $0.6 million relates to the Company) at the time of the Merger Transaction and four-year rate freeze thereafter, with certain exceptions. On March 18, 1996, the Company and WEC filed testimony and exhibits supporting the original August 4, 1995, Merger Transaction filing. On July 24, 1996, the PSCW held a prehearing conference on the merger proceeding. At the prehearing conference, the parties agreed upon an extensive issues list and a schedule for the hearing. At its open meeting on August 8, 1996, the PSCW revised the schedule and set hearings to begin October 30, 1996. In October 1996, the PSCW staff filed testimony with the PSCW proposing various conditions, including potential divestiture of certain transmission, generation and gas assets and a larger reduction in electric rates than proposed by the Company and WEC. The staff recommendations differ materially from the merger terms and conditions included in the application the Company and WEC originally filed with the PSCW. In January 1997, a Dane County Circuit Court judge ordered the PSCW to delay its decision on the merger, pending the results of an investigation regarding alleged prohibited conversations between one of the PSCW commissioners and WEC officials. The judge ordered the PSCW to investigate the allegations. At the request of the PSCW, the matter is under investigation by the District Attorney's Office to Milwaukee County. The Company cannot predict when the PSCW will resolve the allegations and proceed with deliberations concerning the proposed merger. In early 1997, legislation was introduced in the Wisconsin legislature to revise the statue under which the PSCW review utility mergers. As introduced, the legislation would apply to the Primergy merger if it is still pending before the PSCW at the time the legislation is signed into law. In that event, it is highly likely that the PSCW would be required to hold additional hearings on the merger application. In September 1996, the PSCW issued an order setting minimum standards for creating an ISO that differ from the Company's and WEC's ISO proposal. This order was issued as part of a generic electric utility restructuring process the PSCW started in 1995. Although the restructuring process is separate from the merger proceedings, the order is related because the PSCW staff, in its testimony filed in the merger proceeding, as discussed above, recommended establishing an ISO that meets the standards of the PSCW's order as a condition of approving the merger. In addition, in September 1996, the PSCW submitted its ISO order to the FERC with a request that FERC require an ISO satisfying the PSCW minimum standards as a condition of FERC approval of the NSP/WEC merger application. In October 1996, Company and WEC filed with the PSCW, as supplemental testimony and exhibits in the merger proceeding, the same ISO proposal filed with the FERC, as discussed later. The Company was originally scheduled to file a general rate case in June of 1997 for rates effective January 1, 1998 as required by the PSCW biennial filing schedule. However, because of the PSCW's decision to deviate from this schedule, it is unlikely the Company will file a rate case until later in 1997, if at all. If the PSCW approves the NSP/WEC merger, the Company anticipates the PSCW will waive the biennial rate case filing requirement and instead will accept the rate reductions and the four-year rate freeze as proposed in the companies' merger application. Michigan There were no changes in the Michigan electric or gas base rates during 1996. The Company does not anticipate the need to file for a change in Michigan rates in 1997. The Company and WEPCO filed for MPSC approval of the Merger Transaction on August 4, 1995. Electric and gas rates were filed that proposed a rate reduction and a four-year rate freeze. The MPSC gave its approval for the merger on April 10, 1996. Wholesale (FERC) The Company is providing power supply to ten municipal wholesale customers with 1996 revenues of $17.4 million. This reduction of $0.5 million from 1995 revenues was the result of offering discounted rates to customers in exchange for longer contract terms. In 1996, seven customers received discounts of three to five percent below the FERC authorized W-1 Wholesale rate. In that same year, one customer, whose contract term was completed, renewed its power supply agreement for five years, including a discount beginning in 1997. Beginning in 1996, two customers began service under five-year negotiated rate agreements and at the end of the five year terms, the Company will have no further obligation to serve these two customers. All ten municipal wholesale customers have current power supply agreements ranging from four to ten year terms. Changes in the wholesale market were anticipated and the Company is providing discounts and negotiated services to be competitive. Due to these changes, 1997 revenues are estimated to decrease from 1996 levels by $0.4 million. Two Investor Owned Utilities (IOU) wholesale customers renewed their agreements in late 1996 for an additional five years. They will purchase almost all of their power supply requirements from the Company. A partial requirements sale is also being made to one additional municipal customer. Electric Transmission Tariffs and Settlement (FERC) NSP has been an industry leader in the area of transmission open access. In 1990, the Minnesota Company and the Company jointly filed a transmission services tariff for certain transmission customers on the NSP System (as defined later). New rates were effective under the filing, subject to refund, for the period December 29, 1990, through October 31, 1994. On February 5, 1996, the FERC denied the companies' request for a rehearing and required the companies to submit a refund compliance filing in the amount of $1.7 million. A compliance filing was made on March 29, 1996, and the amount refunded by both companies in 1996 was $1.4 million (the Company's portion was $1.0 million). The refund had been fully accrued as of December 31, 1995. In March 1994, the Minnesota Company and the Company jointly filed a revised open access transmission tariff with the FERC. On April 11, 1995, an Offer of Settlement (the Settlement) was entered into by a majority of the parties involved in this proceeding. The settlement agreement includes a transmission tariff that complies with the FERC transmission pricing policy which calls for comparability of service and pricing, network service, and unbundling of ancillary charges such as scheduling and load following. The FERC approved the Settlement on February 14, 1996, subject to the outcome of the final rule in the open access proceedings discussed below. The total revenue effect of the settlement on both the Company and the Minnesota Company would produce an increase in revenues of approximately $200,000 per year. The new tariff enables the Company and the Minnesota Company to comply with transmission pricing provisions of open access transmission requirements of the Energy Policy Act of 1992. On October 11, 1996, NSP filed the Order No. 888 proforma tariff using the settlement rates from the approved NSP tariff. Open Access Transmission Proceedings (FERC) In April 1996, the FERC issued two final rules, Order Nos. 888 and 889, which may have a significant impact on wholesale markets. Order No. 888, which was preceded by a Notice of Proposed Rulemaking referred to as the "Mega-NOPR," concerns rules on non-discriminatory open access transmission service to promote wholesale competition. Order No. 888, which was effective on July 9, 1996, requires utilities and other transmission users to abide by comparable terms, conditions and pricing in transmitting power. Order No. 889, which had its effective date extended to January 3, 1997, requires public utilities to implement Standards of Conduct and an Open Access Same Time Information System (OASIS, formerly known as Real-Time Information Networks). These rules require transmission personnel to provide the same information about the transmission system to all transmission customers using the OASIS. A new proposed rule on Capacity Reservation Open Access Transmission Tariffs also was issued on April 24, 1996. This proposed rule requested comments on a new proposed tariff compliance filing and an information filing that unbundled the transmission component of the full-requirements municipal wholesale customers' rates. With regard to the second phase, in December 1996, NSP submitted its compliance filing which unbundled the transmission component of its coordination sales agreements. For transactions under these agreements, these customers became NSP transmission service customers. In October 1996, the FERC accepted NSP's information filing. NSP also is in compliance with Order 889. Steps taken in compliance include the submission of the requisite Standards of Conduct filing in November 1996 and the training of employees on these standards in January 1997. NSP continues to be generally supportive of the FERC's efforts to increase competition. The FERC's Order No. 888 required utilities to offer a transmission tariff that includes network transmission service (NTS) to transmission customers. NTS allows transmission service customers to fully integrate load and resources on an instantaneous basis, in a manner similar to NSP's historical integration of its load and resources. Customers can elect to participate in the cost-sharing network by requesting NTS service from NSP. Under NTS, the NSP system and participating customers share the total annual transmission cost for their combined joint- use systems, net of related transmission revenues, based upon each company's share of the total system load. The expected annual expense increase to the Company, net of cost-sharing revenues, as a result of offering NTS is estimated to be approximately $4 million for 1997. In 1996, the Company incurred approximately $0.5 million of NTS costs. Proposed Transaction Approval Proceedings (FERC) In July 1995, the Minnesota Company, the Company and WEC (the Applicants) filed an application and supporting testimony with the FERC seeking approval of the Merger Transaction to form Primergy Corporation. The filing consisted of the merger application, the proposed joint transmission tariff and an amendment to the Company's Interchange Agreement with the Minnesota Company. The issues raised by intervenors with respect to the merger application at the FERC are primarily related to two areas: the impact on competition and the nature of the cost savings. On January 31, 1996, the FERC issued a ruling which put the merger approval filing on an accelerated schedule. The FERC set only one of six merger issues raised by intervenors for hearing, provided the applicants agreed to a wholesale rate freeze. The FERC ordered a hearing regarding the effect of the proposed merger on bulk power competition. In February 1996, the Applicants agreed to freeze wholesale rates for four years subsequent to the Merger Transaction. On May 28, 1996, the Applicants filed additional evidence with the FERC, providing a detailed analysis of generation "market power" and more specific information about the independent system operator (ISO) proposal included in earlier filings. This additional information was provided to the FERC in response to concerns raised by intervenors in the merger proceeding and the FERC staff. The FERC administrative law judge (ALJ), in the merger proceeding, issued an initial decision on August 29, 1996, recommending approval of the merger application, subject to the Applicants meeting eight conditions. A significant part of the ALJ's initial decision discusses the design of an ISO. The ALJ's initial decision specifically rejected the need for divestiture of any generation or transmission facilities as a requirement for ensuring open and equal access to the transmission system. In October 1996, the Applicants filed a Unilateral Offer of Settlement (UOS) with the FERC. The UOS includes a transmission system control agreement and articles and bylaws for establishing an ISO, intended to meet the requirements of the ALJ's decision and FERC guidelines. In mid-December 1996, the FERC revised and streamlined its 30-year-old policy for evaluating public utility mergers, with the changes designed to expedite the processing of merger applications. The new policy primarily focuses on three factors in reviewing mergers: the effect on competition, rates, and state and federal regulation. For pending mergers, the policy will be applied on a case-by-case basis. The Applicants believe the proposed merger is consistent with the FERC's revised merger policy and are hopeful that the FERC will simultaneously rule on the UOS and the pending merger application in 1997. Other Proceedings (FERC) In September 1996, the Minnesota Company and the Company filed for FERC approval to "abandon" FERC's jurisdiction over two liquefied natural gas (LNG) plants they operate near St. Paul, Minnesota, and Eau Claire, Wisconsin, respectively. FERC asserted jurisdiction over the plants in the late 1970s, and each company has provided FERC regulated LNG services from its plant since that time. Under the filings, FERC would abandon jurisdiction under Section 7 (c) of the Natural Gas Act, but would retain limited jurisdiction under Section 18 of Code of Federal Regulations (CFR) Part 284.224. The "abandonments" are required to complete the Primergy merger, but would also allow the Company and the Minnesota Company to modify the LNG plant facilities or provide new LNG services without prior FERC approval. Minnesota Company Jurisdictions' Proposed Merger Transaction Proceedings Minnesota Public Utilities Commission (MPUC) On August 4, 1995, the Minnesota Company filed for MPUC approval of the Merger Transaction with WEC. The Minnesota Company proposed a rate plan which would reduce electric rates by 1.5 percent subsequent to the merger and a four-year rate freeze thereafter, except for certain uncontrollable events. The rate plan was modified in March 1996 to also provide for a freeze in gas rates through 1998. The proposed rate plan included a request for a four-year amortization of the costs associated with the Merger Transaction. In June 1996, the MPUC issued an order that established the procedural framework for the MPUC's considerations of the merger. Contested case hearings were ordered for the issues of merger- related savings, electric rate freeze characteristics, the Minnesota Company's pre-merger revenue requirements, Primergy's ability to control the transmission interface between the Mid-Continent Area Power Pool (MAPP) and the Wisconsin and Upper Michigan area, and the impact of control of this interface on other Minnesota utilities. Evidentiary hearings were held from November 20 through December 3, 1996. The Minnesota Department of Public Service recommended a rate reduction of 2.0 percent, compared with the 1.5 percent reduction the Minnesota Company proposed. In January and February 1997, administrative law judges issued their findings and recommendations in the Minnesota merger applications. Among other items they found: that NSP's projected merger-related cost savings in general were reasonable; recommended a four-year rate freeze, with very limited exceptions for rate changes; concluded that the merger would not provide Primergy with the ability or incentive to negatively impact competition; and determined the Minnesota Company's pre-merger electric rates for Minnesota retail customers may exceed revenue requirements by $3.5 million, or one-fifth of one-percent. The MPUC will consider the administrative law judges' recommendations along with other information when it deliberates and decides the case. On March 5, 1997, the Minnesota Office of the Attorney General, a participant in the merger cases, filed a brief which expressed for the first time opposition to the merger. Although NSP had hoped for approvals from all jurisdictions by the end of 1996, it now appears that the MPUC could reach decisions within the first half of 1997. On March 12, 1997, the MPUC issued a notice that it will consider whether to request additional public hearings as well as additional written comments. The MPUC stated if additional hearings or written comments are necessary, final deliberations in this matter could be scheduled for June or July 1997. On March 20, 1997, the MPUC heard comments from the parties on the need for additional hearings or other procedures prior to making a decision on the merger. While NSP believes the case is ready for decision now, the MPUC is considering what further procedures, if any, it will require. If no further procedures are undertaken, a decision in the second quarter is expected. In July 1996, the MPUC, on a motion from a Commissioner, voted to request an investigation into allegations of improper communications between two Commissioners and a Minnesota Company lobbyist. The MPUC in September 1996 determined in an order that no improper contact had taken place. Upon reconsideration of the matter in December 1996, the MPUC reversed itself and found the communications were improper. However, in January 1997, prior to issuing an order on its December decision, the MPUC reconsidered and nullified its December decision. No final order has been issued. The need for general rate filings in 1997 depend upon the outcome of the merger case. North Dakota Public Service Commission (NDPSC) On August 4, 1995, the Minnesota Company filed for NDPSC approval of the Merger Transactions with WEC. The Minnesota Company proposed a rate plan which would reduce electric rates by 1.5 percent on January 1, 1997, or after the close of the Merger Transaction, and implement a four-year rate freeze thereafter, with certain exceptions. A 1.25 percent rate reduction and a four-year rate freeze in gas rates was also proposed. Public hearings on the Merger Transaction were held in Minot, Grand Forks and Fargo, North Dakota, in November and December 1995. A technical hearing was held in March 1996. The NDPSC voted unanimously to approve the Merger on June 26, 1996, basically on the terms proposed by NSP. South Dakota Public Utilities Commission (SDPUC) In 1995, the SDPUC determined that it did not have jurisdiction to approve or deny the Merger Transaction with WEC. On September 30, 1996, the Minnesota Company filed a 1.5% or $1.2 million electric rate reduction to be effective upon closing of the Merger Transaction. After the merger-related reduction, South Dakota rates would then be frozen through 2000. ELECTRIC OPERATIONS Competition The Company's electric sales are subject to competition in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, other private utilities and independent power producers. Electric service also increasingly competes with other forms of energy. The degree of competition may vary from time to time, depending on relative costs and supplies of other forms of energy. Although the Company cannot predict the extent to which its future business may be affected by supply, relative cost or promotion of other electricity or energy suppliers, the Company believes that it will be in a position to compete effectively. In October 1992, the President signed into law the Energy Policy Act of 1992 (Energy Act). The Energy Act amends the Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act. Among many other provisions, the Energy Act is designed to promote competition in the development of wholesale power generation in the electric utility industry. It exempts a new class of independent power producers from regulation under the PUHCA. The Energy Act also allows the FERC to order wholesale "wheeling" by public utilities to provide utility and non-utility generators access to public utility transmission facilities. The provision allows the FERC to set prices for wheeling, which will allow utilities to recover certain costs. The costs would be recovered from the companies receiving the services, rather than the utilities' retail customers. The market-based power agreement filings with FERC and the open access orders issued by FERC (as discussed in "Regulation and Rates," herein) reflect the trend toward increasing transmission access under the Energy Act. The Energy Act is a catalyst for comprehensive and significant changes in the operation of electric utilities, including increased competition. The Act's reform of the PUHCA promotes creation of wholesale non-utility power generators and authorizes the FERC to require utilities to provide wholesale transmission services to third parties. The legislation allows utilities and nonregulated companies to build, own and operate power plants nationally and internationally without being subject to restrictions that previously applied to utilities under the PUHCA. Management believes this legislation will promote the continued trend of increased competition in the electric energy markets. NSP plans to continue its efforts to be a competitively priced supplier of electricity and an active participant in the competitive market for electricity. The NSP System is experiencing a continuing increase in requests for the use of its transmission facilities as power marketers continue to enter the electric industry. In 1996, the Company filed 58 transmission service agreements for FERC approval. Many states are currently considering proposals to increase competition in the supply of electricity. The Company believes the transition to a more competitive electric industry will be beneficial for all consumers. It is likely that retail competition will provide more innovative services and lower prices. The Company supports an orderly transition to an open, fair and efficient competitive energy market for all customers and suppliers. As discussed previously in "Rates and Regulation," regulators in Wisconsin and Michigan are currently considering what actions they should take regarding electric industry competition, including restructuring. The Company believes that, under such restructuring plans, utilities should retain direct operational responsibility of their transmission and distribution systems, and that utilities should be permitted to recover the cost of their investments made under traditional regulation, including any "stranded costs." The timing of regulatory actions regarding restructuring and their impact on the Company cannot be predicted at this time and may be significant. NSP System The Company's electric production and transmission systems are interconnected with the production and transmission system of the Minnesota Company. The combined electric production and transmission systems of the Company and the Minnesota Company are hereinafter called the "NSP System." The facilities of the NSP System include coal and nuclear generating plants, hydro, gas fired combustion turbines, waste wood, and waste wood/refuse derived fuel (RDF) generating plants, an interconnection with the Manitoba-Hydro Electric Board for the purpose of exchanging power, and extra-high voltage transmission facilities for interconnection to Kansas City, Milwaukee and St. Louis to provide the necessary back-up for large power plants in those service territories. The Minnesota Company operates two nuclear generating plants: the single unit, 539 Megawatts (MW) Monticello Nuclear Generating Plant and the Prairie Island Nuclear Generating Plant with two units totaling 1,025 MW. The Monticello Plant received its 40-year operating license from the NRC on September 8, 1970, and commenced operation on June 30, 1971. Prairie Island Units 1 and 2 received their 40-year operating licenses on August 9, 1973, and October 29, 1974, respectively, and commenced operation on December 16, 1973, and December 21, 1974, respectively. The ability of these nuclear plants to continue operating until the end of the license periods is dependent upon the availability of storage facilities for used nuclear fuel. The Monticello plant has sufficient pool capacity for temporary storage of used fuel to operate until 2008. With the additional on-site dry cask fuel storage facilities approved by the Minnesota Legislature in 1994, the Prairie Island plant is expected to have sufficient temporary storage capacity to operate until 2003. The Minnesota Company has contracted with the U.S. Department of Energy (DOE) for the disposal of used nuclear fuel. The DOE charges a quarterly disposal fee based on nuclear electric generation sold. While the DOE has contracted to begin accepting used nuclear fuel in 1998, it has indicated it may not actually be ready until 2010. Consequently, the Minnesota Company may have to rely on on-site or contracted off-site facilities for storage of used fuel to continue operations of its nuclear plants until a DOE disposal or storage facility is ready. (See related legal proceedings under Item 3 - Legal Proceedings, herein.) Capability and Demand The Company's record peak demand occurred on July 13, 1995, and was recorded at 1,075 MW. The peak demand for 1996 occurred on August 6 with 1,034 MW. The NSP System's net generating capability, plus commitments for capacity purchases, less commitments for capacity sales, must be at least equal to the NSP System obligation which is the sum of its maximum demand and its reserve requirements. Being a member of the MAPP, NSP's reserve requirement is determined jointly with the other parties to the MAPP Agreement. Currently, the minimum reserve requirement is 15 percent of the NSP System's maximum demand. The reserve requirement reflects the benefit of MAPP members sharing their reserves to protect against equipment failures on their systems (see Electric Power Pooling Agreements). In March 1996, the members of MAPP approved the conversion of MAPP into a Regional Transmission Group (RTG). On September 12, 1996, the conversion plan, the "Restated Mid-Continent Area Power Pool Agreement, January 12, 1996", was approved by the FERC, in Docket No. ER96-1447, and became effective November 1, 1996. By converting MAPP to an RTG, members will have more input into transmission access within other member's territories. This is one of the proposals in response to intervenor concerns in the FERC regulatory approval proceeding of the Minnesota Company's proposed merger with WEC. (See "Regulation and Rates") The Company primarily relies on the Minnesota Company, through the Interchange Agreement (see Electric Operations - Interchange Agreement), for base load generation. Approximately 77 percent of the total kilowatt hour requirements of the Company were provided by the Minnesota Company generating facilities or purchases made by the Minnesota Company for system uses in the year 1996. The Company also has two electric steam generating facilities. One is the Bay Front Generating Plant which is located in Ashland, Wisconsin. The plant is fueled primarily by natural gas, coal and wood residue. Recent modifications to the facility allow for more effective utilization of additional waste wood fuel supplies and have extended the useful life of the facility approximately 20 years from their completion in 1992. In 1992 the Company received authorization from the Wisconsin Department of Natural Resources (WDNR) to burn tire derived fuel at the Ashland plant on a regular basis. The Company's second electric steam generating plant is the French Island plant located in La Crosse, Wisconsin, which has two fluidized bed boilers modified for the purpose of burning a mixture of waste wood and RDF. The Bay Front plant in Ashland and the French Island steam plant are primarily used on an intermediate load basis. The Company's thermal peaking capability consists of two oil- fired gas turbine peaking plants and a gas and oil turbine peaking plant. The Company also has 19 hydro plants that operate as peaking facilities or run-of-river facilities. Demand Side Management The Company continues to implement various Demand Side Management (DSM) programs designed to improve load factor and reduce the Company's power production cost and system peak demands, thus reducing or delaying the need for additional investment in new generation and transmission facilities. The Company currently offers a broad range of DSM programs to all customer sectors, including information programs, rebate and financing programs, and rate incentive programs. In management's opinion, these programs respond to customer needs and focus on increasing value of service that, over the long term, will reduce the company's capital requirements and help its customer base become more stable, energy efficient and competitive. During 1996, the Company's programs accomplished approximately 20.5 MW of system peak demand reduction in the commercial, industrial and agricultural customer sectors and over 2.5 MW in the residential sector. These impacts were obtained through appliance, lighting, motor, and cooling efficiency and process improvements, peak curtailable and time-of-use rate applications and direct load control of water heaters and air conditioners. Since 1986, the Company's DSM programs have achieved 196 MW of summer peak demand reduction, which is equivalent to almost 19% of the Company's 1996 summer peak demand. The Company is working towards a cumulative goal of 200 MW of peak demand reduction by the end of 1997. The Company continues to focus on improving the cost-effectiveness of its DSM programs through market research studies and program evaluations. Since January 1, 1996, the Company has been allowed to expense rather than defer and amortize DSM program expenditures. Expenditures incurred prior to 1996 continue to be amortized. Interchange Agreement The electric production and transmission costs of the NSP System are shared by the Company and the Minnesota Company. The cost-sharing arrangement between the companies is the Agreement to Coordinate Planning and Operation and Interchange Power and Energy between the Company and the Minnesota Company (Interchange Agreement). It is a FERC regulated agreement and has been accepted by the PSCW and the MPSC for determination of costs recoverable in rates by the Company for charges from the Minnesota Company in rate cases. Historically the Company's share of the NSP System annual production and transmission costs has been in the 14 to 17 percent range. Revenues received from billings to the Minnesota Company for its share of the Company's production and transmission costs are recorded as electric operating revenues on the Company's income statement. The portions of the Minnesota Company's production and transmission costs that were charged to the Company were recorded as purchased and interchange power expenses and other operation expenses, respectively, on the Company's income statement. (See Note 6 to Financial Statements). Under the Interchange Agreement, the Company could be charged a portion of the cost of an assessment made against the Minnesota Company pursuant to the Price-Anderson liability provisions of the Atomic Energy Act of 1954. (See Note 8 to Financial Statements). Electric Power Pooling Agreements Many of the NSP System's power purchases from other utilities are coordinated through the regional power organization MAPP, pursuant to the RTG agreement discussed previously. The NSP System is one of 53 members, 27 associate members and 6 regulatory participants in MAPP. The MAPP agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The most recent MAPP agreement, converting MAPP to an RTG, as discussed previously, was approved by the FERC September 12, 1996 and has been in effect since November 1, 1996. Fuel Supply In 1996 the Company shared in the fuel supply costs incurred by the Minnesota Company in accordance with the Interchange Agreement. Coal and nuclear fuel will continue to dominate the NSP System fuel requirements for the generation of electricity. It is expected that approximately 97 percent of the NSP System annual fuel requirements on a Btu basis will be provided by these two sources and that 3 percent of the NSP System's annual fuel requirements for generation will be provided by other fuels (including natural gas, oil, refuse derived fuel, waste materials, renewable sources, and wood) over the next several years. The actual fuel mix for 1996, and the estimated fuel mix for 1997 and 1998, are as follows: Fuel Use on Btu Basis (Est.) (Est.) 1996 1997 1998 Coal 59.7% 60.3% 59.3% Nuclear 37.2% 36.5% 37.5% Other 3.1% 3.2% 3.2% Electric Operating Statistics The follow table summarizes the revenues, sales and customers from the Company's electric business, excluding sales to the Minnesota Company and miscellaneous revenues: Operating Statistics 1996 1995 1994 1993 1992 Electric Revenue (thousands) Residential With space heating $ 22 876 $ 24 825 $ 23 916 $ 24 086 $ 22 521 Without space heating 95 681 96 248 92 033 90 632 85 889 Small commercial and industrial 54 500 54 826 53 842 52 214 50 234 Large commercial and industrial* 110 318 110 270 107 462 101 609 95 336 Streetlighting and other 4 371 4 320 4 335 4 262 4 206 Total retail 287 746 290 489 281 588 272 803 258 186 Sales for resale 17 391 17 902 17 414 16 009 14 755 Total $305 137 $308 391 $299 002 $288 812 $272 941 Sales (millions of kilowatt-hours) Residential With space heating 348 372 358 362 346 Without space heating 1 358 1 346 1 284 1 265 1 229 Small commercial and industrial 896 882 863 834 814 Large commercial and industrial* 2 466 2 403 2 306 2 169 2 098 Streetlighting and other 43 42 43 42 43 Total retail 5 111 5 045 4 854 4 672 4 530 Sales for resale 458 456 438 417 394 Total 5 569 5 501 5 292 5 089 4 924 Customer accounts (Dec. 31) Residential With space heating 29 133 28 783 28 391 27 958 27 518 Without space heating 154 200 152 368 150 082 148 108 146 704 Small commercial and industrial 28 541 28 066 27 481 26 928 26 671 Large commercial and industrial* 1 412 1 322 1 234 1 171 1 142 Streetlighting and other 1 003 1 000 989 989 1 007 Total retail 214 289 211 539 208 177 205 154 203 042 Sales for resale 10 10 10 10 10 Total 214 299 211 549 208 187 205 164 203 052 *Includes customers with annual electric demand of 100 kilowatts or more. GAS OPERATIONS During 1996, the Company continued its strategy of holding a diversified portfolio of natural gas supplies and transportation arrangements. Since 1993, the Company has complied with the requirements of FERC's Order 636, which significantly changed the services available to, and provided by, local distribution companies and interstate pipelines. The Company is now relying entirely on third party suppliers for its natural gas supply needs, and is utilizing the pipelines only for transportation and storage services. The natural gas supply network throughout North America has been transformed into an integrated gas transportation grid enabling the Company to purchase natural gas from numerous suppliers, obtain contracts for transportation service on directly connected and upstream pipelines, and to flexibly deliver the supplies to the Company's gas service territory. In addition, the Company has directly contracted for underground storage and owns and operates liquefied natural gas and propane- air peak shaving facilities. The Company's diversified supply and transportation contracts, as well as underground storage and peak shaving facilities, provide the Company with the ability to meet customer needs with reliable and economic natural gas supply. The PSCW is continuing to investigate the need to change natural gas regulation in Wisconsin as a result of changes in the structure of natural gas utility pipeline services provided to all gas utilities. The PSCW is advocating a market model in which gas costs will be deregulated by segment, where competition is effective. Distribution service will remain regulated. The Company continues to hold annual and/or winter peaking transportation contracts with Northern Natural Gas Company (NNG), Great Lakes Transmission Limited Partnership, Northern Border Pipeline Company, Viking Gas Transmission Company (Viking), another subsidiary of the Minnesota Company, and TransCanada Pipeline, LTD. The Company's ability to operate in a competitive gas market was expanded through the Minnesota Company's acquisitions of Viking in June 1993 and the formation of an energy services business, Cenerprise, Inc. (Cenerprise), in October 1993. Viking allows NSP continued access to competitive interstate natural gas transportation. Cenerprise, a Minnesota Company subsidiary, allows the Company to provide more customized value- added energy services to retail gas customers without increasing costs within the regulated retail gas distribution business. The Company has been providing limited non-traditional services under a pilot project approved by the PSCW which allows the Company to take advantage of its unique position in the United States and Canadian supply markets. Examples of non- traditional activities may include sales of unused system supply if profitable and brokerage of gas not purchased or required for system needs. These non-traditional marketing opportunities are a result of deregulation in the natural gas industry. Traditional regulated services would not have allowed a mark-up on gas costs. The pilot project, with its sharing of benefits between customers and shareholders, was, by order of the PSCW, discontinued at the end of 1996. In 1997, the Company will continue these activities with 100% of the revenues credited back to customers. In January 1997, the PSCW adopted "Standards of Conduct" for retail natural gas utilities (LDCs) serving Wisconsin consumers. The standards would apply to the Company's existing gas operations, and the retail gas operations of New NSP and Wisconsin Energy Company after the proposed Merger Transaction. The standards are similar to, but much more extensive than, the standards of conduct FERC has imposed on Viking under Order 497 and on NSP's wholesale electric transmission functions under Order 889. The PSCW standards require separation of the LCD delivery function from any affiliate which engages in "gas functions" and impose extensive reporting and other administrative requirements. The Company filed its compliance plan in February 1997. PSCW approval is pending. Gas Operating Statistics The follow table summarizes the revenues, sales and customers from the Company's gas business, excluding sales to the Minnesota Company and miscellaneous revenues (including purchased gas adjustments): 1996 1995 1994 1993 1992 Revenues (thousands) Residential With space heating $40 635 $36 695 $33 726 $32 029 $27 592 Without space heating 747 556 571 535 480 Small com.w/o space heating 1 893 929 869 824 697 Small com.with space heating 22 412 19 263 17 691 17 049 14 990 Small industrial firm 2 309 6 428 6 545 5 961 3 942 Total firm 67 996 63 871 59 402 56 398 47 701 Interruptible 20 419 16 569 15 299 15 156 13 015 Total $88 415 $80 440 $74 701 $71 554 $60 716 Sales (thousands of mcf) Residential With space heating 6 355 5 801 5 243 5 221 4 756 Without space heating 102 72 73 72 66 Small com.w/o space heating 481 180 168 162 145 Small com.with space heating 4 167 3 785 3 424 3 403 3 142 Small industrial firm 1 774 2 162 2 126 1 932 1 128 Total firm 12 879 12 000 11 034 10 790 9 237 Interruptible 7 135 6 951 6 032 6 153 5 650 Total 20 014 18 951 17 066 16 943 14 887 Customer Accounts (Dec. 31) Residential With space heating 63 112 60 420 57 263 54 535 51 583 Without space heating 2 756 2 756 2 931 2 995 3 106 Small com.w/o space heating 686 573 563 537 539 Small com.with space heating 7 665 7 385 7 052 6 707 6 462 Small industrial firm 6 119 116 116 110 Total firm 74 225 71 253 67 925 64 890 61 800 Interruptible 300 300 281 265 265 Total 74 525 71 553 68 206 65 155 62 065 ENVIRONMENTAL MATTERS The Company's policy is to proactively prevent adverse environmental impacts, regularly monitor operations to ensure the environment is not adversely affected, and take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. The Company strives to maintain compliance with all applicable environmental laws. The WDNR has been authorized by the United States Environmental Protection Agency to administer the National Pollutant Discharge Elimination System Permits under the Federal Water Pollution Control Act Amendments of 1977. Such permits are required for the lawful discharge of any pollutant into navigable waters from any point source (e.g. power plants). Permits have been issued for all of the Company's applicable plants and all plants are in compliance with permit requirements. The Company presently operates hydro, coal, natural gas, tire-derived fuel, railroad tie, oil-fired, wood and refuse- derived fuel/wood-fired generation equipment. The WDNR has jurisdiction over emissions to the atmosphere from the operation of this equipment at the Company's power plants. The operation of the Company's generating plants substantially conforms to federal and state limitations pertaining to discharges into the air. Regulatory approval is required for the construction of generating plants and major transmission lines. Also, additional regulations have been instituted governing the use, transport, disposal and inspection of hazardous material and electrical equipment containing polychlorinated biphenyls (PCB). The Company has procedures in place to comply with these regulations. Both the Company and the Minnesota Company have received requests for information concerning groundwater contamination at a landfill site in Hudson, Wisconsin. While neither the Company nor the Minnesota Company has been named potentially responsible parties (PRPs), both companies voluntarily joined a group of other parties to address the contamination at this site. A preliminary estimate of total remediation costs at the site is approximately $6.5 million. The Company's and the Minnesota Company's share of this cost is currently estimated to be 0.6%. The Company's share alone is not expected to exceed $5,000. In addition, the administrator of a group of PRPs has notified the Company that it might be responsible for cleanup of a solid and hazardous waste landfill sites in Eau Claire and Amery, Wisconsin. The Company contends that it did not contribute waste consistent with the contaminants of concern in the subject landfills. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to predict the outcome of the matter at this time or any potential future impact on the Company's financial condition or operating results. On March 2, 1995, the WDNR notified the Company that it is a PRP at a creosote/coal tar contamination site in Ashland, Wisconsin adjacent to Lake Superior. At this time, the WDNR has determined that the Company is the only PRP at this site. The site has three distinct portions - the Company portion of the site, the Kreher Park portion of the site and the Chequamegon Bay (of Lake Superior) portion of the site. The Company portion of the site, formerly a coal gas plant site, is Company property. The Kreher Park portion of the site is adjacent to the Company portion of the site and is not owned by the Company. The Chequamegon Bay portion of the site is adjacent to the Kreher Park portion of the site and is not owned by the Company. The Company is discussing its potential involvement in the Kreher Park and Chequamegon Bay portions of the site with WDNR and the City of Ashland. WDNR's consultant is preparing a remedial option study for the entire Ashland site, which includes the Company's portion and two other adjacent portions. Until this study is completed and more information is known concerning the extent of the final remediation required by the WDNR, the remediation method selected, the related costs, the various parties involved and the extent of the Company's responsibility, if any, for sharing the costs, the ultimate cost to the Company and timing of any payments related to the Ashland site are not determinable. As of December 31, 1996, the Company had recorded an estimated liability of $880,000 for future remediation costs for the Company owned portion of the site. Actual costs incurred through 1996 were $525,000. The PSCW authorized recovery of $353,000 over a two year period beginning in 1997, which represents recovery of actual expenditures through 1995. Based on this PSCW decision to allow recovery of remediation costs incurred, the Company has recorded a regulatory asset for the estimated accrued and actual incurred expenditures related to the Ashland site. The ultimate cleanup and remediation cost at the Ashland site and the extent of the Company's responsibility, if any, for sharing such costs are not known at this time, but may be significant. On February 12, 1996, the Company received a Letter of Non- compliance (LON) from the WDNR for failing to meet the emission guidelines for carbon monoxide (CO) at its Bay Front generating facility. The Company has worked with the WDNR throughout 1996 to establish mutually agreed-upon CO emission limits for the Bay Front facility. No fines or other enforcement mechanism have occurred nor are they expected. On March 11, 1996, the Company received a Notice of Violation (NOV) from the WDNR stating that emissions from the Company's French Island facility had exceeded allowable levels for dioxin. The company's initial investigation and response, including a re-test of Unit #1, resulted in the WDNR clearing the NOV on Unit #1 on September 25, 1996. On October 9, 1996, the Company received a letter from the WDNR reiterating the outstanding NOV on Unit #2 and requesting a written response. The Company responded by providing a written response to the WDNR setting forth the Company's plans for bringing the emissions levels back into compliance. The Company is currently investigating this matter to determine the cause of these unexpected events. At this time, the Company is unable to predict whether any fines will be imposed by the WDNR against the Company or what further corrective action may be required. The Company does not believe any fines, if levied, or corrective action, if required, will have a material adverse effect on the Company's financial condition or results of operation. In late December 1996, the Company completed installation of continuous emission monitors for carbon monoxide at the French Island Generating facility in La Crosse, Wisconsin. The continuous emissions system which will monitor CO emissions from the two generating units was mandated by the Air Pollution Control Permit issued by the WDNR in 1994. CONSTRUCTION AND FINANCING During the five years ended December 31, 1996, the Company had gross additions to utility plant in service of approximately $262.6 million. Included in the Company's gross additions is $26.6 million for electric production facilities, $150.2 million for other electric properties, $39.4 million for gas utility properties, and $46.4 million for other utility properties. Retirements during the same period were approximately $39.9 million. Based on studies made by the Company, the weighted average age of depreciable property was 13.8 years at December 31, 1996. Expenditures for the Company's construction programs for the five-year period 1997-2001, are estimated to be as follows: Year Estimated Construction Expenditures 1997 $ 58 million 1998 68 million 1999 77 million 2000 75 million 2001 81 million TOTAL $359 million The 1997 construction expenditures are estimated to include approximately $41.9 million for electric facilities, $4.5 million for gas facilities and $11.3 million for general plant and equipment. It is presently estimated that approximately 73% of the 1997-2001 construction expenditures will be provided by internally generated funds, with the remainder from short-term and long-term debt financing. At December 31, 1996, the Company's short-term borrowings payable to the Minnesota Company were $39.3 million. The PSCW has authorized up to $80 million of these short-term borrowings. The Company currently projects the need for $50 million of long-term debt in 1999 to finance the estimated construction expenditures for the 1997-2001 construction program. The foregoing estimates of future construction expenditures, internally generated funds and external financing requirements can be affected by numerous factors, including load growth, competition, inflation, changes in the tax laws, rate relief, earnings and regulatory actions. Major electric and gas utility projects are currently subject to the jurisdiction of the PSCW and require its approval. Hence, the above estimated construction program and financing program could change from time to time due to variations in these other factors. EMPLOYEES AND EMPLOYEE BENEFITS At year end 1996, the total number of full- and part-time employees of the Company was approximately 902. About 393 employees of the Company are represented by one local IBEW labor union, under a three year collective bargaining agreement which expired December 31, 1996, but was extended to April 30, 1997. Management and union representatives have reached a tentative agreement on the terms of a new collective bargaining agreement, subject to approval by the union membership. NSP is not able to predict the outcome at this time. Recent changes to the Company's employee and retiree benefits, which support a broad NSP goal of providing market- based benefits, include: Retiree medical premium increases: Retiree medical premiums were increased in 1994 for existing and future retirees. For existing qualifying retirees, pension benefits have been increased to offset some of the premium increase. For future retirees, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing gradually each year to a total of 40% in 1999. 401(k) changes: The Company currently offers eligible employees a 401(k) Retirement Savings Plan. Since 1994, the Company has been matching employees' pre-tax 401(k) contributions. Such matching contributions were $0.5 million in 1996, based on matching up to $900 per year for each nonbargaining employee and up to $600 per year for each bargaining employee. Wage increases: Under a market-based pay structure implemented for nonbargaining employees in 1994, the Company uses salary surveys that indicate how local and regional companies pay their employees for comparable positions. In January 1996, nonbargaining employees received an average wage scale increase of 3.5%, while bargaining employees received a 4.0% base wage increase. In January 1997, non bargaining employees received an average wage scale increase of 4.0%. Wage increases for bargaining employees in 1997 will be determined by the new collective bargaining agreement which is not yet final, as discussed previously. Item 2. Properties Electric Utility The Company's major electric generating facilities consist of the following: Projected Year 1997-8 Winter Station and Units Fuel Installed Capability (MW) Combustion Turbine: Flambeau Station Gas/Oil 1969 17 (1 unit) Park Falls, WI Wheaton Oil 1973 443 (6 units) Eau Claire, WI French Island Oil 1974 192 (2 units) La Crosse, WI Steam: Bay Front Coal/Wood/ 1945-1960 75 (3 units) Gas Ashland, WI French Island Wood/RDF 1940-1948 29 (2 units) La Crosse, WI Hydro Plants: (19 plants) Various dates 249 TOTAL 1 005 At December 31, 1996, the Company owned approximately 2,392 pole miles of overhead electric transmission lines, 8,338 pole miles of overhead electric distribution lines, 38 conduit miles and 1,052 direct buried cable miles of underground electric lines. Virtually all of the land and personal property owned by the Company is subject to the lien of their first mortgage bond indentures pursuant to which the Company has issued first mortgage bonds. Gas Utility The gas properties of the Company include approximately 1,538 miles of natural gas distribution mains. The Company owns two liquefied natural gas facilities with a combined storage capacity of the equivalent of 400,000 Mcf to supplement the available pipeline supply of natural gas during periods of peak demands. The two liquefied natural gas facilities are located in Eau Claire and La Crosse, Wisconsin. The La Crosse LNG facility is currently nonoperational. In January of 1993, the Company installed temporary propane air facilities with a capacity of 144,000 gallons to further supplement its gas supply in the La Crosse, Wisconsin area during peak periods. This propane air facility was not operational for the 1995-96 winter, but was used in the 1996-97 winter heating season. Item 3. Legal Proceedings In the normal course of business, the Company is a party to routine claims and litigation arising from prior and current operations. The Company is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition. On June 20, 1994, the Minnesota Company along with other major utilities filed a lawsuit against the DOE in an attempt to clarify the DOE's obligation to dispose of spent nuclear fuel beginning not later than January 31, 1998. The suit was filed in the U.S. Court of Appeals, Washington, D.C. The primary purpose of the lawsuit was to insure that the Minnesota Company and its customers receive timely storage and disposal of spent nuclear fuel in accordance with the terms of the Minnesota Company's contract with the DOE. On July 23, 1996, the U.S. Court of Appeals for the District of Columbia Circuit, affirmed the federal government's obligation. The court unanimously ruled that the Nuclear Waste Policy Act creates an unconditional obligation for the DOE to begin acceptance of spent nuclear fuel by January 31, 1998. The DOE did not seek U.S. Supreme Court review. On January 31, 1997, the Minnesota Company, along with 30 other electric utilities and 45 state agencies, filed another lawsuit against the DOE requesting authority to withhold payments to the DOE for the permanent disposal program. For a discussion of environmental proceedings, see "Environmental Matters" under Item 1, incorporated herein by reference. For a discussion of proceedings involving the Company's utility rates, see "Regulation and Rates" under Item 1, incorporated herein by reference. Item 4. Submission of Matters to a Vote of Security Holders None. PART II Item 5. Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters This is not applicable as the Company is a wholly owned subsidiary. Item 6. Selected Financial Data This is omitted per conditions set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations Management's Discussion and Analysis of Financial Condition and Results of Operations is omitted per conditions as set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management's narrative analysis of the results of operations set forth in general instructions J (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). This analysis will primarily compare its revenue and expense items for the year ended December 31, 1996 with the year ended December 31, 1995. The Company's net income for year ended December 31, 1996 was $38.7 million, down from the $39.2 million earned in the same period of 1995. The 1996 operating income increased by $0.4 million from the 1995 level. Electric Sales and Revenues Electric revenues in total decreased $4.0 million in 1996. Sales to unaffiliated customers decreased $3.1 million or 1.0 percent in 1996 as compared to 1995 primarily due to price decreases net of higher sales levels. Customer and sales growth, partially offset by less favorable weather in 1996, produced an electric sales increase of 1.2 percent. These sales increases were more than offset by decreased revenues from a 1.7 percent electric rate reduction effective January 1, 1996 as discussed in the Rate Matters by Jurisdiction section. The remaining $0.9 million reduction in electric revenues relates to lower Interchange Agreement billings to the Minnesota Company as discussed in Note 6 to the Financial Statements. Gas Sales and Revenues Gas revenues in 1996 increased $10.7 million or 13.7 percent as compared with 1995. Gas sales increased 5.6 percent in 1996 from 1995 due to favorable winter weather and sales growth. As discussed in the Rate Matters by Jurisdiction section, a 3.4 percent gas rate increase effective January 1, 1996 also contributed to the increased revenues. Gas revenues also increased due to higher costs per unit of gas purchased, as discussed below, which are reflected in customer rates through the purchased gas adjustment clause mechanism. Operating Expenses and Other Factors Purchased and Interchange Power and Fuel for Electric Generation together increased $0.2 million or 0.1 percent in 1996 from 1995. Compared to 1995, the Company's total sales requirements increased 1.1 percent in 1996. The effects of higher sales requirements were partially offset by lower average production costs per unit charged from the Minnesota Company. Gas Purchased for Resale increased $6.0 million or 11.4 percent in 1996. Of the increase, approximately $2.8 million relates to additional gas purchases to support increased gas sales, and approximately $3.2 million relates to a higher cost per unit of purchased gas. Other operation, maintenance, and administrative and general expenses together decreased $4.2 million or 4.6 percent in 1996 as compared to 1995 primarily due to reduced employee benefit expenses as discussed in Note 5 to the Financial Statements, lower employee levels, and reduced maintenance on overhead lines. Conservation costs in 1996 increased $1.4 million as compared to 1995 due to certain demand side management costs which were capitalized in previous years. Depreciation and Amortization increased $2.6 million in 1996 due to increases in the Company's plant in service. Property and General Taxes increased $0.2 million in 1996 from 1995 primarily due to increases in property tax rates. Income tax expense was approximately the same for both years, reflecting comparable pretax operating income. Allowance for Funds Used During Construction (AFC) decreased in total by $0.2 million in 1996 from 1995 due to varying levels of construction work in progress and lower AFC rates associated with increased use of lower-cost, short-term borrowings to fund construction. Other income and deductions decreased $1.0 million in 1996 from 1995 primarily due to lower subsidiary company earnings. Other interest and amortization (before AFC) expense decreased $0.3 million in 1996 from 1995. An increase in interest paid to the Minnesota Company for short-term borrowings was offset by reduced interest on long-term debt and a 1995 charge for interest on prior year income tax assessments. Item 8 Financial Statements and Supplementary Data See Item 14(a)-1 in Part IV for financial statements included herein. See Note 10 to the financial statements for summarized quarterly financial data. REPORT OF INDEPENDENT ACCOUNTANTS To The Shareholder of Northern States Power Company (Wisconsin): In our opinion, the accompanying balance sheets and the related statements of income and retained earnings and of cash flows present fairly, in all material respects, the financial position of Northern States Power Company, a Wisconsin corporation, at December 31, 1996 and 1995, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. The financial statements of the Company for the year ended December 31, 1994 were audited by other independent accountants whose report dated January 27, 1995 expressed an unqualified opinion on those statements. /s/ PRICE WATERHOUSE LLP Minneapolis, Minnesota February 3, 1997 INDEPENDENT AUDITORS' REPORT Northern States Power Company (Wisconsin): We have audited the accompanying statements of income and retained earnings and of cash flows of Northern States Power Company (Wisconsin) and its subsidiaries (the Companies) for the year ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the results of operations and cash flows of the Companies for the year ended December 31, 1994, in conformity with generally accepted accounting principles. /s/ Deloitte and Touche LLP Minneapolis, Minnesota January 27, 1995 Statements of Income and Retained Earnings Year Ended December 31 (Thousands of dollars) 1996 1995 1994 Operating Revenues Electric $ 377 073 $ 381 040 $ 375 105 Gas 88 756 78 058 76 715 Total 465 829 459 098 451 820 Operating Expenses Purchased and interchange power 173 492 173 743 174 144 Fuel for electric generation 5 165 4 703 5 414 Gas purchased for resale 58 347 52 356 53 484 Other operation 46 920 46 534 44 260 Maintenance 19 617 20 780 22 385 Administrative and general 21 814 25 264 26 487 Conservation and demand side management 9 117 7 674 7 211 Depreciation and amortization 35 731 33 097 30 774 Property and general taxes 14 332 14 109 13 710 Income taxes 24 688 24 662 19 077 Total operating expenses 409 223 402 922 396 946 Operating Income 56 606 56 176 54 874 Other Income and Deductions Allowance for funds used during construction-equity 339 445 671 Other income and deductions-net 677 1 698 574 Total Other Income 1 016 2 143 1 245 Income Before Interest Charges 57 622 58 319 56 119 Interest Charges Interest on long-term debt 15 918 16 038 15 995 Other interest and amortization 3 406 3 548 2 060 Allowance for funds used during construction-debt (399) (484) (481) Total interest charges 18 925 19 102 17 574 Net Income 38 697 39 217 38 545 Retained Earnings, January 1 221 638 218 833 205 114 Dividends paid to parent on common stock (25 584) (36 412) (24 826) Retained Earnings, December 31 $ 234 751 $ 221 638 $ 218 833 See Notes to Financial Statements. Statements of Cash Flows Year Ended December 31 (Thousands of dollars) 1996 1995 1994 Cash Flows from Operating Activities: Net Income $38 697 $39 217 $38 545 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 36 665 34 180 32 382 Deferred income taxes 1 736 1 839 7 614 Deferred investment tax credits recognized (910) (936) (943) Allowance for funds used during construction - equity (339) (445) (671) Insurance receivable 3 091 (3 091) Cash provided by (used for) changes in certain working capital items (2 633) 7 282 (9 568) Cash used for changes in other assets and liabilities (2 691) (1 064) (6 076) Net Cash Provided by Operating Activities 70 525 83 164 58 192 Cash Flows from Investing Activities: Capital expenditures (49 403) (51 173) (52 639) Increase (decrease) in construction payables (118) (457) (633) Allowance for funds used during construction - equity 339 445 671 Other (897) (1 606) 2 037 Net Cash Used for Investing Activities (50 079) (52 791) (50 564) Cash Flows from Financing Activities: Issuances (repayment) of short-term debt due to parent - net (11 600) 9 600 17 800 Proceeds from issuance of long-term debt 82 691 Redemption of long-term debt, including reacquisition premiums (65 992) (3 375) (990) Dividends paid to parent (25 584) (36 412) (24 826) Net Cash Used for Financing Activities (20 485) (30 187) (8 016) Net Increase (decrease) in cash and cash equivalents (39) 186 (388) Cash and cash equivalents beginning of period 247 61 449 Cash and cash equivalents end of period $ 208 $ 247 $ 61 Cash provided by (used for) changes in certain working capital items: Accounts receivable-net $2 883 ($6 188) $ 770 Materials and supplies (1 447) 3 442 (4 708) Accounts payable and accrued liabilities 668 1 241 332 Payables to affiliated companies 2 087 4 475 (2 655) Income and other taxes accrued (4 007) 417 (4 174) Other (2 817) 3 895 867 Net ($2 633) $7 282 ($9 568) Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $ 18 556 $ 15 389 $ 15 870 Income taxes (net of refunds received) $ 26 977 $ 17 333 $ 18 773 See Notes to Financial Statements. Balance Sheets December 31 (Thousands of dollars) 1996 1995 Assets Utility Plant Electric-including construction work in progress: 1996, $11,948; 1995, $12,640 $ 894 143 $ 864 514 Gas 99 817 94 425 Other 67 262 63 758 Total 1 061 222 1 022 697 Accumulated provision for depreciation (395 619) (370 634) Net utility plant 665 603 652 063 Other Property and Investments Non-utility property - at cost 3 126 3 123 Accumulated provision for depreciation (327) (334) Other investments 7 433 6 429 Total other property and investments 10 232 9 218 Current Assets Cash 208 247 Accounts receivable 41 151 43 988 Accumulated provision for uncollectible accounts (901) (854) Materials and supplies - at average cost Fuel 7 780 6 689 Other 5 918 5 561 Unbilled utility revenues 21 074 18 665 Prepayments and other 11 703 11 295 Total current assets 86 933 85 591 Other Assets Regulatory assets 37 102 34 704 Unamortized debt expense 1 855 2 780 Federal Income tax receivable 3 307 3 307 Other 4 099 3 235 Total other assets 46 363 44 026 Total Assets $ 809 131 $ 790 898 See Notes to Financial Statements. December 31, (Thousands of dollars) 1996 1995 Liabilities and Equity Capitalization Common stock-authorized 870,000 shares of $100 par value; issued shares: 1996 and 1995, 862,000 $ 86 200 $ 86 200 Premium on common stock 10 461 10 461 Retained earnings 234 751 221 638 Total common stock equity 331 412 318 299 Long-term debt (net of unamortized discount of $1,912 in 1996) 231 688 213 235 Total capitalization 563 100 531 534 Current Liabilities Notes payable - parent company 39 300 50 900 Accounts payable 16 493 14 884 Payables to affiliated companies (principally parent) 15 544 13 457 Salaries, wages, and vacation pay accrued 6 417 6 343 Taxes accrued 1 641 5 648 Interest accrued 4 459 5 300 Current deferred income taxes 1 670 1 963 Capital lease obligations and other 3 888 4 177 Total current liabilities 89 412 102 672 Other Liabilities Accumulated deferred income taxes 100 898 100 227 Accumulated deferred investment tax credits 20 024 21 205 Regulatory liabilities 19 409 18 020 Customer advances 7 334 6 458 Benefit obligations and other 8 954 10 782 Total other liabilities 156 619 156 692 Commitments and Contingent Liabilities (see Note 8) Total Liabilities and Equity $ 809 131 $ 790 898 See Notes to Financial Statements. NORTHERN STATES POWER COMPANY (WISCONSIN) NOTES TO FINANCIAL STATEMENTS 1. Summary of Accounting Policies System of Accounts - Northern States Power Company (Wisconsin), (the Company), a wholly-owned subsidiary of Northern States Power Company, a Minnesota corporation (the Minnesota Company), maintains the accounting records in accordance with either the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) or those prescribed by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC), which systems are the same in all material respects. Investment in Subsidiaries - The Company carries its investment in its subsidiaries (Chippewa and Flambeau Improvement Company, 75.86% owned; NSP Lands, Incorporated, 100% owned; and Clearwater Investments, Incorporated, 100% owned) at cost plus equity in earnings since acquisition. The impact of consolidation of these subsidiaries is considered immaterial. Related Party Transactions - The Company's financial statements include intercompany transactions and balances related to sales among the electric and gas utility businesses of the Company, the Minnesota Company and Viking Gas Transmission Company (a wholly-owned subsidiary of the Minnesota Company), including intercompany profits which are allowed in utility rates. See Note 6 for further discussion of intercompany transactions with the Minnesota Company. Utility Plant and Retirements - Utility Plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction (AFC). The cost of units of property retired, plus net removal cost, is charged to the accumulated provision for depreciation and amortization. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses. Depreciation - For financial reporting purposes, depreciation is computed on the straight-line method based on the annual rates certified by the PSCW and MPSC for the various classes of property. Depreciation provisions, as a percentage of the average balance of depreciable property in service, were 3.57 percent in 1996, 3.48 percent in 1995, and 3.45 percent in 1994. Allowance for Funds Used during Construction (AFC) - AFC, a non-cash item, is computed by applying a composite pretax rate, representing the cost of capital used to fund utility construction, to qualified Construction Work in Progress (CWIP). The Company used the FERC calculation for production and transmission property and the PSCW calculation for other qualified CWIP. The rates used for the FERC calculation were 5.70 percent in 1996, 6.20 percent in 1995, and 7.55 percent in 1994. The rates used for the PSCW calculation were 10.03 percent in 1996, 10.13 percent in 1995, and 10.13 percent in 1994. The amount of AFC capitalized as a construction cost in CWIP is credited to other income and interest charges. AFC amounts capitalized in CWIP are included in utility rate base for establishing utility service rates. Revenues - Revenues are recognized based on products and services provided to customers each month. Because utility customer meters are read and billed on a cycle basis, unbilled revenues are estimated and recorded for services provided from the monthly meter-reading dates to month-end. Regulatory Deferrals - As a regulated utility, the Company accounts for certain income and expense items under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 - Accounting for the Effects of Certain Types of Regulation. In doing so, certain costs which would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits which would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistent with ratemaking treatment as established by regulators. Note 7 describes the components of regulatory assets and liabilities. Income Taxes - Under the liability method used by the Company, income taxes are deferred for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. Due to the effects of regulation, current income tax expense is provided for the reversal of some temporary differences previously accounted for by the flow-through method. Also, regulation has created certain regulatory assets and liabilities related to income taxes, as summarized in Note 7. The Company is included in the consolidated Federal income tax return filed by the Minnesota Company and files separate state returns for Wisconsin and Michigan. The Company records current and deferred income taxes at the statutory rates as if it filed a separate return for Federal income tax purposes. State income tax payments are made directly to the taxing authorities. Federal income tax payments are made to the Internal Revenue Service by the Minnesota Company and charged back to the Company. Investment tax credits were deferred and are being amortized over the estimated lives of the related property. Purchased Tax Benefits - The Company purchased tax-benefit transfer leases under the Safe Harbor Lease provisions of the Economic Recovery Tax Act of 1981. For both financial reporting and regulatory purposes, the Company is amortizing the difference between the cost of the purchased tax benefits and the amounts to be realized through reduced current income tax liabilities over the remaining terms of the leases after the initial investments have been recovered. Derivative Financial Instruments - As discussed in Note 2, the Company has entered into an interest rate swap agreement to manage the risk of holding fixed-rate debt in a declining interest rate environment. The cost or benefit of swap transactions is recorded as an adjustment to interest expense each period over the term of the agreement. Environmental Costs - Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense (or deferred as a regulatory asset based on expected recovery from customers in future rates) if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use (such as pollution control equipment), the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where the Company has been designated as one of several potentially responsible parties, the amount accrued represents the Company's estimated share of the cost. The Company intends to treat any future costs related to decommissioning and restoration of its power plants and substation sites, where operation may extend indefinitely, as a capitalized removal cost of retirement in utility plant. Depreciation expense levels currently recovered in rates include a provision for an estimate of removal costs (based on historical experience). Use of Estimates - In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental loss contingencies, unbilled revenues and actuarially determined benefit costs. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Recent changes in interest rates have resulted in changes to actuarial assumptions used in the benefit cost calculations for postretirement benefits, as discussed in Note 5. Reclassifications - Certain reclassifications have been made to the 1995 and 1994 financial statements to conform with the 1996 presentation. These reclassifications had no effect on net income or earnings per share. 2. Long-term Debt Dec. 31 Dec. 31 1996 1995 (Thousands of dollars) Long-term debt includes the following issues: First Mortgage Bonds (less reacquired bonds of $3,365 at December 31, 1995): Series due: Oct. 1, 2003, 5 3/4% $ 40 000 $ 40 000 Apr. 1, 2021, 9 1/8% 44 635 Mar. 1, 2023, 7 1/4% 110 000 110 000 Dec. 1, 2026, 7 3/8% 65 000 Total First Mortgage Bonds 215 000 194 635 City of La Crosse Resource Recovery Revenue Bonds - Series due Nov. 1, 2011, 7 3/4% 18 600 Series due Nov. 1, 2021, 6 % 18 600 Total long-term debt $ 233 600 $ 213 235 Except for minor exclusions, all real and personal property is subject to the lien of the Company's First Mortgage Bonds. The Supplemental and Restated Trust Indenture dated March 1, 1991, and effective October 1, 1993 permits an amount of established permanent additions to be deemed equivalent to the payment of cash necessary to redeem 1% of the highest principal amount of each series of first mortgage bonds (other than pollution control financing) at any time outstanding. Interest Rate Swap Agreement - The Company has entered into an interest rate swap agreement extending through March 1, 1998 for $20 million of the 7-1/4% series first mortgage bonds. This agreement effectively converts the interest costs for $20 million of this debt issue from fixed to variable rates based on six- month London Interbank Offered Rates (LIBOR) with the rates changing semi-annually, March 1 and September 1. The net effective interest rate under the Swap agreement was 7.89% at December 31, 1996. Market risks associated with this agreement result from short-term interest rate fluctuations. Credit risk related to non-performance of the counterparties is not deemed significant, but would result in NSP terminating the swap transaction and recognizing a gain or loss, depending on the fair market value of the swap. Such agreements are not reflected on the Company's balance sheets. The interest rate swap serves to hedge the interest rate risk associated with fixed rate debt in a declining interest rate environment. This hedge is produced by the tendency for changes in the fair market value of the swap to be offset by changes in the present value of the liability attributable to the fixed rate debt issued in conjunction with the interest rate swap. If the interest rate swap had been terminated at Dec. 31, 1996, $212,000 would have been payable by the Company while the present value of the related fixed rate debt issued with the swaps was $618,000 below carrying value. Fair Value of Debt - The estimated fair value of the Company's long term debt at December 31, 1996 and 1995 is $227.7 million and $230.6 million, respectively. This fair value is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. Capital Lease Obligations - Amounts due under capital lease obligations are approximately $752,000, $441,000, $128,000, $14,000, and $0, respectively, for the years 1997-2001. 3. Short-Term Borrowings The Company had bank lines of credit aggregating $1,000,000 at December 31, 1996. Compensating balance arrangements in support of such lines of credit were not required. These credit lines make short-term financing available by providing bank loans. During 1996 and 1995 there were no bank loans outstanding as the Company obtained short-term borrowings from the Minnesota Company at the Minnesota Company's average daily interest rate, including the cost of their compensating balance requirements. The PSCW has authorized the Company's short-term commercial paper borrowings up to $80.0 million. At December 31, 1996 and 1995, the Company had $39.3 million and $50.9 million, respectively, in short-term commercial paper borrowings outstanding. The weighted average interest rates on all short- term borrowings as of December 31, 1996 and 1995, were 5.59 percent and 6.2 percent, respectively. 4. Income Tax Expense The total income tax expense differs from the amount computed by applying the Federal income tax statutory rate of 35% to net income before income tax expense. The reasons for the difference are as follows: 1996 1995 1994 (Thousands of dollars) Tax computed at statutory rate $ 22 148 $ 22 140 $ 20 074 Increases (decreases) in tax from: State income taxes, net of Federal income tax benefit 2 921 3 314 2 393 Investment tax credits recognized (910) (936) (943) Adjustment to taxes accrued in prior years 682 90 (2 430) Other - net (259) (567) (283) Total income tax expense $ 24 582 $ 24 041 $ 18 811 Effective income tax rate 38.9% 38.0% 32.8% Income tax expense is comprised of the following: Included in Utility operating expenses: Current Federal tax expense $ 18 293 $ 17 772 $ 8 075 Current state tax expense 3 838 4 546 2 810 Deferred Federal tax expense 2 790 2 679 7 967 Deferred state tax expense 677 601 1 168 Deferred investment tax credit adjustments (910) (936) (943) Total 24 688 24 662 19 077 Included in income deductions: Current Federal tax expense 1 299 691 1 039 Current state tax expense 326 130 216 Deferred Federal tax expense (1 385) (1 264) (1 008) Deferred state tax expense (346) (178) (513) Total income tax expense $ 24 582 $ 24 041 $ 18 811 The components of the Company's net deferred tax liability at Dec. 31 (including current and noncurrent amounts) were as follows: (Thousands of dollars) 1996 1995 Deferred tax liabilities: Differences between book and tax bases of property $ 103 771 $ 106 390 Tax benefit transfer leases 1 638 3 369 Regulatory assets 12 690 12 498 Other 3 782 4 337 Total deferred tax liabilities 121 881 126 594 Deferred tax assets: Deferred investment tax credits 8 014 8 507 Regulatory liabilities 7 729 11 063 Deferred compensation, accrued vacation and other reserves not currently deductible 2 310 4 040 Other 1 260 794 Total deferred tax assets 19 313 24 404 Net deferred tax liability $ 102 568 $ 102 190 5. Pension Plans and Other Post Retirement Benefits The Company offers the following benefit plans to its benefit employees, of whom approximately 52 percent are represented by one local labor union under a collective- bargaining agreement, which expired December 31, 1996, but was extended to April 30, 1997. Management and union representatives have reached a tentative agreement on the terms of a new collective-bargaining agreement, subject to approval by the union membership. The Company is not able to predict the outcome at this time. Pension Benefits - Employees of the Company participate in the Northern States Power Company Pension Plan. This noncontributory defined benefit pension plan covers substantially all employees. Benefits are based on a combination of years of service, the employees highest average pay for 48 consecutive months and Social Security benefits. It is the Company's policy to fully fund the actuarially determined pension costs recognized for ratemaking purposes, subject to the limitations under applicable employee benefit and tax laws. Plan assets consist principally of common stock of public companies, corporate bonds and U.S. government securities. The following table sets forth the funded status of the pension plan, including amounts allocable to the Company, as of December 31: 1996 1995 Company Company (Thousands of dollars) Total Plan Portion Total Plan Portion Actuarial present value of benefit obligation: Vested $ 660 920 $ 84 924 $ 686 403 $ 87 877 Nonvested 147 278 16 332 155 177 17 901 Accumulated benefit obligation $ 808 198 $ 101 256 $ 841 580 $ 105 778 Projected benefit obligation $ 993 821 $ 120 886 $ 1 039 981 $ 127 287 Plan assets at fair value 1 634 696 196 089 1 456 530 145 963 Plan assets in excess of projected benefit obligation 640 875 75 203 416 549 18 676 Unrecognized prior service cost 19 734 2 469 20 805 2 602 Unrecognized net gain (651 368) (77 174) (452 699) (23 842) Unrecognized net transitional asset (539) (67) (615) (77) Net pension asset (liability) recorded $ 8 702 $ 431 $ (15 960)$ (2 641) Effective January 1, 1993, for financial reporting and regulatory purposes, the Company's pension expense is determined and recorded under the SFAS No. 87 - Employers' Accounting for Pensions method. The Company's accumulated regulatory asset from the use of another method prior to that date is being amortized over a 15-year period ending in 2007. Net periodic pension costs for the Company for its share of total plan costs include the following components: 1996 1995 1994 (Thousands of dollars) Service cost - benefits earned during the period $ 3 390 $ 2 844 $ 3 114 Interest cost on projected benefit obligation 8 618 8 662 8 087 Actual return on allocated share of plan assets (12 353) (10 994) (1 702) Net amortization and deferral (2 727) (1 567) (10 130) Net periodic pension cost determined under SFAS No. 87 (3 072) (1 055) (631) Expenses recognized due to actions of regulators 90 90 90 Net periodic pension cost (credit) recognized for ratemaking $ (2 982) $ (965) $ (541) The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7.5% in 1996 and 7% in 1995. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5% in 1996 and 1995. The assumed long- term rate of return on assets used for cost determinations under SFAS No. 87 was 9% in 1996 and 1995, and 8% in 1994. Assumption changes increased 1996 pension costs by approximately $1.4 million and decreased 1995 pension costs by approximately $2.5 million. Assumption changes are expected to decrease 1997 pension costs by approximately $0.8 million. Postretirement Health Care - The Company participates in the Minnesota Company's contributory health and welfare benefit plan that provides health care and death benefits to substantially all employees after their retirement. The plan is intended to provide for sharing the costs of retiree health care between the Company and retirees. For employees retiring after January 1, 1994, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40 percent in 1999. In conjunction with the 1993 adoption of SFAS No. 106 - Employers' Accounting for Postretirement Benefits Other Than Pensions, the Company elected to amortize on a straight-line basis over 20 years the unrecognized accumulated postretirement benefit obligation (APBO) of approximately $29.5 million for current and future retirees of the Company. Before 1993, NSP funded payments for retiree benefits internally. While the Company generally prefers to continue using internal funding of benefits paid and accrued, there have been some external funding requirements imposed by the Company's regulators, as discussed below, including the use of tax advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1996, consisted of investments in equity mutual funds and cash equivalents. The following table sets forth the funded status of the health care plan, including amounts allocable to the Company, as of December 31. 1996 1995 Company Company (Thousands of dollars) Total Plan Portion Total Plan Portion APBO: Retirees $144 180 $ 22 166 $ 145,763 $ 22 709 Fully eligible plan participants 23 438 3 447 24 406 3 235 Other active plan participants 101 065 12 065 116 810 14 872 Total APBO 268 683 37 678 286 979 40 816 Plan Assets at Fair Value 15 514 8 285 11 583 5 608 APBO in excess of plan assets 253 169 29 393 275 396 35 208 Unrecognized net actuarial gain (loss) (12 467) (2 057) (40 411) (7 925) Unrecognized transition obligation (172 480) (23 586) (183 260) (25 060) Postretirement benefit liablity recorded $ 68 222 $ 3 750 $ 51 725 $ 2 223 The assumed health care cost trend rate used in measuring the APBO at December 31, 1996 and 1995, respectively, were 9.8 and 10.4 percent for those under age 65 and 7.1 and 7.3 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 5.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. A 1 percent increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31, 1996, by approximately 14 percent and service and interest cost components of the net periodic postretirement cost by approximately 17 percent. The assumed discount rate used in determining the APBO was 7.5 percent for December 31, 1996 and 7 percent for December 31, 1995, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for 1996, 1995, and 1994. Assumption changes had an immaterial effect on results of operations. The Company's share of net annual periodic postretirement benefit costs under the plan consists of the following components (thousands of dollars): 1996 1995 1994 Service cost-benefits earned during the year $ 804 $ 686 $ 644 Interest cost (on service cost and APBO) 2 700 2 761 2 251 Amortization of transition obligation 1 474 1 474 1 474 Return on assets and other (632) (301) (182) Net amortization and deferral 221 Net periodic postretirement health care costs $ 4 567 $ 4 620 $ 4 187 The Company's regulators have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. External funding is required in Wisconsin and Michigan to the extent it is tax advantaged. The FERC has required external funding for all benefits paid and accrued under SFAS No. 106. Funding began for both retail and FERC jurisdictions in 1993. 401(k) - The Company participates in the Minnesota Company's contributory, defined contribution Retirement Savings Plan (the Plan), which complies with section 401(k) of the Internal Revenue code and covers substantially all Company employees. Employer matching contributions under this Plan began in 1994, and are required to match a specified amount of employee contributions. The Company's matching contribution to the Plan was $0.5 million in both 1996 and 1995 and $0.3 million in 1994. 6. Parent Company and Intercompany Agreements The Company is wholly-owned by the Minnesota Company. The electric production and transmission costs of the NSP system are shared by the Company and the Minnesota Company. A FERC approved agreement (Interchange Agreement) between the Company and the Minnesota Company provides for the sharing of all costs of electric generation and transmission facilities of the NSP System, including capital costs. Billings under the Interchange Agreement and an intercompany gas agreement which are included in the statement of income are as follows: Year Ended December 31 1996 1995 1994 (Thousands of dollars) Operating revenues: Electric $69 337 $70 251 $73 503 Gas $39 $43 $50 Operating expenses: Purchased and interchange power $173 492 $173 743 $174 144 Gas purchased for resale $216 $205 $227 Other operation $13 685 $13 791 $12 824 7. Regulatory Assets and Liabilities The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheet at Dec. 31: (Thousands of dollars) Amortization Period 1996 1995 AFC recorded in plant on a net-of-tax basis Plant Lives* $ 9 928 $ 9 918 Losses on reacquired debt Term of New Debt 13 341 9 749 Conservation and energy management programs Up to 9 years* 10 604 12 347 Environmental costs To be determined 1 405 1 284 Unrecovered purchased gas costs 1 year 722 Pensions and other Mainly 11 years 1 102 1 406 Total Regulatory Assets $ 37 102 $ 34 704 Excess deferred income taxes collected from customers $ 3 420 $ 1 449 Investment tax credit deferrals 13 412 14 237 Fuel refunds and other 2 577 2 334 Total Regulatory Liabilities $ 19 409 $ 18 020 * Earns a return on investment in the ratemaking process. 8. Commitments and Contingent Liabilities Commitments - The Company presently estimates capital expenditures will be $58 million in 1997 and $359 million for 1997-2001. Rentals under operating leases were approximately $1,704,000, $1,644,000, and $1,792,000 for 1996, 1995, and 1994, respectively. Future commitments under these leases generally decline from current levels. Purchased Gas Contracts - The Company has contracts providing for the purchase and delivery of a significant portion of its current natural gas requirements. These contracts, which expire in various years between 1997 and 2011, require minimum contractual purchases and deliveries of fuel. In total, the Company is committed to the minimum purchase of approximately $156 million of natural gas and related transportation, or to make payments in lieu thereof, under these contracts. In addition, the Company is required to pay additional amounts depending on actual quantities shipped under these agreements. As a result of FERC Order 636, the Company has been very active in developing a mix of gas supply, transportation and storage contracts designed to meet its needs for retail gas sales. The contracts are with several suppliers and for various periods of time. Because the Company has other sources of fuel available and suppliers are expected to continue to provide reliable fuel supplies, risk of loss from non-performance under these contracts is not considered significant. In addition, the Company's risk of loss (in the form of increased costs) from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of nearly all fuel costs. Nuclear Contingencies - Although the Company does not own a nuclear facility, any assessment made against the Minnesota Company and under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, would be a cost included under the Interchange Agreement (see Note 6) and the Company would be charged its proportion of the assessment. Such provisions set a limit of $8.9 billion for public liability claims that could arise from a nuclear incident. The Minnesota Company has secured insurance of $200 million to satisfy such claims. The remaining $8.7 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. The Minnesota Company is subject to an assessment of $79 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States with a maximum funding requirement of $10 million per reactor during any one year. Environmental Contingencies - The Company potentially may be involved in the cleanup and remediation at four sites. Two sites are solid and hazardous waste landfill sites in Eau Claire and Amery, Wisconsin. The Company contends that it did not contribute waste consistent with the contaminants of concern in these landfills. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to predict the outcome of these matters at this time. The third site is a landfill in Hudson, Wisconsin. Payment amounts for the cleanup of this site will be decided in early 1997 and are not expected to exceed $5,000. The fourth site, in Ashland, Wisconsin, contains creosote/coal tar contamination. In 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Company that it is a potentially responsible party (PRP) at the Ashland site. At this time, the WDNR has determined that the Company is the only PRP at this site. The Ashland site has three distinct portions--the Company portion, the Kreher Park portion and the Chequamegon Bay (of Lake Superior) portion. The Company portion of the site, formerly a coal gas plant site, is Company property. The Kreher Park portion is adjacent to the Company site and is not owned by the Company. The Chequamegon Bay portion is adjacent to the Kreher Park portion and is not owned by the Company. The Company is discussing its potential involvement in the Kreher Park and Chequamegon Bay portions with the WDNR and the City of Ashland. In February 1996, the Company received from the WDNR's consultant a draft report of the results of a remediation action options feasibility study for the Kreher Park portion of the Ashland site. The draft report contains several remediation options that were scored by the consultant across a variety of parameters. Two options scored the most technologically and economically feasible, and one of those is the lowest-cost option for remediation at the Kreher Park portion of the site. The draft report estimates that this option, which would involve capping the property and some limited groundwater treatment, would cost approximately $6 million. In 1996, the WDNR completed a sediment contamination investigation of the impacted area of the Chequamegon Bay portion of the site to determine the extent and nature of the contamination. Contamination of the near shore area has been confirmed by the study. WDNR's consultant is preparing a remedial option study for the entire Ashland site, which includes the Company's portion and two other adjacent portions. Until this study is completed and more information is known concerning the extent of the final remediation required by the WDNR, the remediation method selected, the related costs, the various parties involved, and the extent of the Company's responsibility, if any, for sharing the costs, the ultimate cost to the Company and timing of any payments related to the Ashland site is not determinable. As of December 31, 1996, the Company had recorded an estimated liability of $880,000 for future remediation costs for the Company owned portion of the site. Actual costs incurred through 1996 were $525,000. The PSCW authorized recovery of $353,000 over a two year period beginning in 1997, which represents recovery of actual expenditures through 1995. Based on this PSCW decision to allow recovery of remediation costs incurred, the Company has recorded a regulatory asset for the estimated accrued and actual incurred expenditures related to the Ashland site. The ultimate cleanup and remediation cost at the Ashland site and the extent of the Company's responsibility, if any, for sharing such costs are not known at this time, but may be significant. Legal Claims - In the normal course of business, the Company is a party to routine claims and litigation arising from prior and current operations. The Company is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition. 9. Segment Information Year Ended December 31 1996 1995 1994 (Thousands of dollars) Operating income before income taxes: Electric $ 69 730 $ 72 595 $ 67 453 Gas 11 564 8 243 6 498 Total operating income before income taxes $ 81 294 $ 80 838 $ 73 951 Depreciation and amortization: Electric $ 30 857 $ 28 752 $ 26 874 Gas 4 874 4 345 3 900 Total depreciation and amortization $ 35 731 $ 33 097 $ 30 774 Construction expenditures: Electric $ 42 519 $ 42 843 $ 42 756 Gas 6 884 8 330 9 883 Total construction expenditures $ 49 403 $ 51 173 $ 52 639 Identifiable assets: Electric utility $661 585 $654 130 $634 848 Gas utility 91 557 86 021 81 244 Total identifiable assets 753 142 740 151 716 092 Other corporate assets 55 989 50 747 52 208 Total assets $809 131 $790 898 $768 300 10. Summarized Quarterly Financial Data (Unaudited) Quarter Ended Mar. 31, Jun. 30, Sep. 30, Dec. 31, 1996 1996 1996 1996 (Thousands of dollars) Operating revenues $ 138 730 $ 101 678 $ 100 366 $ 125 055 Operating income $ 17 341 $ 9 902 $ 11 379 $ 17 984 Net income $ 12 919 $ 5 432 $ 6 799 $ 13 547 Quarter Ended Mar. 31, Jun. 30, Sep. 30, Dec. 31, 1995 1995 1995 1995 (Thousands of dollars) Operating revenues $ 127 994 $ 102 323 $ 105 083 $ 123 698 Operating income $ 19 649 $ 9 307 $ 10 075 $ 17 145 Net income $ 15 160 $ 4 261 $ 6 047 $ 13 749 11. Merger Agreement with Wisconsin Energy Corporation As previously reported in the Company's Current Report on Form 8-K, dated May 8, 1995, and Quarterly Reports on Form 10-Q, the Minnesota Company and Wisconsin Energy Corporation (WEC) have entered into an Agreement and Plan of Merger (Merger Agreement), which provides for a strategic business combination involving the Minnesota Company and WEC in a "merger-of-equals" transaction (the Transaction). Primergy Corporation (Primergy), which will be registered under the Public Utility Holding Company Act of 1935, as amended, will be the parent company of both the Minnesota Company (which, for regulatory reasons, will reincorporate in Wisconsin) and WEC's current principal utility subsidiary, Wisconsin Electric Power Company, which will be renamed "Wisconsin Energy Company." It is anticipated that, following the Transaction, except for certain gas distribution properties transferred to the Minnesota Company, the Company will be merged into Wisconsin Energy Company and that some or all of the Company's subsidiaries will be divested to Primergy or another of its subsidiaries. As noted above, pursuant to the Transaction, NSP will reincorporate in Wisconsin. This reincorporation will be accomplished by the merger of the Minnesota Company into a new company, Northern Power Wisconsin Corporation (New NSP), with New NSP being the surviving corporation and succeeding to the business of the Minnesota Company as an operating public utility. Following such merger, a new WEC subsidiary, WEC Sub Corporation (WEC Sub), will be merged with and into New NSP, with New NSP being the surviving corporation and becoming a subsidiary of Primergy. Both New NSP and WEC Sub were created to effect the Transaction and will not have any significant operations, assets or liabilities prior to such mergers. After the Transaction is completed, the Company will be dissolved and no common stock will be outstanding. Current bondholders of the Company will become investors in Wisconsin Energy Company. PRO FORMA FINANCIAL INFORMATION (UNAUDITED) Exhibits 99.03 and 99.04 include unaudited pro forma financial information which reflects the adjustment of the historical consolidated balance sheets and statements of income of NSP, the Company and WEC to give effect to the Transaction to form Primergy and a new subsidiary structure. The unaudited pro forma balance sheet information gives effect to the Transaction as if it had occurred on December 31, 1996. The unaudited pro forma income statements give effect to the Transaction as if it had occurred on January 1, 1994. This pro forma information was prepared from the historical consolidated financial statements of NSP, the Company and WEC on the basis of accounting for the Transaction as a pooling of interests and should be read in conjunction with such historical consolidated financial statements and related notes thereto of the Minnesota Company, the Company and WEC. The pro forma information is not necessarily indicative of the financial position or operating results that would have occurred had the Transaction been consummated on the dates for which the Transaction is being given effect, nor is it necessarily indicative of future operating results or financial position of Primergy or Wisconsin Energy Company. The Primergy pro forma financial information in Exhibit 99.03 reflects the combination of the historical financial statements of NSP and WEC after giving effect to the Transaction to form Primergy. The Wisconsin Energy Company pro forma financial information in Exhibit 99.04 reflects the adjustment of the historical financial statements of the Company to give effect to the Transaction, including the merger of the Company into Wisconsin Energy Company and the transfer of ownership of all of the other current Company subsidiaries to Primergy or another of its subsidiaries. The transfer of certain Company gas distribution properties to New NSP, which is anticipated as part of the merger, has also been reflected in the pro forma amounts in Exhibit 99.04. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure During 1996 there were no disagreements with the Company's independent certified public accountants on accounting procedures or accounting and financial disclosures. PART III Part III of Form 10-K has been omitted from this report in accordance with conditions set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries. Item 10. Directors and Executive Officers of the Registrant Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management Item 13. Certain Relationships and Related Transactions PART IV Item 14. Exhibits, Financial Statement Schedules Page and Reports on Form 8-K (a) 1. Financial Statements Included in Part II of this report: Report of Independent Accountants for the years ended December 31, 1996 and 1995. 25 Independent Auditors' Report for the year ended December 31, 1994. 26 Statements of Income and Retained Earnings for the three years ended December 31, 1996. 27 Statements of Cash Flows for the three years ended December 31, 1996. 28 Balance Sheets, December 31, 1996 and 1995. 29 Notes to Financial Statements. 31 2. Financial Statement Schedules Schedules are omitted because of the absence of the conditions under which they are required or because the information required is included in the financial statements or the notes. 3. Exhibits * indicates incorporation by reference 2.01* Amended and Restated Agreement and Plan of Merger, dated as of April 28, 1995, as amended and restated as of July 26,1995, by and among Northern States Power Company, Wisconsin Energy Corporation, Northern Power Wisconsin Corp. and WEC Sub. Corp. (Exhibit (2)-1 to Northern Power Wisconsin Corporation's Registration Statement on Form S-4 filed on August 7, 1995, File No. 33-61619-01). 2.02* WEC Stock Option Agreement, dated as of April 28, 1995, by and among Northern States Power Company and Wisconsin Energy Corporation (Exhibit (2)- 2 to Form 8-K dated April 28, 1995, File No. 1- 3034). 2.03* NSP Stock Option Agreement, dated as of April 28, 1995, by and among Wisconsin Energy Corporation and Northern States Power Company (Exhibit (2)-3 to Form 8-K dated April 28, 1995, File No. 1-3034). 3.01* Restated Articles of Incorporation as of December 23, 1987. (Filed as Exhibit 30.01 to Form 10-K Report 10- 3140 for the year 1987) 3.02* Copy of the By-Laws of the Company as amended August 19, 1992. (Filed as Exhibit 3.02 to Form 10-K Report 10-3140 for the year 1992) 4.01* Copy of Trust Indenture, dated April 1, 1947, From the Company to First Wisconsin Trust Company. (Filed as Exhibit 7.01 to Registration Statement 2-6982) 4.02* Copy of Supplemental Trust Indenture, dated March 1, 1949. (Filed as Exhibit 7.02 to Registration Statement 2-7825) 4.03* Copy of Supplemental Trust Indenture, dated June 1, 1957. (Filed as Exhibit 2.13 to Registration Statement 2-13463) 4.04* Copy of Supplemental Trust Indenture, dated August 1, 1964. (Filed as Exhibit 4.20 to Registration Statement 2-23726) 4.05* Copy of Supplemental Trust Indenture, dated December 1, 1969. (Filed as Exhibit 2.03E to Registration Statement 2-36693) 4.06* Copy of Supplemental Trust Indenture, dated September 1, 1973. (Filed as Exhibit 2.01F to Registration Statement 2-48805) 4.07* Copy of Supplemental Trust Indenture, dated February 1, 1982. (Filed as Exhibit 4.01G to Registration Statement 2-76146) 4.08* Copy of Supplemental Trust Indenture, dated March 1, 1982. (Filed as Exhibit 4.08 to form 10-K Report 10-3140 for the year 1982) 4.09* Copy of Supplemental Trust Indenture, dated June 1, 1986. (Filed as Exhibit 4.09 to Form 10-K Report 10-3140 for the year 1986) 4.10* Copy of Supplemental Trust Indenture, dated March 1, 1988. (Filed as Exhibit 4.10 to Form 10-K Report 10-3140 for the year 1988) 4.11* Copy of Supplemental and Restated Trust Indenture, dated March 1, 1991. (Filed as Exhibit 4.01K to Registration Statement 33-39831) 4.12* Copy of Supplemental Trust Indenture, dated April 1, 1991. (Filed as Exhibit 4.01 to Form 10-Q Report 10-3140 for the quarter ended March 31, 1991) 4.13* Copy of Supplemental Trust Indenture, dated March 1, 1993. (Filed as Exhibit to Form 8-K Report dated March 3, 1993) 4.14* Copy of Supplemental Trust Indenture, dated October 1, 1993. (Filed as Exhibit 4.01 to Form 8-K Report dated September 21, 1993) 4.15* Copy of Supplemental Trust Indenture, dated December 1, 1996. (Filed as Exhibit 4.01 to Form 8-K Report dated December 12, 1996) 10.01* Copy of Interchange Agreement dated September 17, 1984, and Settlement Agreement dated May 31, 1985, between the Company, the Minnesota Company and LSDP. (Filed as Exhibit 10.10 to Form 10-K Report 10-3140 for the year 1985) 27.01 Financial Data Schedule 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995. 99.02* Press Release, dated May 1, 1995, of NSP (Exhibit (99)-01 to Form 8-K dated April 28, 1995, File No. 1-3034). 99.03 Unaudited Pro Forma Combined Condensed Balance Sheets for the year ended December 31, 1996 and unaudited Pro Forma Combined Condensed Statements of Income for the years ended December 31, 1994, 1995 and 1996 for Primergy Corporation. 99.04 Unaudited Pro Forma Combined Condensed Balance Sheets for the year ended December 31, 1996 and unaudited Pro Forma Combined Condensed Statements of Income for the years ended December 31, 1994, 1995 and 1996 for Wisconsin Energy Company. 99.05* Audited Financial Statements of Wisconsin Energy Corporation. (Item 8 of Wisconsin Energy Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-9057). 99.06* Audited Financial Statements of Northern States Power Company. (Item 8 of Northern States Power Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3034). 99.07* Audited Financial Statements of Wisconsin Electric Power Company. (Item 8 of Wisconsin Electric Power Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-1245). (b) Reports on Form 8-K - The following report on Form 8-K was filed either during the three months ended December 31, 1996, or between December 31, 1996 and the date of this report. December 12, 1996 (Filed December 16, 1996) - Items 5 and 7. Other Events and Financial Statements and Exhibits. Disclosure of the Company entering into an Underwriting Agreement and filed with the Securities and Exchange commission a prospectus supplement and final prospectus relating to $65,000,000 in aggregate principal amount of the Company's First Mortgage Bonds, Series due December 1, 2026. SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto authorized. NORTHERN STATES POWER COMPANY /s/ John A. Noer President and Chief Executive Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. /s/ John A. Noer (Principal Executive Officer) /s/ /s/ M. N. Gregerson H. Lyman Bretting Vice President-Customer Services Director /s/ /s/ A. G. Schuster P. M. Gelatt Vice President Director Power Delivery and Generation /s/ /s/ Patrick D. Watkins Wayne E. Harrison Vice President-Corporate Services Director /s/ /s/ John P. Moore, Jr. Loren L. Taylor General Counsel and Secretary Director /s/ /s/ Roger D. Sandeen Ray A. Larson, Jr. Controller Director (Principal Accounting Officer) /s/ /s/ Neal A. Siikarla Larry G. Schnack Treasurer Director (Principal Financial Officer) EXHIBIT INDEX Method of Exhibit Filing No. Description DT 27.01 Financial Data Schedule DT 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995. DT 99.03 Unaudited Pro Forma Combined Condensed Balance Sheets for Primergy Corporate at Dec. 31, 1996 and Unaudited Pro Forma Combined Condensed Statements of Income for the three years ended Dec. 31, 1996. DT 99.04 Unaudited Pro Forma Condensed Balance Sheet for Wisconsin Energy Company at Dec. 31, 1996 and Unaudited Pro Forma Condensed Statements of Income for the three years ended Dec. 31, 1996. EX-27 2
UT EXHIBIT 27.01 This schedule contains summary financial information extracted from the Statements of Income and Retained Earnings, Balance Sheets and Statements of Cash Flows and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 665,603 10,232 86,933 46,363 0 809,131 86,200 10,461 234,751 331,412 0 0 231,688 0 39,300 0 0 0 0 0 206,731 809,131 465,829 24,688 384,535 409,223 56,606 1,016 57,622 18,925 38,697 0 38,697 25,584 15,918 70,525 44.89 44.89
EX-99 3 Exhibit 99.01 Northern States Power Company Cautionary Factors The Private Securities Litigation Reform Act of 1995 (the Act) provides a new "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward- looking statements have been and will be made in written documents and oral presentations of Northern States Power Company, a Wisconsin Corporation (the Company). Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used in the Company's documents or oral presentations, the words "anticipate", "estimate", "expect", "objective", "possible", "potential" and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: - - Economic conditions including inflation rates and monetary fluctuations; - - Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Company has a financial interest; - - Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services; - - Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight; - - Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, or the Company; or security ratings; - - Factors affecting operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints; - - Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages; - - Increased competition in the utility industry, including: industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market; - - Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options; - - Social attitudes regarding the utility and power industries; - - Cost and other effects of legal and administrative proceedings, settlements, investigations and claims; - - Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets; - - Numerous matters associated with the proposed combination of Northern States Power Company, a Minnesota corporation (NSPM) and Wisconsin Energy Corporation to form Primergy Corporation (Primergy), including: - Regulatory authorities' decisions regarding business combination issues including the approval of the business combination as proposed, the rate structure of utility operating companies after the merger, transmission system operation and administration, or divestiture of gas utility or non-regulated portions of NSPM's business; - Qualification of the transaction as a pooling of interests; - Factors affecting the anticipated cost savings including national and regional economic conditions, national and regional competitive conditions, inflation rates, weather conditions, financial market conditions, and synergies resulting from the business combination; - Allocation of benefits of cost savings between shareholders and customers, which will depend, among other things, upon the results of regulatory proceedings in various jurisdictions; - Regulation of Primergy as a registered public utility holding company and other different or additional federal and state regulatory requirements or restrictions to which Primergy and its subsidiaries may be subject as a result of the business combination (including conditions which may be imposed in connection with obtaining the regulatory approvals necessary to consummate the business combination, such as the possible requirement to divest gas utility and possibly certain non- regulated operations); - Factors affecting dividend policy including results of operations and financial condition of Primergy and its subsidiaries and such other business considerations as the Primergy Board of Directors considers relevant. - - Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors pursuant to the Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made by the Company prior to the effective date of the Act. EX-99 4 Exhibit 99.03 UNAUDITED PRO FORMA FINANCIAL INFORMATION The following unaudited pro forma financial information reflects the adjustment of the historical consolidated balance sheets and statements of income of NSP and WEC after giving effect to their proposed business combination transaction (the Transaction) to form Primergy and a new subsidiary structure. The unaudited pro forma combined condensed balance sheets at Dec. 31, 1996 give effect to the Transaction as if it had occurred on that date. The unaudited pro forma combined condensed statements of income for each of the three years in the period ended December 31, 1996, give effect to the Transaction as if it had occurred at January 1, 1994. These statements are prepared on the basis of accounting for the Transaction as a pooling of interests and are based on the assumptions set forth in the notes thereto. The following pro forma financial information has been prepared from, and should be read in conjunction with, the historical consolidated financial statements and related notes thereto of NSP and WEC. The following information is not necessarily indicative of the financial position or operating results that would have occurred had the Transaction been consummated on the date, or at the beginning of the periods, for which the Transaction is being given effect nor is it necessarily indicative of future Primergy operating results or financial position. Completion of the Transaction is subject to numerous conditions, many of which are beyond NSP's control. Primergy Pro Forma Combined Condensed Information The pro forma financial information combines the historical financial statements of NSP and WEC after giving effect to the Transaction to form Primergy on the basis of accounting for the Transaction as a pooling of interests. PRIMERGY CORPORATION UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME TWELVE MONTHS ENDED DECEMBER 31, 1996 (In thousands, except per share amounts) NSP WEC Pro Forma Pro Forma (As Reported) (As Reported) Adjustments Combined Utility Operating Revenues Electric $2,127,413 $1,393,270 - $3,520,683 Gas 526,793 364,875 - 891,668 Steam - 15,675 - 15,675 Total Operating Revenues 2,654,206 1,773,820 - 4,428,026 Utility Operating Expenses Electric Production-Fuel and Purchased Power 541,267 331,867 - 873,134 Cost of Gas Sold & Transported 335,453 234,254 - 569,707 Other Operation 554,946 391,520 - 946,466 Maintenance 155,830 103,046 - 258,876 Depreciation and Amortization 306,432 202,796 - 509,228 Taxes Other Than Income Taxes 232,824 77,866 - 310,690 Income Taxes 161,410 126,627 - 288,037 Total Operating Expenses 2,288,162 1,467,976 - 3,756,138 Utility Operating Income 366,044 305,844 - 671,888 Other Income (Expense) Equity Earnings of Unconsolidated Investees 31,025 - - 31,025 Other Income and Deductions - Net 8,169 20,042 - 28,211 Total Other Income (Expense) 39,194 20,042 - 59,236 Income before Interest Charges and Preferred Dividends 405,238 325,886 - 731,124 Interest Charges 130,699 106,548 - 237,247 Preferred Dividends of Subsidiaries 12,245 1,203 - 13,448 Net Income $262,294 $218,135 - $480,429 Average Common Shares Outstanding (Note 1) 68,679 110,983 42,993 222,655 Earnings Per Common Share $3.82 $1.97 $2.16 NSP Equivalent Shares (Note 1) 68,679 110,983 (42,728) 136,934 Earnings Per Common Share using NSP Equivalent Shares $3.51 See accompanying notes to unaudited pro forma combined condensed financial statements. PRIMERGY CORPORATION UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME TWELVE MONTHS ENDED DECEMBER 31, 1995 (In thousands, except per share amounts) NSP WEC Pro Forma Pro Forma (As Reported) (As Reported) Adjustments Combined Utility Operating Revenues Electric $2,142,770 $1,437,480 - $3,580,250 Gas 425,814 318,262 - 744,076 Steam - 14,742 - 14,742 Total Operating Revenues 2,568,584 1,770,484 - 4,339,068 Utility Operating Expenses Electric Production-Fuel and Purchased Power 570,245 345,387 - 915,632 Cost of Gas Sold & Transported 256,758 188,764 - 445,522 Other Operation 560,734 395,242 - 955,976 Maintenance 158,203 112,400 - 270,603 Depreciation and Amortization 290,184 183,876 - 474,060 Taxes Other Than Income Taxes 239,433 74,765 - 314,198 Income Taxes 147,148 141,029 - 288,177 Total Operating Expenses 2,222,705 1,441,463 - 3,664,168 Utility Operating Income 345,879 329,021 - 674,900 Other Income (Expense) Equity Earnings of Unconsolidated Investees 59,067 - - 59,067 Other Income and Deductions - Net (6,261) 16,821 - 10,560 Total Other Income (Expense) 52,806 16,821 - 69,627 Income before Interest Charges and Preferred Dividends 398,685 345,842 - 744,527 Interest Charges 122,890 110,605 - 233,495 Preferred Dividends of Subsidiaries 12,449 1,203 - 13,652 Net Income $263,346 $234,034 - $497,380 Average Common Shares Outstanding (Note 1) 67,416 109,850 42,202 219,468 Earnings Per Common Share $3.91 $2.13 $2.27 NSP Equivalent Shares (Note 1) 67,416 109,850 (42,292) 134,974 Earnings Per Common Share using NSP Equivalent Shares $3.69 See accompanying notes to unaudited pro forma combined condensed financial statements. PRIMERGY CORPORATION UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME TWELVE MONTHS ENDED DECEMBER 31, 1994 (In thousands, except per share amounts) NSP WEC Pro Forma Pro Forma (As Reported) (As Reported) Adjustments Combined Utility Operating Revenues Electric $2,066,644 $1,403,562 - $3,470,206 Gas 419,903 324,349 - 744,252 Steam - 14,281 - 14,281 Total Operating Revenues 2,486,547 1,742,192 - 4,228,739 Utility Operating Expenses Electric Production-Fuel and Purchased Power 570,880 328,485 - 899,365 Cost of Gas Sold & Transported 263,905 199,511 - 463,416 Other Operation 535,706 399,011 - 934,717 Maintenance 170,145 124,602 - 294,747 Depreciation and Amortization 273,801 177,614 - 451,415 Taxes Other Than Income Taxes 234,564 76,035 - 310,599 Revitalization Charges - 73,900 - 73,900 Income Taxes 129,228 99,761 - 228,989 Total Operating Expenses 2,178,229 1,478,919 - 3,657,148 Utility Operating Income 308,318 263,273 - 571,591 Other Income (Expense) Equity Earnings of Unconsolidated Investees 41,709 - - 41,709 Other Income and Deductions - Net 663 26,965 - 27,628 Total Other Income (Expense) 42,372 26,965 - 69,337 Income before Interest Charges and Preferred Dividends 350,690 290,238 - 640,928 Interest Charges 107,215 108,019 - 215,234 Preferred Dividends of Subsidiaries 12,364 1,351 - 13,715 Net Income $231,111 $180,868 - $411,979 Average Common Shares Outstanding (Note 1) 66,845 108,025 41,845 216,715 Earnings Per Common Share $3.46 $1.67 $1.90 NSP Equivalent Shares (Note 1) 66,845 108,025 (41,589) 133,281 Earnings Per Common Share using NSP Equivalent Shares $3.09 See accompanying notes to unaudited pro forma combined condensed financial statements. PRIMERGY CORPORATION UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEETS DECEMBER 31, 1996 (In thousands) NSP WEC Pro Forma Pro Forma Pro Forma Balance Sheet (As Reported) (As Reported) Adjustments Combined ASSETS UTILITY PLANT Electric $6,766,896 $4,857,528 - $11,624,424 Gas 750,449 505,100 - 1,255,549 Other 331,441 61,765 - 393,206 Total 7,848,786 5,424,393 - 13,273,179 Accumulated provision for depreciation (3,611,244) (2,441,950) - (6,053,194) Nuclear fuel - net 100,338 75,476 - 175,814 Net utility plant 4,337,880 3,057,919 - 7,395,799 CURRENT ASSETS Cash and cash equivalents 51,118 10,748 - 61,866 Accounts receivable-net 371,654 151,473 - 523,127 Accrued utility revenues 147,366 155,838 - 303,204 Fossil fuel inventories 45,013 113,516 - 158,529 Material & supplies inventories 109,425 70,900 - 180,325 Prepayments and other 72,647 63,383 - 136,030 Total current assets 797,223 565,858 - 1,363,081 OTHER ASSETS Regulatory Assets 354,128 286,461 - 640,589 External decommissioning fund 260,756 322,085 - 582,841 Investments on non-regulated projects and other investments 451,223 104,919 - 556,142 Non-regulated property-net 192,790 173,525 - 366,315 Intangible assets and other (Note 4) 242,900 300,071 (153,806) 389,165 Total other assets 1,501,797 1,187,061 (153,806) 2,535,052 TOTAL ASSETS $6,636,900 $4,810,838 $(153,806) $11,293,932 LIABILITIES AND EQUITY CAPITALIZATION Common stock equity: Common stock (Note 1) $ 172,659 $ 1,117 $(171,536) $ 2,240 Other stockholders' equity (Note 1) 1,963,221 1,944,227 171,536 4,078,984 Total common stock equity 2,135,880 1,945,344 - 4,081,224 Cumulative preferred stock and premium 240,469 30,450 - 270,919 Long-term debt 1,592,568 1,416,067 - 3,008,635 Total capitalization 3,968,917 3,391,861 - 7,360,778 CURRENT LIABILITIES Current portion of long-term debt 261,218 190,204 - 451,422 Short-term debt 368,367 69,265 - 437,632 Accounts payable 236,341 148,429 - 384,770 Taxes accrued 204,348 37,362 - 241,710 Other accrued liabilities 166,126 81,758 - 247,884 Total current liabilities 1,236,400 527,018 - 1,763,418 OTHER LIABILITIES Deferred income taxes (Note 4) 804,342 511,399 (153,806) 1,161,935 Deferred investment tax credits 149,606 87,798 - 237,404 Regulatory liabilities 302,647 175,943 - 478,590 Other liabilities and deferred credits 174,988 116,819 - 291,807 Total other liabilities 1,431,583 891,959 (153,806) 2,169,736 TOTAL CAPITALIZATION AND LIABILITIES $6,636,900 $4,810,838 $(153,806) $11,293,932 See accompanying notes to unaudited pro forma combined condensed financial statements. PRIMERGY CORPORATION NOTES TO UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL STATEMENTS 1. The pro forma combined condensed financial statements reflect the conversion of each share of NSP common stock outstanding ($2.50 par value) into 1.626 shares of Primergy Common Stock ($.01 par value) and the continuation of each share of WEC Common Stock outstanding as one share of Primergy common stock ($.01 par value), as provided in the Merger Agreement. The pro forma combined condensed financial statements are presented as if the companies were combined during all periods included therein. NSP equivalent shares shown on the pro forma combined condensed income statements represent the pro forma equivalent of one share of NSP Common Stock calculated by multiplying the pro forma information by the conversion ratio of 1.626 shares of Primergy Common Stock for each share of NSP Common Stock. 2. The allocation between NSP and WEC and their customers of the estimated cost savings, resulting from the Merger Transaction, net of the costs incurred to achieve such savings, will be subject to regulatory review and approval. At the time the Merger Agreement was signed, cost savings resulting from the Merger Transaction were estimated to be approximately $2 billion over a 10-year period, net of transaction costs (including fees for financial advisors, attorneys, accountants, consultants, filings and printing) and net of costs to achieve the savings of approximately $30 million and $122 million, respectively. None of these estimated cost savings, the costs to achieve such savings, or the transaction costs have been reflected in the pro forma combined condensed financial statements. 3. Intercompany transactions (including purchased and exchanged power transactions) between NSP and WEC during the periods presented were not material and, accordingly, no pro forma adjustments were made to eliminate such transactions. 4. A pro forma adjustment has been made to conform the presentation of noncurrent deferred income taxes in the pro forma combined condensed balance sheet into one net amount. All other report presentation and accounting policy differences are immaterial and have not been adjusted in the pro forma combined condensed financial statements. EX-99 5 Exhibit 99.04 UNAUDITED PRO FORMA FINANCIAL INFORMATION The following unaudited pro forma financial information adjusts the historical consolidated balance sheets and statements of income of the Company and WEC's utility subsidiary, Wisconsin Electric Power Company (referred to herein as WE) after giving effect to the proposed business combination transaction (the Transaction) to form Primergy and a new subsidiary structure. The unaudited pro forma combined condensed balance sheets at December 31, 1996 give effect to the Transaction as if it had occurred on that date. The unaudited pro forma combined condensed statements of income for the periods ended December 31, 1996, 1995, and 1994, give effect to the Transaction as if it had occurred at January 1, 1994. These statements are prepared on the basis of accounting for the Transaction as a pooling of interests and are based on the assumptions set forth in the notes thereto. The following pro forma financial information has been prepared from, and should be read in conjunction with, the historical consolidated financial statements and related notes thereto of the Company and WE. The following information is not necessarily indicative of the financial position or operating results that would have occurred had the Transaction been consummated on the date, or at the beginning of the periods, for which the Transaction is being given effect nor is it necessarily indicative of future operating results or financial position. Completion of the Transaction is subject to numerous conditions, many of which are beyond NSP's control. Wisconsin Energy Company Pro Forma Combined Condensed Information The pro forma financial information combines the historical financial statements of the Company and WE after giving effect to the Transaction, including the merger of the Company into Wisconsin Energy Company and the transfer of certain Company gas distribution properties to New NSP. WISCONSIN ENERGY COMPANY * UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME TWELVE MONTHS ENDED DECEMBER 31, 1996 (In thousands) WE The Company Pro Forma Pro Forma As Reported As Reported Adjustments Combined Utility Operating Revenues Electric $1 393 270 $377 073 $1 770 343 Gas 364 875 88 756 453 631 Steam 15 675 15 675 Total Operating Revenues 1 773 820 465 829 2 239 649 Utility Operating Expenses Electric production- fuel and purchased power 331 867 178 657 510 524 Cost of gas sold and transported 234 254 58 347 292 601 Other operation 391 520 77 851 469 371 Maintenance 103 046 19 617 122 663 Depreciation and amortization 202 796 35 731 238 527 Taxes other than income taxes 77 866 14 332 92 198 Income taxes 126 627 24 688 151 315 Total Operating Expenses 1 467 976 409 223 1 877 199 Utility Operating Income 305 844 56 606 362 450 Other Income (Expenses) 11 746 1 016 12 762 Income Before Interest Charges and Preferred Dividends 317 590 57 622 375 212 Interest Charges 106 275 18 925 125 200 Net Income 211 315 38 697 250 012 Preferred Stock Dividend Requirement 1 203 1 203 Earnings Available for Common Stockholder $ 210 112 $ 38 697 $ 248 809 See accompanying notes to unaudited pro forma combined financial statements. * In connection with the business combinations, WE will be renamed Wisconsin Energy Company Note: Earnings per share of common stock are not applicable because the Wisconsin Energy Company common stock will be owned by Primergy. WISCONSIN ENERGY COMPANY * UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME TWELVE MONTHS ENDED DECEMBER 31, 1995 (In thousands) WE The Company Pro Forma Pro Forma As Reported As Reported Adjustments Combined Utility Operating Revenues Electric $1 437 480 $381 040 $1 818 520 Gas 318 262 78 058 396 320 Steam 14 742 14 742 Total Operating Revenues 1 770 484 459 098 2 229 582 Utility Operating Expenses Electric production- fuel and purchased power 345 387 178 446 523 833 Cost of gas sold and transported 188 764 52 356 241 120 Other operation 395 242 79 472 474 714 Maintenance 112 400 20 780 133 180 Depreciation and amortization 183 876 33 097 216 973 Taxes other than income taxes 74 765 14 109 88 874 Income taxes 141 029 24 662 165 691 Total Operating Expenses 1 441 463 402 922 1 844 385 Utility Operating Income 329 021 56 176 385 197 Other Income (Expenses) 21 272 2 143 23 415 Income Before Interest Charges and Preferred Dividends 350 293 58 319 408 612 Interest Charges 109 625 19 102 128 727 Net Income 240 668 39 217 279 885 Preferred Stock Dividend Requirement 1 203 1 203 Earnings Available for Common Stockholder $ 239 465 $ 39 217 $ 278 682 See accompanying notes to unaudited pro forma combined financial statements. * In connection with the business combinations, WE will be renamed Wisconsin Energy Company Note: Earnings per share of common stock are not applicable because the Wisconsin Energy Company common stock will be owned by Primergy. WISCONSIN ENERGY COMPANY * UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME TWELVE MONTHS ENDED DECEMBER 31, 1994 (In thousands) WE The Company Pro Forma Pro Forma As Reported As Reported Adjustments Combined Utility Operating Revenues Electric $1 403 562 $375 105 $1 778 667 Gas 324 349 76 715 401 064 Steam 14 281 14 281 Total Operating Revenues 1 742 192 451 820 2 194 012 Utility Operating Expenses Electric production- fuel and purchased power 328 485 179 558 508 043 Cost of gas sold and transported 199 511 53 484 252 995 Other operation 399 011 77 958 476 969 Maintenance 124 602 22 385 146 987 Depreciation and amortization 177 614 30 774 208 388 Taxes other than income taxes 76 035 13 710 89 745 Revitalization Charges 73 900 73 900 Income taxes 99 761 19 077 118 838 Total Operating Expenses 1 478 919 396 946 1 875 865 Utility Operating Income 263 273 54 874 318 147 Other Income (Expenses) 25 334 1 245 26 579 Income Before Interest Charges and Preferred Dividends 288 607 56 119 344 726 Interest Charges 106 853 17 574 124 427 Net Income 181 754 38 545 220 299 Preferred Stock Dividend Requirement 1 351 1 351 Earnings Available for Common Stockholder $ 180 403 $ 38 545 $ 218 948 See accompanying notes to unaudited pro forma combined financial statements. * In connection with the business combinations, WE will be renamed Wisconsin Energy Company Note: Earnings per share of common stock are not applicable because the Wisconsin Energy Company common stock will be owned by Primergy. NORTHERN STATES POWER COMPANY (WISCONSIN) UNAUDITED PRO FORMA CONDENSED BALANCE SHEET DECEMBER 31, 1996 (In thousands) The Company Pro Forma The Company Pro Forma Balance Sheet As Reported Adjustments As Adjusted (Note 2) Assets Utility Plant Electric $894 143 $894 143 Gas 99 817 (35 406) 64 411 Other 67 262 67 262 Total 1 061 222 (35 406) 1 025 816 Accumulated provision for depreciation (395 619) 15 196 (380 423) Nuclear fuel-net Net Utility Plant 665 603 (20 210) 645 393 Current Assets 86 933 18 445 105 378 Other Assets 56 595 (1 183) 55 412 Total Assets $809 131 $(2 948) $806 183 Liabilities and Equity Capitalization Common stock equity $331 412 $331 412 Cumulative preferred stock and premium Long-term debt 231 688 231 688 Total Capitalization 563 100 563 100 Current Liabilities Current portion of long-term debt Short-term debt 39 300 39 300 Other 50 112 50 112 Total Current Liabilities 89 412 89 412 Other Liabilities 156 619 (2 948) 153 671 Total Capitalization and Liabilities $809 131 $(2 948) $806 183 See accompanying notes to unaudited pro forma combined condensed financial statements. WISCONSIN ENERGY COMPANY* UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET DECEMBER 31, 1996 (In thousands) Adjusted WE The Company Pro Forma Pro Forma Pro Forma Balance Sheet As Reported As Adjusted Adjustments Combined (See Page 59) (Note 3) Assets Utility Plant Electric $4 857 528 $894 143 $5 751 671 Gas 505 100 64 411 569 511 Other 61 765 67 262 129 027 Total 5 424 393 1 025 816 6 450 209 Accumulated provision for depreciation (2 441 950) (380 423) (2 822 373) Nuclear fuel-net 75 476 Net Utility Plant 3 057 919 645 393 3 703 312 Current Assets 540 825 105 378 646 203 Other Assets 908 416 55 412 (150 269) 813 559 Total Assets $4 507 160 $806 183 $(150 269) $5 163 074 Liabilities and Equity Capitalization Common stock equity $1 738 788 $331 412 $2 070 200 Cumulative preferred stock and premium 30 450 30 450 Long-term debt 1 371 446 231 688 1 603 134 Total Capitalization 3 140 684 563 100 3 703 784 Current Liabilities Current portion of long-term debt 183 635 183 635 Short-term debt 45 390 39 300 84 690 Other 258 570 50 112 308 682 Total Current Liabilities 487 595 89 412 577 007 Other Liabilities 878 881 153 671 (150 269) 882 283 Total Capitalization and Liabilities $4 507 160 $806 183 $(150 269) $5 163 074 See accompanying notes to unaudited pro forma combined condensed financial statements. * In connection with the business combinations, WE will be renamed Wisconsin Energy Company. WISCONSIN ENERGY COMPANY * NOTES TO UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL STATEMENTS 1. The unaudited pro forma combined condensed financial statements reflect the previously planned merger by WEC of its gas utility subsidiary, Wisconsin Natural (WN), into WE to form a single combined utility subsidiary. Completion of the planned merger occurred on January 1, 1996. As part of the Merger Transaction, the unaudited pro forma combined condensed financial statements reflect the merger of the Company, currently a wholly owned subsidiary of the Minnesota Company, into Wisconsin Energy Company. At the time of the merger of the Company into Wisconsin Energy Company, New NSP will acquire certain gas utility assets in La Crosse and Hudson, Wisconsin from the Company. 2. A pro forma adjustment has been made in the Company's Unaudited Pro Forma Condensed Balance Sheet at December 31, 1996 to reflect the sale at net book value of the gas utility assets and liabilities of the Company's divisions in La Crosse and Hudson, Wisconsin to New NSP. Unaudited pro forma income statement amounts for Wisconsin Energy Company do not reflect the transfer of the La Crosse and Hudson divisions by the Company to New NSP. The revenues related to those divisions for the twelve months ended December 31, 1996, 1995 and 1994 were $32,462,000, $28,897,000, and $26,779,000, respectively. The amount of related expenses have not been quantified. 3. A pro forma adjustment has been made in the Wisconsin Energy Company Unaudited Pro Forma Combined Condensed Balance Sheet at December 31, 1996 to conform the presentation of noncurrent deferred income taxes into one net amount. All other financial statement presentation and accounting policy differences are immaterial and have not been adjusted in the unaudited pro forma combined condensed financial statements. 4. Intercompany transactions (including purchased power and exchanged power transactions) between WE and the Company during the period presented were not material and, accordingly, no pro forma adjustments were made to eliminate such transactions. 5. The allocation between NSP and WEC and their customers of the estimated cost savings resulting from the transactions contemplated by the Merger Agreement, net of the costs incurred to achieve such savings, will be subject to regulatory review and approval. None of these estimated cost savings, the costs to achieve such savings, or transaction costs have been reflected in the unaudited pro forma combined condensed financial statements. * In connection with the business combinations, WE will be renamed Wisconsin Energy Company. -----END PRIVACY-ENHANCED MESSAGE-----