-----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, A0eak2u86zC9u14zf+T/tGU6fF91va3UguBE4ULsB3XEYcIXshTyi9dSbU9tX1A4 s+QxxWDwvdpHWJFMPtjlpA== 0000072909-96-000002.txt : 19960402 0000072909-96-000002.hdr.sgml : 19960402 ACCESSION NUMBER: 0000072909-96-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960401 SROS: AMEX 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: 96542226 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 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 202,000 retail customers in an area of approximately 18,900 square miles in northwestern Wisconsin, to approximately 9,200 electric retail customers in an area of approximately 300 square miles in the western portion of the Upper Peninsula of Michigan, and to 10 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 71,000 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 1995, the Company derived 83 percent of its total operating revenues from electric utility operations and 17 percent from gas utility operations. As of December 31, 1995, the Company had 896 full-time equivalent employees including 801 full-time employees. PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION Description of the 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 corpo ration (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 strategic business combination involving the Minnesota Company and WEC in a "merger-of-equals" transaction (the Merger Transaction). The Merger Transaction, which was ap proved by the respective Boards of Directors and shareholders of the constituent companies, is expected to close shortly after all of the conditions to the consummation of the Merger Transaction, including obtaining applicable regulatory approvals, are met or waived. The goal of the Minnesota Company and WEC is to receive approvals from all regulatory authorities by the end of 1996, however, some regulatory authorities have not established a timetable for their decisions. Therefore, timing of the receipt of the approvals necessary to complete the Merger Transaction is not known at this time. See discussion of the regulatory proceedings under the caption "Utility 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, the holding company of the combined enterprise will be registered under the Public Utility Holding Company Act of 1935, as amended. The holding company will be named Primergy Corpo ration ("Primergy") and will be the parent company of both the Minnesota Company (which, for regulatory reasons, will reincorporate in Wisconsin) and of WEC's principal utility subsidiary, Wisconsin Electric Power Company ("WEPCO"), which will be renamed "Wisconsin Energy Company." Wisconsin Energy Company will include the operations of WEC's other current utility subsidiary, Wisconsin Natural Gas Company, which was merged into WEPCO effective Jan. 1, 1996. It is anticipated that, following the Transaction, except for certain gas distribution properties serving the cities of La Crosse and Hudson, Wisconsin transferred to the Minnesota Company, the Company will be merged into Wisconsin Energy Company. The Merger Agreement 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 (defined below) 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 will 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 des ignations. Following the merger of the Company into Wisconsin Energy Company, the Company' 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. Merger Consummation Conditions The Transaction is subject to customary closing conditions, including, without limitation, the receipt of all necessary governmental approvals 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 "Utility 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 WEC and the Minnesota Company 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 it is expected that the Minnesota Company and WEC will make the following filings as part of the regulatory approval process of the merger: -Notification under the Hart-Scott-Rodino Antitrust Act of 1976, as amended, is expected to be filed in the second quarter of 1996 with the Department of Justice and Federal Trade Commission. -An Application will be filed for SEC approval of the registration of Primergy under the Public Utility Holding Company Act of 1935, as amended, including a decision on possible divestiture of the existing gas operations and certain non-regulated businesses. 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. 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 Oct. 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 satisfied by 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 contained 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 Agree ment 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 A preliminary estimate indicates that the Merger Transaction will result in net savings for the constituent companies of approximately $2.0 billion in costs over 10 years. It is anticipated that the synergies created by the Merger Transaction 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 rate reduction of 1.5 percent and a four-year rate freeze in the retail electric 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 will be 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. The Minnesota Company has proposed a two-year freeze for retail natural gas rates in its Minnesota jurisdiction. In addition, 38 percent of the Minnesota Companys net gas savings available in 1997 are forecasted to be in the purchased cost of gas and would be reflected in customer rates 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 in that time period. 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 Wisconsin Energy Company 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, Wisconsin Energy Company 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 they believe 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 Wisconsin Energy Company be allowed to file with the PSCW during the rate freeze period for recovery of the costs related to these events. Both 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. REGULATION AND RATES Utility Industry Restructuring in Wisconsin 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. To date, after reviewing a set of proposals developed by its working group, the PSCW has set a target date of 2000 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. The PSCW is also examining similar issues for the gas industry. Construction Authorization in Wisconsin 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 from $1,000,000 to $3,000,000. Any projects costing less than $3,000,000, or 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 Michigan Public Service Commission ("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 91.8 percent of the Company's 1995 revenues from sales were subject to PSCW jurisdiction. Of the 91.8 percent, 73 percent was generated from electric retail revenues and the remaining 18.8 percent from retail gas revenues. The Company's wholesale revenues from sales subject to FERC jurisdiction were approximately 4.6 percent of the Company's 1995 revenues from sales with the remaining 3.6 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 dated March 11, 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 certain demand costs for sales and purchased power, which had been excluded prior to that date. The Company's retail gas rate schedules include a purchased gas adjustment clause which provides for inclusion of the current cost of gas including its transportation. The factors applied under the purchased gas adjustment clause are adjusted on an ongoing basis to reflect a reconciliation of gas costs incurred and recovered. The PSCW scheduled a generic hearing in March 1996 to consider alternative incentive-based gas cost recovery adjustment mechanisms to replace the current purchased gas adjustment clause. The incentive-based mechanism, as proposed by the Company would allow recovery of fluctuations in gas costs based on an index, such as the spot market price. A PSCW decision is pending. 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. Wholesale 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 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 issued a letter requesting the Company to decrease electric rates by $4.8 million (1.7%). The Company accepted the PSCW proposal in a letter dated November 2, 1995. On December 21, 1995, the PSCW issued an order approving a $2.5 million gas rate increase (3.4% on an annual basis). 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. The Company expects its next general rate case filing to be in June 1997, for rates effective in 1998, as required by the PSCW biennial filing requirements if the Transaction has not been completed prior to that time. 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 $0.2 million relates to the Company) at the time of the Merger Transaction and four-year rate freeze thereafter, with certain exceptions. The Company and WEPCO filed full stand alone rate cases on March 15, 1996, based on a 1997 year. Technical hearings on the stand alone rate cases are expected in July 1996. Testimony and exhibits supporting the Merger Transaction and rate plan were filed before the PSCW on March 18, 1996. The PSCW's decision on the merger approval filing is expected in the fourth quarter of 1996. Michigan There were no changes in the Michigan electric or gas base rates during 1995. 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's decision on the Merger Transaction approval filing is expected in the first half of 1996. Wholesale (FERC) The Company had 10 wholesale customers at December 31, 1995, with revenues of approximately $18.0 million. In 1995, the Wisconsin Company offered its wholesale customers a discount of from three to five percent from the FERC authorized rate. Seven of the ten municipal customers elected to either renew or extend their contracts to receive these discounts. As part of the settlement agreement between the Primergy partners and the Wisconsin Intervenors, the cities of Medford and Rice Lake have a 5 year power supply agreement. For the first year the two cities receive at discounted full requirements service, for the remaining four years, they receive service at a negotiated, fixed rate. Upon completion of the term, NSP will have no further obligation to service these two customers. The other customer did not elect to sign a new contract, but continues with its existing contract. Due to these changes, 1996 revenues are estimated to decrease from 1995 revenues by approximately $0.6 million. Electric Transmission Tariffs and Settlement (FERC) 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. The Company's portion of refunds due were not material at December 31, 1995. In March 1994, the Minnesota Company and the Company jointly filed a revised open access transmission tariff with the FERC. On May 25, 1994, the FERC accepted the filing with the new rates effective November 1, 1994, subject to refund. The FERC also ruled the tariff would be subject to the requirement that the Company and the Minnesota Company offer transmission service using terms and conditions comparable to their own use of the system. 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. On May 25, 1995, the Administrative Law Judge (ALJ) issued to the FERC a Certification of Contested Offer of Settlement. Although there are no genuine issues of material fact and all parties support certification of the Settlement, the ALJ stated the Settlement was contested since FERC Staff and Electric Clearinghouse listed numerous provisions that needed to be modified in response to the issuance of a proposed rulemaking referred to as the Mega NOPR. (See discussion and definition of Mega-NOPR below.) The ALJ further stated the Settlement was not affected by the issuance of the Mega-NOPR, even though the FERC in the Mega-NOPR stated that any settlement approved prior to the issuance of the final rule will be made subject to the outcome of the final rule. The FERC approved the Settlement on February 14, 1996, subject to the outcome of the final rule. The revenue effect on the Company and the Minnesota Company is expected to be an increase 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. Open Access Transmission Proceedings (FERC) In March 1995, the FERC issued two pronouncements which are expected to have a major impact on the electric industry: Notice of Proposed Rulemaking on Open Access Non-Discriminatory Transmission Services and a Supplemental Notice of Proposed Rulemaking on Stranded Investment (together called the Mega-NOPR); and a proposal to require Real-Time Information Networks (RIN). The stated purpose for the Mega-NOPR is to create a vigorous wholesale electric market by requiring transmission providers to offer open access to their transmission systems. FERC seeks to accomplish this by requiring utilities to unbundle power sales from transmission--but only for new requirements contracts and new coordination trade contracts. FERC did not require utilities to divest or separate their generation businesses from their transmission businesses. FERC also proposes to not disrupt any existing power or transmission contracts. The Mega-NOPR would apply to all utilities under FERC's jurisdiction and would require each utility to file individual tariffs. FERC also seeks to require non-jurisdictional transmission-owning entities (such as municipals and cooperatives) to offer open access by including a reciprocity clause in utilities' individual tariffs, so that those who take service from a FERC jurisdictional utility must offer the open access. The rule will be implemented in two stages. In the first stage, generic pro forma tariffs rates would take effect under financial data filed with FERC on Form 1. In the second stage, utilities and their customers could file to modify the tariffs and rates within the limits of non-discriminatory open access. A Procedural Order which was concurrently issued with the Mega-NOPR grandfathers the pending joint transmission tariff of the Company and the Minnesota Company into the second stage. The rules proposed in the Mega-NOPR would require transmission providers to offer network, point-to-point and ancillary services. Ancillary services would include scheduling and dispatching, load following, imbalance resolution, reactive power support and system protection. In the Mega-NOPR, FERC further clarified its guidelines for utilities to recover stranded investment costs due to facilitation of open access to a competitive market. FERC stated that it recognized the vital link between the prior stranded cost proposal issued in 1994 and the open access initiative. In the Mega-NOPR, FERC has proposed a backstop position, whereby it will only entertain stranded cost filings when a state regulatory commission does not have authority under state law to address stranded costs at the time retail wheeling (which is the transmission to retail customers of power generated by a third party, in competition with supplies from the host utility) takes place. The Mega-NOPR also provides that FERC will entertain utilities' requests for stranded-cost recovery even after a state has addressed the issue. However, if a state commission has authority to act, but does not do so, a utility may not seek recovery from the FERC. With regard to the RIN proposal, FERC is considering requiring that each public utility create an electronic bulletin board to ensure that potential purchasers of transmission services have access to information to enable them to obtain open access transmission services on a non- discriminatory basis from the public utility. The proposed RIN would include a wide range of information such as: availability of transmission services (including ancillary services); rates; hourly transfer capacities; hourly amounts scheduled; transmission and unit outages; load flow data; and transaction specific information on all requests for transmission service, including requests by transmission owner's wholesale power marketing department. In their joint response to the RIN and Mega-NOPR proposals, the Minnesota Company and the Company filed comments which indicated support for FERCs open access objective and for FERCs position that it should be a backstop for the recovery of stranded costs. Proposed Transaction Approval Proceedings (FERC) On July 10, 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, a proposed joint transmission tariff, and an amendment to the Company's Interchange Agreement with the Minnesota Company. On September 11, 1995, several parties filed interventions and protests. On October 10, 1995, the Applicants replied to the petitions for intervention and requests for hearing. On or about October 25, 1995, intervenors filed responses to the Applicants reply. On November 9, 1995, the Applicants filed a response to the intervenors reply comments. Additional intervenor comments were filed on November 22, 1995. The issues raised by the intervenors with respect to the merger application at FERC are primarily related to two areas: the impact on competition and the nature of the cost savings. The intervenors argue competition will be adversely affected because NSP and WEPCO will constrain the transmission system at the interconnections between NSP and a group of Wisconsin and upper Michigan utilities, allowing NSP and WEPCO to increase the amount they charge for energy. In response to these intervenor concerns the Applicants: have committed to make whatever changes are required in their transmission tariff by FERC in its Mega-NOPR proceedings to ensure access is achieved. have filed to expand the capacity of the interconnections and further expansion is being pursued. have committed that if the interface is constrained, any economy energy sales that NSP and WEPCO make to the Wisconsin and upper Michigan utilities will be at incremental cost. will waive their AES (native load) and Mid-Continent Area Power Pool (MAPP) line loading relief procedures priorities for internal and economy transactions through the interface. To the extent that a regional transmission operator has not been established by the time of the merger, are willing to establish an unaffiliated entity as an Independent Tariff Administrator that will schedule transmission use and otherwise ensure that transmission service is provided on a nondiscriminatory basis. See discussion of the negotiations to convert MAPP to a Regional Transmission Group at the Electric Operations - Capability and Demand section herein. On January 31, 1996, the FERC issued an order which put the merger approval filing on an accelerated schedule. The FERC set only one issue hearing. The FERC ordered a hearing regarding the effect of the proposed merger on bulk power competition. The order requires the initial decision to be issued by August 30, 1996, and briefs on exception to be filed by September 30, 1996. In March 1996, the PSCW requested that the FERC broaden the scope of the merger hearing to evaluate whether the proposed merger will impair effective state oversight of retail rates. The FERC has not acted upon the PSCW's request. While the Company expects the FERC's decision on the merger in the fourth quarter of 1996, the approval process may extend beyond 1996. The FERC also set for hearing the Transmission Tariff filing (Docket ER95-1358-000) and the Interchange Agreement filing (Docket ER95-1357-000). The Applicants have settled with several intervenors and are continuing to meet with interested parties in the FERC proceeding, seeking resolution of the intervenor issues. ELECTRIC OPERATIONS Competition The Company's electric sales are subject to competition in some areas from municipally owned systems, rural 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 (1935 Act) 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 1935 Act. 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 Mega-NOPR issued by FERC (as discussed in "Regulation and Rates", herein) reflect the trend toward increasing transmission access under the Energy Act. The FERC Mega- NOPR seeks to standardize the terms, conditions and rate development approaches to ensure fundamental principles underlie open access tariffs. The Company shares the FERC view that such tariffs are a necessary step to support functional unbundling of generation and transmission and the evolution of a competitive electric power market place. The final rules FERC will issue as a result of the Mega-NOPR are expected to be aligned with the pro-forma tariff. The use of pro-forma tariffs in merger filings enables FERC to separate and exclude open access transmission from other issues in the Primergy merger docket. This treatment was requested in the Primergy merger filing that included the pro-forma tariff. The Energy Act's ultimate impact on the Company cannot be predicted at this time. Many states are currently considering retail competition. Regulators in Wisconsin are currently considering what actions they should take regarding electric industry competition. 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. Competition should be phased in for retail markets by customer classes, with all customers having choice of supplier by 2001. The generation segment of the industry should be deregulated by 2001. Prudent stranded costs should be recovered prior to the advent of retail wheeling. Finally, 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. In 1995, the PSCW voted to adopt an electric utility restructuring plan which includes a 32-step phase-in of retail wheeling by the year 2001. A key component of the plan is to provide the protections necessary to ensure that consumers are not harmed in an increasingly competitive environment. One component of the plan is to have an independent system operator to control transmission access. The Company believes the transition to a more competitive electric industry is inevitable and beneficial for all consumers. The Company supports both regulators goals to facilitate an orderly and efficient transition to an open, fair and competitive energy market for all customers and suppliers. Michigan also has a retail wheeling experiment, limited to its two largest utilities and customers larger than $50 million, currently underway. The Company's customers are not included in this experiment which is currently being challenged in court. A report on further restructuring has been issued by the Governor of Michigan, known as the Rothwell Report, and the MPSC is moving forward under guidelines set forth in this report. 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 NSP System added the Angus Anson 232 MW gas-fired combustion turbines generation facility, located in Sioux Falls, South Dakota in September 1994. Also in 1994, the Minnesota Company signed a long-term power purchase contract with LSP-Cottage Grove for 245 MW of annual capacity for thirty years scheduled for an in service date of 1997. The Minnesota Company operates two nuclear generating plants: the single unit, 539 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 Sept. 8, 1970, and commenced operation on June 30, 1971. Prairie Island Units 1 and 2 received their 40-year operating licenses on Aug. 9, 1973, and Oct. 29, 1974, respectively, and commenced operation on Dec. 16, 1973, and Dec. 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 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. DOE disposal fees have been ranging from approximately $10 million to $12 million per year, which the Minnesota Company recovers from its customers in cost-of-energy rate adjustments. In 1985, the Minnesota Company paid the DOE a one-time fee of $95 million for fuel used prior to April 7, 1983. 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. In 1979 the Minnesota Company began expanding the used nuclear fuel storage facilities at its Monticello Plant by replacement of the racks in the storage pool. Also, in 1987, the Company completed the shipment of 1,058 spent fuel assemblies from the Monticello Plant to a General Electric storage facility in Morris, Illinois. As a result, the Monticello plant now has sufficient pool capacity for temporary storage of used fuel to operate until 2008. In 1976 the Minnesota Company began expanding the used nuclear fuel storage facilities at its Prairie Island Plant by replacement of the racks in the storage pool. Total capacity was increased from 210 fuel assemblies to 1,386 fuel assemblies. In 1994 the spent nuclear fuel storage facilities at the Minnesota Company's Prairie Island Plant reached full capacity. In May 1994 additional on-site dry cask fuel storage facilities were approved by the Minnesota Legislature which are expected to provide sufficient temporary storage capacity to operate the Prairie Island plant until at least 2002. Capability and Demand The Company's record peak demand occurred on December 11, 1995, and was recorded at 1,042 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). Due to MAPP's penalty for reserve margin shortfalls and to be prepared for weather uncertainty at the lowest potential cost, the NSP system carried a reserve margin for 1995 of 20 percent. In March 1996, the members of MAPP approved the conversion of MAPP into a Regional Transmission Group (RTG). This conversion plan will now be submitted to FERC for approval before August 1, 1996. By converting MAPP to an RTG, members will have more input into transmission access within other members territories. This is one of the proposals in response to intervenor concerns in the FERC regulatory approval proceeding of the Minnesota Companys 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 80 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 1995. 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 ("DNR") to burn tire derived fuel 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 need to respond to customer needs and focus on increasing value of service so that, over the long term, the programs help its customer base become more stable, energy efficient and competitive. During 1995, the Company's programs reduced system peak demand by approximately 20 Megawatts (MW) in the commercial, industrial and agricultural customer sectors and over 3.9 MW in the residential sector. These reductions were achieved 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 173 MW of summer peak demand reduction, which is equivalent to 16% of its 1995 summer peak demand. A cumulative goal of 200 MW of peak demand reduction by 1997 has been established. The Company continues to focus on improving the cost- effectiveness of its DSM programs through market research studies and program evaluations. The PSCW has approved changes to the Companys deferral and amortization practices for Wisconsin DSM program expenditures effective January 1, 1996. These changes allow the Company to currently expense rather than defer and amortize certain program expenditures beginning in 1996. Expenditures incurred prior to 1996 will 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 Northern States Power Company (Minnesota) and Northern States Power Company (Wisconsin) ("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 an agreement dated March 31, 1972, with amendments filed in 1994. The NSP System is one of 58 members in MAPP consisting of 8 investor-owned systems, eight generation and transmission cooperatives, three public power districts, eight municipal systems and the DOE's Western Area Power Administration, and 30 Associate Participants. 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 1972 MAPP agreement, as amended, was accepted for filing with the FERC on December 15, 1994. Fuel Supply In 1995 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, and wood) over the next several years. The actual fuel mix for 1995, and the estimated fuel mix for 1996 and 1997, are as follows: Fuel Use on Btu Basis (Est.) (Est.) 1995 1996 1997 Coal 57.9 59.9 59.7 Nuclear 39.0 36.8 36.6 Other * 3.1 3.3 3.7 * Includes oil, gas, refuse derived fuel and wood 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 Electric Revenue (thousands) Residential 1995 1994 1993 1992 1991 With space heating $ 24 825 $ 23 916 $ 24 086 $ 22 521 $ 23 357 Without space heating 96 248 92 033 90 632 85 889 87 036 Small comm'l and indust'l 54 826 53 842 52 214 50 234 50 391 Large comm'l and indust'l* 110 270 107 462 101 609 95 336 90 748 Street lighting and other 4 320 4 335 4 262 4 206 4 141 Total retail 290 489 281 588 272 803 258 186 255 673 Sales for resale 17 902 17 414 16 009 14 755 21 579 Total $308 391 $299 002 $288 812 $272 941 $277 252 Sales (millions of kilowatt-hours) Residential With space heating 372 358 362 346 369 Without space heating 1 346 1 284 1 265 1 229 1 289 Small comm'l and indust'l 882 863 834 814 846 Large comm'l and indust'l* 2 403 2 306 2 169 2 098 2 056 Street lighting and other 42 43 42 43 45 Total retail 5 045 4 854 4 672 4 530 4 605 Sales for resale 456 438 417 394 571 Total 5 501 5 292 5 089 4 924 5 176 Customer accounts (Dec. 31) Residential With space heating 28 521 28 024 27 600 27 266 26 923 Without space heating 150 799 148 852 147 000 145 533 144 197 Small comm'l and indust'l 27 706 27 175 26 800 26 418 25 988 Large comm'l and indust'l* 1 276 1 182 1 200 1 109 1 073 Streetlighting and other 998 989 900 1 000 993 Total retail 209 300 206 222 203 500 201 326 199 174 Sales for resale 10 10 10 10 16 Total 209 310 206 232 203 510 201 336 199 190 *Includes customers with annual electric demand of 100 kilowatts or more. GAS OPERATIONS During 1995, 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 Companys 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 Companys 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 primary gas transportation provider, NNG, is in the process of determining the final amount of transition costs to be passed on to all customers as a result of Order 636 restructuring. NNG's restructuring provided for the assignment of a significant portion of NNG's gas supply and upstream contract obligations. The solution was beneficial because NNGs customers contracted directly for obligations, rather than paying to buy out those obligations and then contracting with the same gas suppliers and pipelines to replace the merchant function. NNGs total transition costs recoverable for the remaining unassigned agreements is limited to $78 million. In addition, NNG may seek transition cost recovery for certain other costs, subject to prudency review. NNGs total Order 636 transition costs, to be passed to all of its customers, are estimated to be approximately $100 million. NNG will recover the prudent transition costs by amortizing the amount over a period of several years, and including the amortized costs as a component of its transportation charges. The Company and the Minnesota Company estimate that they will be responsible for less than $11 million of NNG's transition costs, spread over a period of approximately five years, which began November 1, 1993. To date, the Company's regulatory commissions have approved recovery of restructuring charges in retail gas rates. The Company has no Order 636 transition cost responsibilities to its other pipelines. The Companys ability to operate in a competitive gas market was expanded through the Minnesota Companys acquisitions of Viking in June 1993 and the assets of a gas marketing business, in October 1993. Viking allows NSP continued access to competitive interstate natural gas transportation. The gas marketing business assets are owned by Cenerprise, Inc. (Cenerprise), a Minnesota Company subsidiary. Cenerprise 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 is continuing its pursuit of growth and profitability through expansion of its distribution system and services both inside and outside of its existing service territories. In 1995 the Company extended service to the Township of Pleasant Valley in Eau Claire County, the Townships of Tainter and Cedar Falls in Dunn County, and the Town of Washburn in Bayfield County. 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: energy management services, 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, will, by order of the PSCW, be discontinued at the end of 1996. Prior to that time, the Company will determine whether to continue these activities as fully regulated or shift them to fully unregulated. 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): Revenues (thousands) Residential 1995 1994 1993 1992 1991 With space heating $36 695 $33 726 $32 029 $27 592 $24 411 Without space heating 556 571 535 480 532 Small com.w/o space heating 929 869 824 697 682 Small com.with space heating 19 263 17 691 17 049 14 990 13 728 Small industrial firm 6 428 6 545 5 961 3 942 2 953 Total firm 63 871 59 402 56 398 47 701 42 306 Interruptible 16 569 15 299 15 156 13 015 12 869 Total $80 440 $74 701 $71 554 $60 716 $55 175 Sales (thousands of mcf) Residential With space heating 5 801 5 243 5 221 4 756 4 598 Without space heating 72 73 72 66 82 Small com.w/o space heating 180 168 162 145 150 Small com.with space heating 3 785 3 424 3 403 3 142 3 056 Small industrial firm 2 162 2 126 1 932 1 128 838 Total firm 12 000 11 034 10 790 9 237 8 724 Interruptible 6 951 6 032 6 153 5 650 5 685 Total 18 951 17 066 16 943 14 887 14 409 Customer Accounts Residential With space heating 58 549 55 663 52 700 49 413 46 060 Without space heating 2 778 2 946 3 000 3 089 3 253 Small com.w/o space heating 560 551 500 529 526 Small com.with space heating 7 205 6 846 6 600 6 269 5 960 Small industrial firm 116 116 100 110 113 Total firm 69 208 66 122 62 900 59 410 55 912 Interruptible 292 272 300 259 253 Total 69 500 66 394 63 200 59 669 56 165 ENVIRONMENTAL MATTERS The Wisconsin Department of Natural Resources (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 affected 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 to the air. Occasional, infrequent exceedances of DNR air emission opacity limitations occurred in 1995 at the Company's Bay Front facility. These are being resolved through operating changes. No agency enforcement action has resulted. 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. The Company has procedures in place to comply with these regulations. 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. Both the Company and the Minnesota Company have received notices for 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 (PRP's), 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 million. The Company's and the Minnesota Company's share of this cost is currently estimated to be approximately 1%. The Company's share alone is estimated to be $20,000. In addition, the administrator of a group of PRP's has notified the Company that it might be responsible for cleanup of a solid and hazardous waste landfill site in Eau Claire, Wisconsin. The Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined, it is not feasible to predict the outcome of the matter at this time or any potential future impact on the Companys 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. On February 19, 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 a number of remediation options which 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 ongoing limited groundwater treatment, would cost approximately $6.0 million. Currently, the WDNR is conducting an investigation in Chequamegon Bay adjacent to Kreher Park to determine the extent of contamination in the bay. The WDNR has informed the Company that it will not choose or proceed with any remediation options on any portion of the Ashland site until the completion of the Chequamegon Bay investigation in the second half of 1996. Until more information is known concerning the extent of remediation required by the WDNR, the remediation method selected and 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 the expected timing of any payments related to the Ashland site is not determinable. At December 31, 1995, the Company had recorded an estimated liability of $900,000 for future remediation costs at this site and had incurred approximately $400,000 in actual expenditures. On March 11, 1996, the Company received a Notice of Violation from the WDNR stating that emissions from the Company's French Island facility had exceeded allowable levels for dioxin. The WDNR has requested a written response from the Company no later than April 15, 1996, setting forth the Companys plans for bringing the emissions levels back into compliance. The Company is currently investigating this matter to determine the cause of this unexpected event. 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 operations. In late December 1994, the Company completed installation of a control center monitoring system at the Bay Front generating plant in Ashland, Wisconsin. The continuous emissions system which will monitor emissions from the four generating units, was mandated by the Clean Air Act and has been in service since January 1, 1995. CONSTRUCTION AND FINANCING During the five years ended December 31, 1995, the Company had gross additions to utility plant in service of approximately $250.9 million. Included in the Company's gross additions is $29.8 million for electric production facilities, $149.9 million for other electric properties, $38.4 million for gas utility properties, and $32.8 million for other utility properties. Retirements during the same period were approximately $39.2 million. Based on studies made by the Company, the weighted average age of depreciable property was 12.9 years at December 31, 1995. Expenditures for the Company's construction programs for the five-year period 1996-2000, are estimated to be as follows: Year Estimated Construction Expenditures 1996 $ 54 million 1997 60 million 1998 68 million 1999 64 million 2000 57 million TOTAL $303 million The 1996 construction expenditures are estimated to include approximately $37.6 million for electric facilities, $5.0 million for gas facilities and $11.2 million for general plant and equipment. It is presently estimated that approximately 88% of the 1996-2000 construction expenditures will be provided by internally generated funds, with the remainder from short-term and long-term debt financing. In addition to construction financing needs, long-term debt is expected to be issued to refinance the Companys 9-1/8% first mortgage bonds, which are callable beginning April 1, 1996. At December 31, 1995, the Company's short-term borrowings payable to the Minnesota Company were $50.9 million. These short-term borrowings have been authorized up to $55.0 million by the PSCW. 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 1995, the total number of full- and part-time employees of the Company was approximately 896. About 410 employees of the Company are represented by one local IBEW labor union, under a three year collective bargaining agreement expiring December 31, 1996. Recent changes to the Company's employee and retiree benefits, which support a broad NSP goal of providing market-based benefits, include: Active nonbargaining medical premium increases: A cost sharing strategy for medical benefits for nonbargaining employees was implemented in 1994. The strategy consisted of adjusting the employee contribution portion of total medical costs to 10% in 1994 and 20% in 1995 and 1996. 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. In 1994, the Company began matching employees' pre-tax 401(k) contributions. Such matching contributions were $0.5 million in 1995, based on matching up to $700 per year for each nonbargaining employee and up to $500 per year for each bargaining employee. In 1994, matching contributions were $0.3 million. In 1996, NSP's annual match will increase to $900 for nonbargaining employees. Under the terms of the bargaining agreement implemented in 1994, NSP's annual match for each bargaining employee will increase to $600 in 1996. 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 1995, nonbargaining employees received an average wage scale increase of 3.5%, while bargaining employees received a 2% base wage increase and a 1.5% lump sum payment. In January 1996, nonbargaining employees received an average wage scale increase of 3.5%, while bargaining employees received a 4% base wage increase. Item 2. Properties Electric Utility The Company's major electric generating facilities consist of the following: Projected Year 1996-7 Winter Station and Units Fuel Installed Capability (MW) Combustion Turbine: Flambeau Station Gas/Oil 1969 17 (1 unit) Park Falls, WI Wheaton Oil 1973 440 (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 248 TOTAL 1 001 At December 31, 1995, the Company owned approximately 2,392 pole miles of overhead electric transmission lines, 8,044 pole miles of overhead electric distribution lines, 37 conduit miles and 1,011 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 1,438 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 liquified natural gas facilities are located in Eau Claire and La Crosse, Wisconsin. 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 may be considered for use 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. 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 Omitted per conditions set forth in general instruction J (1) and (a) and (b) of Form 10-K for wholly-owned subsidiaries (reduced disclosure format). 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, 1995 with the year ended December 31, 1994. The Company's net income for year ended December 31, 1995 was $39.2 million, up from the $38.5 million earned in the same period of 1994. The 1995 operating income increased by $1.3 million from the 1994 level. Electric Sales and Revenues Electric revenues for 1995 increased $5.9 million, a 1.6 percent increase from 1994. Revenues from retail sales, which accounted for 76.3 percent of the electric revenues in 1995, increased $8.9 million or 3.2 percent. Reflected in this revenue increase is an estimated $5.1 million due to more favorable weather conditions. Residential sales in 1995 were 4.6 percent higher than 1994, including weather impacts. Included in the 1995 retail increase is $2.8 million related to the Company's large commercial and industrial customers, some of which expanded their operations, increasing energy needs. The Company's wholesale customers accounted for 5.8 percent of the total electric revenues. Wholesale revenues increased $0.5 million or 2.8 percent in 1995, with sales increasing 4.2 percent. Another major component (approximately 15.3 percent) of electric revenues is charges billed to the Minnesota Company through the Interchange Agreement (see Part I, Item 1; Business-Electric Operations). Interchange Agreement billings charged to the Minnesota Company decreased $3.3 million mainly as a result of less fuel being burned in Wisconsin for system requirements. Other electric revenues decreased $0.2 million in 1995. Gas Sales and Revenues Gas revenues in 1995 increased by $1.3 million or 1.8 percent as compared with 1994. This is the impact of increased revenues due to a 8.8 percent increase in firm sales due to customer and usage growth, and increased revenues of $0.5 million due to more moderate winter weather in 1994. Offsetting these firm sales increases were the impact of lower purchased gas costs being reflected in customer rates. Operating Expenses and Other Factors Fuel for Electric Generation, which represents the Company's portion of the NSP System's fuel generation and Purchased and Interchange Power together decreased $1.1 million or 0.6 percent in 1995 from 1994. Although system output increased to meet higher sales demand, decreases in the cost per unit of energy more than offset the costs of higher sales. Gas Purchased for Resale decreased $1.1 million or 2.1 percent. Of the $1.1 million deviation, approximately $0.3 million is due to the lower cost per unit of purchased gas, $0.7 million is due to lower transportation charges, with the remaining $0.1 million due to decreases in miscellaneous purchased gas costs. Other operation costs increased $2.3 million due to increases in steam and distribution operating expenses and in transmission costs charged from the Minnesota Company for the Companys share of NSP system costs. Maintenance expense for 1995 was $1.6 million lower than 1994 levels. Of this decrease, $1.3 million related to lower maintenance costs for the Companys hydro plants. Administrative and general costs decreased $1.2 million due to a decrease in labor costs. Conservation costs increased $0.5 million from 1995 as compared to 1994 primarily due to increases in the amortization levels for demand side management program costs previously capitalized. Depreciation and Amortization increased $2.3 million in 1995 primarily due to higher levels of depreciable plant, particularly shorter-lived computer equipment. Property and General Taxes increased $0.4 million primarily due to higher gross receipts tax as a result of 1995 revenues increasing over 1994 revenues. Income taxes increased $5.5 million in 1995 over the 1994 level. Approximately $2.8 million of the increase is due to adjustments made in the third quarter of 1994 decreasing current tax expense. These adjustments resulted from the updating of the status of the estimated income tax payments expected to be incurred as a result of unaudited tax years. The remaining $2.7 million increase is primarily attributable to the increase in pretax book income. See Note 4 to the Financial Statements for a detailed reconciliation of effective tax rates and statutory rates. Allowances for Funds Used During Construction (AFC) decreased $0.2 million in 1995 from 1994 due to lower levels of qualifying construction and lower AFC rates associated with increased use of low-cost short-term borrowings. Other income and deductions increased $1.1 million in 1995 from 1994. This increase was mainly due to increases in subsidiary company earnings, including affordable housing and real estate businesses. Other interest and amortization expense increased $1.5 million in 1995 from 1994. An increase in interest to associated companies accounted for $1.1 million of the increase. Of this increase, $1.1 million resulted from increases in both the interest rate and the level of short-term borrowings from the Minnesota Company in 1995. The remaining $0.4 million increase in other interest expense is due to the write-off of previously deferred interest on 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 sheet 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, 1995, and the results of its operations and its cash flows for the year in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Companys management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit 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 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 audit provides a reasonable basis for the opinion expressed above. The financial statements of the Company for the years ended December 31, 1994 and 1993 were audited by other independent accountants whose report dated January 27, 1995 expressed an unqualified opinion on those statements. PRICE WATERHOUSE LLP Minneapolis, Minnesota February 5, 1996, except as to the Environmental Contingencies section of Note 8, which is as of February 19, 1996 Item 8 Financial Statements and Supplementary Data INDEPENDENT AUDITORS' REPORT Northern States Power Company (Wisconsin): We have audited the accompanying balance sheet of Northern States Power Company (Wisconsin) (the Company) and its subsidiaries as of December 31, 1994 and the related statements of income and retained earnings and of cash flows for each of the two years in the period 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 audits. We conducted our audits 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 audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1994 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. Deloitte and Touche LLP Minneapolis, Minnesota January 27, 1995 Item 8 Financial Statements and Supplementary Data Statements of Income and Retained Earnings Year Ended December 31 (Thousands of dollars) 1995 1994 1993 Operating Revenues Electric $ 380 724 $ 374 777 $ 362 473 Gas 78 058 76 715 72 760 Total 458 782 451 492 435 233 Operating Expenses Purchased and interchange power 173 743 174 144 162 510 Fuel for electric generation 4 703 5 414 3 185 Gas purchased for resale 52 356 53 484 51 501 Other operation 46 534 44 260 43 351 Maintenance 20 780 22 385 21 703 Administrative and general 25 264 26 487 26 842 Conservation and demand side management 7 674 7 211 6 556 Depreciation and amortization 33 059 30 736 28 585 Property and general taxes 14 109 13 710 13 091 Income taxes 24 662 19 077 23 103 Total operating expenses 402 884 396 908 380 427 Operating Income 55 898 54 584 54 806 Other Income and Deductions Allowance for funds used during construction-equity 445 671 694 Other income and deductions-net 1 976 864 844 Total Other Income 2 421 1 535 1 538 Income Before Interest Charges 58 319 56 119 56 344 Interest Charges Interest on long-term debt 16 038 15 995 16 343 Other interest and amortization 3 548 2 060 2 406 Allowance for funds used during construction-debt (484) (481) (411) Total interest charges 19 102 17 574 18 338 Net Income 39 217 38 545 38 006 Retained Earnings, January 1 218 833 205 114 192 816 Dividends paid on common stock (36 412) (24 826) (25 708) Retained Earnings, December 31 $ 221 638 $ 218 833 $ 205 114 See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data Statements of Cash Flows Year Ended December 31 (Thousands of dollars) 1995 1994 1993 Cash Flows from Operating Activities: Net Income $39 217 $38 545 $38 006 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 34 180 32 382 33 580 Deferred income taxes 1 839 7 614 7 161 Deferred investment tax credits recognized (936) (943) (948) AFC-equity (445) (671) (694) Insurance receivable 3 091 (3 091) 0 Other (1 064) (6 076) 67 Cash provided by (used for) changes in certain working capital items 7 282 (9 568) 299 Net Cash Provided by Operating Activities 83 164 58 192 77 471 Cash Flows from Financing Activities: Proceeds from issuance of long-term debt 0 0 146 587 Proceeds from issuance of notes payable-parent company 9 600 17 800 0 Repayment of notes payable-parent company 0 0 (800) Repayment of long-term debt (including reacquisition premium) (3 375) (990) (136 090) Dividends paid to parent (36 412) (24 826) (25 708) Net Cash Used for Financing Activities (30 187) (8 016) (16 011) Cash Flows from Investing Activities: Construction expenditures capitalized (51 173) (52 639) (59 954) Decrease in construction payables (457) (633) (2 143) AFC-equity 445 671 694 Other (1 606) 2 037 (489) Net Cash Used for Investing Activities (52 791) (50 564) (61 892) Net Increase/(Decrease) in Cash 186 (388) (432) Cash at Beginning of Period 61 449 881 Cash at End of Period $ 247 $ 61 $ 449 Cash (used for) provided by changes in certain working capital items: Accounts receivable-net $(6 188) $ 770 $(1 597) Materials and supplies 3 442 (4 708) (453) Accounts payable and accrued liabilities 1 241 332 7 633 Payables to affiliated companies 4 475 (2 655) 127 Income and other taxes accrued 417 (4 174) (2 762) Other 3 895 867 (2 649) Net $ 7 282 $ (9 568) $ 299 Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $ 15 389 $ 15 870 $ 17 440 Income taxes (net of refunds received) $ 17 333 $ 18 773 $ 18 825 See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data Balance Sheets December 31 (Thousands of dollars) 1995 1994 Assets Utility Plant Electric-including construction work in progress: 1995, $12,640; 1994, $14,599 $ 864 514 $ 836 665 Gas 94 425 88 350 Other 63 758 54 675 Total 1 022 697 979 690 Accumulated provision for depreciation (370 634) (344 675) Net utility plant 652 063 635 015 Other Property and Investments Nonutility property - at cost 3 123 3 082 Accumulated provision for depreciation (334) (365) Other investments - at cost which approximates market 6 429 3 974 Total other property and investments 9 218 6 691 Current Assets Cash 247 61 Accounts receivable 43 988 37 484 Accumulated provision for uncollectible accounts (854) (538) Materials and supplies - at average cost Fuel 6 689 9 804 Other 5 561 5 889 Unbilled utility revenues 18 665 16 409 Prepayments and other 11 295 11 030 Deferred tax asset 0 1 415 Total current assets 85 591 81 554 Other Assets Unamortized debt expense 2 780 2 928 Regulatory assets 34 704 32 783 Federal Income tax receivable 3 307 3 307 Insurance receivable 0 3 091 Other 3 235 2 931 Total deferred debits 44 026 45 040 Total $ 790 898 $ 768 300 See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data December 31 (Thousands of dollars) 1995 1994 Liabilities and Equity Capitalization Common stock-authorized 870,000 shares of $100 par value; issued shares: 1995 and 1994, 862,000 $ 86 200 $ 86 200 Premium on common stock 10 461 10 461 Retained earnings 221 638 218 833 Total common equity 318 299 315 494 Long-term debt 213 235 213 700 Total capitalization 531 534 529 194 Current Liabilities Notes payable - parent company 50 900 41 300 Long-term debt due within one year 0 2 910 Accounts payable 14 884 14 415 Payables to affiliated companies (principally parent) 13 457 8 982 Salaries, wages, and vacation pay accrued 6 343 6 028 Federal income taxes accrued 4 111 0 Other taxes accrued 1 537 936 Interest accrued 5 300 5 485 Deferred tax liability 1 963 0 Capital lease obligations and other 3 767 1 463 Total current liabilities 102 262 81 519 Deferred Credits Accumulated deferred income taxes 100 227 99 748 Accumulated deferred investment tax credits 21 205 22 332 Regulatory liabilities 18 430 17 961 Customer advances 6 458 5 543 Benefit obligations and other 10 782 12 003 Total deferred credits 157 102 157 587 Commitments and Contingent Liabilities Total $ 790 898 $ 768 300 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 to the Company's financial position. Related Party Transactions All significant intercompany transactions and balances have been eliminated in consolidation except for intercompany and intersegment profits for 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), 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 3.48 percent in 1995, 3.45 percent in 1994, and 3.40 percent in 1993. 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 rates used for the FERC calculation were 6.20 percent in 1995, 7.55 percent in 1994, and 7.93 percent in 1993. The rates used for the PSCW calculation were 10.13 percent in 1995, 10.13 percent in 1994, and 10.84 percent in 1993. 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 Customers' meters are read and bills rendered on a cycle basis. The Company accrues the amount of estimated unbilled revenues for services provided from the monthly meter reading date to month-end. The current asset, unbilled utility revenues, is adjusted monthly, with a corresponding adjustment to revenues, to reflect estimated changes in unbilled revenues. 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 The Company records income taxes in accordance with SFAS No. 109 - Accounting For Income Taxes. SFAS No. 109 requires the use of the liability method whereby income taxes are deferred for 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 backed to the Company. Investment tax credits are deferred and 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 lease 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 are 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. When a single estimate of the liability cannot be determined, the low end of the estimated range is recorded. 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 Notes 5 and 8. Reclassifications Certain reclassifications have been made to the 1994 and 1993 financial statements to conform with the 1995 presentation. These reclassifications had no effect on net income or earnings per share. 2. Long-term Debt December 31 1995 1994 (Thousands of dollars) Long-term debt includes the following issues: First Mortgage Bonds - less reacquired bonds of $3,365 and $490 at December 31, 1995 and 1994, respectively: Series due: Apr. 1, 2021, 9-1/8% $ 44 635 $ 48 010 Mar. 1, 2023, 7 1/4% 110 000 110 000 Oct. 1, 2003, 5 3/4% 40 000 40 000 Total 194 635 198 010 Less April 1, 2021, 9 1/8% bonds redeemed in February 1995 (classified as current at December 31, 1994) 0 2 910 ________ ________ Net long-term portion of First Mortgage Bonds 194 635 195 100 City of LaCrosse Resource Recovery Revenue Bonds - Series due Nov. 1, 2011, 7 3/4% 18 600 18 600 Total long-term debt $213 235 $213 700 Except for minor exclusions, all real and personal property is subject to the lien of the Companys 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 $20.0 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 8.03% at December 31, 1995. 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 Companys balance sheets. The interest rate swaps serve 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, 1995, $1.8 million would have been payable by the Company while the present value of the fixed rate debt issued with the swaps was $3.1 million below par value. Fair Value of Debt The estimated fair value of the Companys long term debt (including debt due within one year classified as current) at December 31, 1995 and 1994 is $230.6 million and $196.2 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 in the next five years are approximately $1,061,000, $753,000, $442,000, $129,000, and $15,000, respectively, for the years 1996-2000. 3. Short-Term Borrowings The Company had bank lines of credit aggregating $1,000,000 at December 31, 1995. 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 1995 and 1994 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 $55.0 million. At December 31, 1995 and 1994, the Company had $50.9 million and $41.3 million, respectively, in short-term commercial paper borrowings outstanding. The weighted average interest rates on all short-term borrowings as of December 31, 1995, and December 31, 1994, were 6.2 percent and 5.0 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: 1995 1994 1993 (Thousands of dollars) Tax computed at statutory rate $ 22 140 $ 20 074 $ 21 387 Increases (decreases) in tax from: State income taxes, net of Federal income tax benefit 3 314 2 393 3 165 Investment tax credits recognized (936) (943) (948) Adjustment to taxes accrued in prior years 90 (2 430) 0 Other - net (567) (283) (506) Total income tax expense $ 24 041 $ 18 811 $ 23 098 Effective income tax rate 38.0% 32.8% 37.8% Income tax expense is comprised of the following: Included in income taxes: Current Federal tax expense $ 17 772 $ 8 075 $ 12 919 Current state tax expense 4 546 2 810 3 180 Deferred Federal tax expense 2 680 7 967 6 173 Deferred state tax expense 601 1 168 1 778 Deferred inv. tax credit adjustments (936) (943) (948) Total 24 663 19 077 23 103 Included in income deductions: Current Federal tax expense 691 1 039 875 Current state tax expense 129 216 (90) Deferred Federal tax expense (1 264) (1 008) (790) Deferred state tax expense (178) (513) 0 Total income tax expense $ 24 041 $ 18 811 $ 23 098 The components of the Company's net deferred tax liability at Dec. 31 (including current and noncurrent amounts) were as follows: (Thousands of dollars) 1995 1994 Deferred tax liabilities: Differences between book and tax bases of property $ 106 390 $ 98 526 Tax benefit transfer leases 3 369 4 950 Regulatory assets 12 498 11 626 Other 4 336 3 332 Total deferred tax liabilities 126 593 118 434 Deferred tax assets: Deferred investment tax credits 8 507 8 955 Regulatory liabilities 11 063 7 409 Deferred compensation, accrued vacation and other reserves not currently deductible 4 040 3 155 Other 794 582 Total deferred tax assets 24 404 20 101 Net deferred tax liability $ 102 189 $ 98 333 5. Pension Plans and Other Post Retirement Benefits 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. 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: 1995 1994 1993 (Thousands of dollars) Service cost - benefits earned during the period $ 2 844 $ 3 114 $ 2 845 Interest cost on projected benefit obligation 8 662 8 087 9 024 Actual return on allocated share of plan assets (10 994) (1 702) (18 724) Net amortization and deferral (1 567) (10 130) 8 091 Net periodic pension cost determined under SFAS No. 87 (1 055) (631) 1 236 Expenses recognized due to actions of regulators 90 90 90 Net periodic pension (benefit) cost recognized for ratemaking $ (965) $ (541) $ 1,326 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 funded status of the pension plan, including amounts allocable to the Company, as of December 31 is as follows: 1995 1994 Company Company Total Plan Portion Total Plan Portion Actuarial present value of benefit obligation: Vested $686 403 $ 87 877 $571 254 $ 74 387 Nonvested 155 177 17 901 120 420 14 538 Accumulated benefit obligation $841 580 $105 778 $691 674 $ 88 925 Projected benefit obligation $1 039 981 $127 287 $836 957 $104 302 Plan assets at fair value 1 456 530 145,963 1 165 584 141 964 Plan assets in excess of projected benefit obligation (416 549) (18 676) (328 627) (37 662) Unrecognized prior service cost (20 805) (2 602) (21 538) (2 735) Unrecognized net gain 452 699 23 842 370 289 44 006 Unrecognized net transitional asset 615 77 691 87 Net pension liability recorded $15 960 $ 2 641 $ 20 815 $ 3 696 The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7% in 1995 and 8% in 1994. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5% in 1995 and 1994. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 87 was 9% in 1995 and 8% in 1994 and 1993. Assumption changes decreased 1995 pension costs (determined under SFAS No. 87) by approximately $2.5 million. Assumption changes are expected to increase 1996 pension costs (determined under SFAS No. 87) by approximately $1.5 million. Postretirement Health Care The Company participates in the Minnesota Companys 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. Effective Jan. 1, 1993, the Company adopted the provisions of SFAS No. 106 - Employers' Accounting for Postretirement Benefits Other Than Pensions. SFAS No. 106 requires that the actuarially determined obligation for postretirement health care and death benefits is to be fully accrued by the date employees attain full eligibility for such benefits, which is generally when they reach retirement age. This is a significant change from the Company's pre-1993 policy of recognizing benefit costs on a cash basis after retirement. In conjunction with the adoption of SFAS No. 106, for financial reporting purposes, 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. This obligation considered 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity measures that were not in effect in 1993. 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, 1995, 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, at December 31. 1995 1994 (Thousands of Dollars) Total Company Total Company Plan Portion Plan Portion APBO: Retirees $145,763 $22 709 $132 223 $20 857 Fully eligible plan participants 24 133 3 235 21 522 2 617 Other active plan participants 116 810 14 872 79 374 9 978 Total APBO 286 706 40 816 233 119 33 452 Plan Assets at Fair Value 11 726 5 608 7 993 3 757 APBO in excess of plan assets 274 980 35 208 225 126 29 695 Unrecognized net actuarial gain (loss) (40 623) (7 925) 2 305 (1 824) Unrecognized transition obligation (183 260) (25 060) (194 040) (26 534) Postretirement benefit liability recorded $ 51 097 $ 2 223 $ 33 391 $ 1 337 The assumed health care cost trend rate used in measuring the APBO at Dec. 31, 1995 and 1994, respectively, were 10.4 and 11.0 percent for those under age 65 and 7.3 and 7.5 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 one percent increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31, 1995, by approximately 15 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 percent for Dec. 31, 1995, 8 percent for Dec. 31, 1994 and 7 percent for Dec. 31, 1993, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for all periods. Changes to actuarial assumptions had an immaterial effect on benefit costs incurred for 1994, decreased 1995 costs by $0.4 million, and will increase costs expected for 1996 by $0.4 million. The Company's share of net annual periodic postretirement benefit costs under the plan consists of the following components (thousands of dollars): 1995 1994 1993 Service cost-benefits earned during the year $ 686 $ 644 $ 579 Interest cost (on service cost and APBO) 2 761 2 251 2 360 Amortization of transition obligation 1 474 1 474 1 474 Return on assets and other (301) (182) (1) Net periodic postretirement health care costs $4 620 $4 187 $4 412 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 Companys 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 Companys matching contribution to the Plan was $0.5 million in 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 1995 1994 1993 (Thousands of dollars) Operating revenues: Electric $ 70 251 $ 73 503 $ 72 162 Gas 43 50 56 Operating expenses: Purchased and interchange power 173 743 174 144 162 510 Gas purchased for resale 205 227 267 Other operation 13 791 12 824 12 515 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 1995 1994 AFC recorded in plant on a net-of-tax basis Plant Lives* $ 9 918 $ 9 732 Losses on reacquired debt Term of Debt 9 749 10 303 Conservation and energy management programs Up to 10 years* 12 347 10 622 Pensions and other 3-15 years 1 406 2 126 Total Regulatory Assets $33 420 $32 783 Excess deferred income taxes collected from customers $ 1 449 $ 2 853 Investment tax credit deferrals 14 237 14 950 Fuel refunds and other 3 001 158 Total Regulatory Liabilities $18 687 $17 961 * Earns a return on investment in the ratemaking process. 8. Commitments and Contingent Liabilities Commitments The Company presently estimates capital expenditures will be $54 million in 1996 and $303 million for 1996-2000. Rentals under operating leases were approximately $1,644,000, $1,792,000, and $2,651,000, for 1995, 1994, and 1993, respectively. Fuel 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 1996 and 2013, require minimum contractual purchases and deliveries of fuel. In total, the Company is committed to the minimum purchase of approximately $256 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 Companys 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 Fund, a fund available from assessments by the Federal government in the event of nuclear incidents. The Minnesota Company is subject to an assessment of $79.3 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 On March 2, 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Company that it is a PRP at a creosote/coal tar contamination site in Ashland, Wisconsin. 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. On February 19, 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 a number of remediation options which 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 ongoing limited groundwater treatment, would cost approximately $6.0 million. Currently, the WDNR is conducting an investigation in Chequamegon Bay adjacent to Kreher Park to determine the extent of contamination in the bay. The WDNR has informed the Company that it will not choose or proceed with any remediation options on any portion of the Ashland site until the completion of the Chequamegon Bay investigation in the second half of 1996. Until more information is known concerning the extent of remediation required by the WDNR, the remediation method selected and the related costs, the various parties involved, and the extent of the Companys responsibility, if any, for sharing the costs, the ultimate cost to the Company and the expected timing of any payments related to the Ashland site is not determinable. At December 31, 1995, the Company had recorded an estimated liability of $900,000 for future remediation costs at this site and had incurred approximately $400,000 in actual expenditures. The Company potentially may be involved in the cleanup and remediation at a solid and hazardous waste landfill site in Eau Claire, Wisconsin. The Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in questions. 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 this matter at this time. 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 1995 1994 1993 (Thousands of dollars) Operating income before income taxes: Electric $ 72 317 $ 67 165 $ 73 012 Gas 8 243 6 498 4 897 Total operating income before income taxes $ 80 560 $ 73 663 $ 77 909 Depreciation and amortization: Electric $ 28 714 $ 26 836 $ 25 179 Gas 4 345 3 900 3 406 Total depreciation and amortization $ 33 059 $ 30 736 $ 28 585 Construction expenditures: Electric $ 42 843 $ 42 756 $ 49 692 Gas 8 330 9 883 10 262 Total construction expenditures $ 51 173 $ 52 639 $ 59 954 Identifiable assets: Electric utility $612 299 $596 798 $581 031 Gas utility 71 967 66 298 60 026 Total identifiable assets 684 266 663 096 641 057 Other corporate assets 106 632 105 204 95 922 Total assets $790 898 $768 300 $736 979 10. Summarized Quarterly Financial Data (Unaudited) Quarter Ended Mar. 31, Jun. 30, Sep. 30, Dec. 31, 1995 1995 1995 1995 (Thousands of dollars) Operating revenues $ 127 913 $ 102 246 $ 105 005 $ 123 618 Operating income $ 19 577 $ 9 240 $ 10 007 $ 17 074 Net income 15 160 $ 4 261 $ 6 047 $ 13 749 Quarter Ended Mar. 31, Jun. 30, Sep. 30, Dec. 31, 1994 1994 1994 1994 (Thousands of dollars) Operating revenues $ 134 004 $100 105 $ 101 100 $ 116 283 Operating income $ 22 268 $ 7 273 $ 9 416 $ 15 627 Net income $ 18 306 $ 3 441 $ 4 894 $ 11 904 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 99.02 and 99.03 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, 1995. The unaudited pro forma income statements give effect to the Transaction as if it had occurred on January 1, 1993. 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 99.02 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 99.03 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 99.03. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure During 1995 there were no disagreements with the Company's independent certified public accountants on accounting procedures or accounting and financial disclosures. As discussed in the Companys Current Report on Form 8-K filed December 19, 1994, on December 19, 1994 the Company's Board of Directors approved the appointment of the accounting firm of Price Waterhouse LLP as independent accountants for the Company beginning in fiscal year 1995, subject to ratification by the shareholder. On May 3, 1995, the Companys shareholder ratified the appointment of Price Waterhouse LLP as the Companys independent accountants for 1995. 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 year ended December 31, 1995. 22 Independent Auditors Report for the years ended December 31, 1994 and 1993. 23 Statements of Income and Retained Earnings for the three years ended December 31, 1995. 24 Statements of Cash Flows for the three years ended December 31, 1995. 25 Balance Sheets, December 31, 1995 and 1994. 26 Notes to Financial Statements. 28 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 States 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 Wisconsin 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) 10.01* Copy of MAPP Agreement, dated March 31, 1972 with amendments in 1994, between the local power suppliers in the North Central States area. (Exhibit 10.01 of Northern States Power Companys Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1- 3034.) 10.02* 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) 12.01 Unaudited Pro Forma Statements of Computation of Ratio of Earnings to Fixed Charges for Wisconsin Energy Company for the years ended December 31, 1991, 1992, 1993, 1994 and 1995. 16.01* Independent Auditors' Letter re: Change in Certifying Accountant (Exhibit 16.01 to Form 8-K dated December 19, 1994, File No. 10-3140). 27.01 Financial Data Schedule 99.01* Press Release, dated May 1, 1995, of NSP (Exhibit (99)- 01 to Form 8-K dated April 28, 1995, File No. 1-3034). 99.02 Unaudited Pro Forma Combined Condensed Balance Sheets for the year ended December 31, 1995 and unaudited Pro Forma Combined Condensed Statements of Income for the years ended December 31, 1993, 1994 and 1995 for Primergy Corporation. 99.03 Unaudited Pro Forma Combined Condensed Balance Sheets for the year ended December 31, 1995 and unaudited Pro Forma Combined Condensed Statements of Income for the years ended December 31, 1993, 1994 and 1995 for Wisconsin Energy Company. 99.04* 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, 1995, File No. 1-9057): 99.05* 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, 1995, File No. 1-3034): 99.06* 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, 1995, File No. 1-1245): (b) Reports on Form 8-K None 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. John A. Noer (Principal Executive Officer) M. N. Gregerson H. Lyman Bretting Vice President-Customer Services Director A. G. Schuster P. M. Gelatt Vice President Director Power Delivery and Generation Patrick D. Watkins Wayne E. Harrison Vice President-Corporate Services Director John P. Moore, Jr. Loren L. Taylor General Counsel and Secretary Director David E. Ripka Ray A. Larson, Jr. Controller Director (Principal Accounting Officer) Neal A. Siikarla Larry G. Schnack Treasurer Director (Principal Financial Officer) Exhibit 12.01 WISCONSIN ELECTRIC POWER COMPANY STATEMENT OF COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (Unaudited) (Thousands of Dollars) Year Ended December 31 1990 1991 1992 1993 1994 1995 Net Income $233 568 $231 034 $214 150 $230 086 $220 299 $279 885 Income Tax 122 571 122 946 113 731 124 225 120 665 165 975 Pretax Income 356 139 353 980 327 881 354 311 340 964 445 860 Fixed Charges: Interest on Long-Term Debt 95 989 96 794 103 100 105 987 103 685 103 113 Amortization of Debt Premium, Discount & Expense 3 095 3 325 5 571 15 613 15 136 13 420 Other Interest Expense 5 150 7 709 4 605 4 356 8 903 14 740 Interest Factor of Rents Nuclear Fuel 3 992 3 174 2 098 1 697 1 896 2 401 Other 787 935 1 054 1 528 1 070 1 070 Total Fixed Ch. 109 013 111 937 116 428 129 181 130 690 134 744 Earnings Before Income Taxes & Fixed Charges $465 152 $465 917 $444 309 $483 492 $471 654 $580 604 Ratio of Earnings to Fixed Charges 4.3% 4.2% 3.8% 3.7% 3.6% 4.3% Note: See accompanying notes to the Unaudited Pro Forma Financial Information for Wisconsin Energy Company under Item 14, at Exhibit 99.03 to the 1995 Form 10-K, incorporated herein by reference. Exhibit 99.02 UNAUDITED PRO FORMA FINANCIAL INFORMATION The following unaudited pro forma financial information adjusts 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, 1995 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 Dec. 31, 1995 give effect to the Transaction as if it had occurred at the beginning of the periods presented. 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 operating results or financial position. 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. Exhibit 99.02 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 Pro Forma Forma 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 Common Per Share using NSP Equivalent Shares $3.69 See accompanying notes to unaudited pro forma combined condensed financial statements. Exhibit 99.02 PRIMERGY CORPORATION UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME YEAR ENDED DECEMBER 31, 1994 (In thousands, except per share amounts) NSP WEC Pro forma Pro forma As Reported As Reported Adjust. 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 pro forma combined condensed financial statements. Exhibit 99.02 PRIMERGY CORPORATION UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME YEAR ENDED DECEMBER 31, 1993 (In thousands, except per share amounts) NSP WEC Pro Pro Forma Forma (As (As Adj. Combined Reported) Reported) Utility Operating Revenues Electric 1,974,916 1,347,844 - 3,322,760 Gas 429,076 331,301 - 760,377 Steam - 14,090 - 14,090 Total Operating Revenues 2,403,992 1,693,235 - 4,097,227 Utility Operating Expenses Electric Production-Fuel and Purchased Power 524,126 318,265 - 842,391 Cost of Gas Sold & Transported 282,036 214,132 - 496,168 Other Operation 516,560 399,135 - 915,695 Maintenance 161,413 156,085 - 317,498 Depreciation and Amortization 264,517 167,066 - 431,583 Taxes Other Than Income 223,108 74,653 - 297,761 Revitalization Charges - - - - Income Taxes 128,346 98,463 - 226,809 Total Operating Expenses 2,100,106 1,427,799 - 3,527,905 Utility Operating Income 303,886 265,436 - 569,322 Other Income (Expense) Equity Earnings of Unconsolidated Investees 3,030 - - 3,030 Other Income and Deductions-Net 12,916 32,073 - 44,989 Total Other Income(Expense) 15,946 32,073 - 48,019 Income before Interest Charges and Preferred Dividends 319,832 297,509 - 617,341 Interest Charges 108,092 102,997 - 211,089 Preferred Dividends of Subsidiaries 14,580 4,377 - 18,957 Net Income 197,160 190,135 - 387,295 Average Common Shares Outstanding (Note 1) 65,211 105,878 40,822 211,911 Earnings Per Common Share $ 3.02 $ 1.80 $ 1.83 NSP Equivalent Shares (Note 1) 65,211 105,878 (40,762) 130,327 Earnings Per Common Share using NSP Equivalent Shares $ 2.97 See accompanying notes to pro forma combined condensed financial statements. Exhibit 99.02 PRIMERGY CORPORATION UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEETS DECEMBER 31, 1995 (In thousands) NSP WEC Pro Pro Forma Forma Pro Forma Balance Sheet (As (As Combine Reporte Reporte Adjustm d d) d) ents ASSETS UTILITY PLANT Electric 6,553,383 4,608,120 - 11,161,503 Gas 710,035 491,176 1,201,211 Other 299,585 40,078 339,663 Total 7,563,003 5,139,374 12,702,377 Accumulated provision for depreciation (3,343,760)(2,288,080) - (5,631,840) Nuclear fuel - net 91,098 59,260 150,358 Net utility plant 4,310,341 2,910,554 7,220,895 CURRENT ASSETS Cash and cash equivalents 28,794 23,626 52,420 Accounts receivable - net 360,577 150,149 510,726 Accrued utility revenues 112,650 140,201 252,851 Fossil fuel inventories 43,941 83,366 127,307 Material & supplies inventories 100,607 70,347 170,954 Prepayments and other 57,894 63,830 121,724 Total current assets 704,463 531,519 1,235,982 OTHER ASSETS Regulatory Assets 374,212 309,280 683,492 External decommissioning fund 203,625 275,125 478,750 Investments in non-regulated projects and other investments 289,495 110,145 399,640 Non-regulated property - net 177,598 115,392 292,990 Intangible assets and other(Note4) 168,851 308,720 (140 844) 336,727 Total other assets 1,213,781 1,118,662 (140 844) 2,191,599 TOTAL ASSETS 6,228,585 4,560,735 (140,844)10,648,476 LIABILITIES AND EQUITY CAPITALIZATION Common stock equity: Common stock (Note 1) 170,440 1,108 (169,331) 2,217 Other stkhrs' equity(Note 1) 1,856,951 1,870,157 169,331 3,896,439 Total common stock equity 2,027,391 1,871,265 - 3,898,656 Cum. pref'd stock and premium 240,469 30,451 270,920 Long-term debt 1,542,286 1,367,644 2,909,930 Total capitalization 3,810,146 3,269,360 7,079,506 CURRENT LIABILITIES Current portion of long-term debt 167,360 51,854 219,214 Short-term debt 216,194 156,919 373,113 Accounts payable 246,051 108,508 354,559 Taxes accrued 202,777 20,072 222,849 Other accrued liabilities 158,991 98,753 257,744 Total current liabilities 991,373 436,106 1,427,479 OTHER LIABILITIES Deferred income taxes (Note 4) 841,153 483,410 (140 844) 1,183,719 Deferred investment tax credits 161,513 89,672 251,185 Regulatory liabilities 242,787 167,483 410,270 Other liab. & dfd cr. 181,613 114,704 296,317 Total other liabilities 1,427,066 855,269 (140 844) 2,141,491 TOTAL CAPITALIZATION AND LIABILITIES 6,228,585 4,560,735 (140,844) 10,648,476 See accompanying notes to unaudited pro forma combined condensed financial statements. Exhibit 99.02 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. 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. Cost savings resulting from the Merger Transaction are estimated to be approximately $2.0 billion over a 10-year period, net of transaction costs (including fees for financial advisors, attorneys, accountants, consultants, filings and printing) and costs to achieve the savings of approximately $30.0 million and $122.0 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. 5. Certain reclassifications have been made to the 1994 and 1993 NSP financial statements to conform with the 1995 presentation. These reclassifications had no effect on net income or earnings per share. Exhibit 99.03 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 WECs 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 Dec. 31, 1995 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 Dec. 31, 1995, 1994, and 1993, give effect to the Transaction as if it had occurred at Jan. 1, 1993. 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. 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 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. Exhibit 99.03 WISCONSIN ENERGY COMPANY * UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME 12 MONTHS ENDED DECEMBER 31, 1995 (In thousands) WE (As The Co. Pro Forma Pro Forma Reported) As Reported Adj. Combined Utility Operating Revenues Electric $1 437 480 $380 724 $1 818 204 Gas 318 262 78 058 396 320 Steam 14 742 14 742 Total Operating Revenues 1 770 484 458 782 2 229 266 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 33 059 216 935 Taxes other than income taxes 74 765 14 109 88 874 Income taxes 141 029 24 662 165 691 Total Operating Expenses 1 441 463 402 884 1 844 347 Utility Operating Income 329 021 55 898 384 919 Other Income (Expenses) 21 272 2 421 23 693 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 Dividend Stock Requirement 1 203 1 203 Earnings Available for Common Stockholder $ 239 465 $ 39 217 $ 278 682 See accompanying notes to unaudited pro forma combined condensed 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. Exhibit 99.03 WISCONSIN ENERGY COMPANY * UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME 12 MONTHS ENDED DECEMBER 31, 1994 (In thousands) WE The Comp. Pro Forma Pro Forma As Reported As Reported Adj. Combined Utility Operating Revenues Electric $1 403 562 $374 777 $1 778 339 Gas 324 349 76 715 401 064 Steam 14 281 14 281 Total Operating Revenues 1 742 192 451 492 2 193 684 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 30 736 208 350 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 1 478 919 396 908 1 875 827 Utility Operating Income 263 273 54 584 317 857 Other Income (Expenses) 25 334 1 535 26 869 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 Stock Requirement Preferred Dividend 1 351 1 351 Earnings Available for Common Stockholder $ 180 403 $38 545 $ 218 948 See accompanying notes to unaudited pro forma combined condensed financial statements. * In connection with the business combinations, WE will be renamed Wisconsin Energy Company. Exhibit 99.03 WISCONSIN ENERGY COMPANY * UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME 12 MONTHS ENDED DECEMBER 31, 1993 (In thousands) WE (As The Comp. Pro Forma Pro Forma Reported) As Reported Adj. Combined Utility Operating Revenues Electric $1 347 844 $362 473 $1 710 317 Gas 331 301 72 760 404 061 Steam 14 090 14 090 Total Operating Revenues 1 693 235 435 233 2 128 468 Utility Operating Expenses Electric production-fuel and purchased power 318 265 165 695 483 960 Cost of gas sold and transported 214 132 51 501 265 633 Other operation 399 135 76 749 475 884 Maintenance 156 085 21 703 177 788 Depreciation and amortization 167 066 28 585 195 651 Taxes other than income taxes 74 653 13 091 87 744 Income taxes 98 463 23 103 121 566 Total Operating Expenses 1 427 799 380 427 1 808 226 Utility Operating Income 265 436 54 806 320 242 Other Income (Expenses) 29 114 1 538 30 652 Income Before Interest Charges and Preferred Dividends 294 550 56 344 350 894 Interest Charges 102 470 18 338 120 808 Net Income 192 080 38 006 230 086 Preferred Dividend Stock Requirement 4 377 4 377 Earnings Available for Common Stockholder $ 187 703 $38 006 $ 225 709 See accompanying notes to unaudited pro forma combined condensed financial statements. * In connection with the business combinations, WE will be renamed Wisconsin Energy Company. Exhibit 99.03 NORTHERN STATES POWER COMPANY (WISCONSIN) UNAUDITED PRO FORMA CONDENSED BALANCE SHEET DECEMBER 31, 1995 (In thousands) The Comp. Pro Forma The Comp. As Reported Adj. As Adjusted (Note 2) Assets Utility Plant Electric $864 514 $864 514 Gas 94 425 (33 644) 60 781 Other 63 758 63 758 Total 1 022 697 (33 644) 989 053 Accumulated provision for depreciation (370 634) 15 215 (355 419) Nuclear fuel - net Net Utility Plant 652 063 (18 429) 633 634 Current Assets 85 591 16 836 102 427 Other Assets 53 244 (944) 52 300 Total Assets $790 898 $(2 537) $788 361 Liabilities and Equity Capitalization Common stock equity $318 299 $318 299 Cumulative preferred stock and premium Long-term debt 213 235 213 235 Total Capitalization 531 534 531 534 Current Liabilities Current portion of long-term debt Short-term debt 50 900 50 900 Other 51 362 (38) 51 324 Total Current Liabilities 102 262 (38) 102 224 Other Liabilities 157 102 (2 499) 154 603 Total Capitalization and Liabilities $790 898 $(2 537) $788 361 See accompanying notes to unaudited pro forma combined condensed financial statements. Exhibit 99.03 WISCONSIN ENERGY COMPANY * UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET DECEMBER 31, 1995 (In thousands) (See Page 48) (Note 3) Assets Utility Plant Electric $4 608 120 $864 514 $5 472 634 Gas 491 176 60 781 551 957 Other 40 078 63 758 103 836 Total 5 139 374 989 053 6 128 427 Accumulated provision for depreciation (2 288 080) (355 419) (2 643 499) Nuclear fuel - net 59 260 59 260 Net Utility Plant 2 910 554 633 634 3 544 188 Current Assets 517 724 102 427 620 151 Other Assets 890 646 52 300 (136 581) 806 365 Total Assets $4 318 924 $788 361 $(136 581) $4 970 704 Liabilities and Equity Capitalization Common stock equity $1 696 565 $318 299 $2 014 864 Cumulative preferred stock and premium 30 451 30 451 Long-term debt 1 325 169 213 235 1 538 404 Total Capitalization 3 052 185 531 534 3 583 719 Current Liabilities Current portion of long-term debt 51 419 51 419 Short-term debt 150 694 50 900 201 594 Other 222 571 51 324 273 895 Total Current Liabilities 424 684 102 224 526 908 Other Liabilities 842 055 154 603 (136 581) 860 077 Total Capitalization and Liabilities $4 318 924 $788 361 $(136 581) $4 970 704 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 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 NSP-WI, currently a wholly owned subsidiary of NSP, into Wisconsin Energy Company. Prior to 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 Companys Unaudited Pro Forma Condensed Balance Sheet at December 31, 1995 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, 1995, 1994 and 1993 were $28,897,000, $26,779,000 and $28,028,000, 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, 1995 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 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. 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, 1995 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 29, 1996 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 4 Construction Authorization in Wisconsin 5 Ratemaking Principles in Wisconsin 5 Fuel and Purchased Gas Adjustment Clauses 5 Rate Matters by Jurisdiction 6 Electric Transmission Tariffs and Settlement (FERC) 7 ELECTRIC OPERATIONS Competition 9 NSP System 10 Capability and Demand 11 Demand Side Management 11 Interchange Agreement 12 Electric Power Pooling Agreements 12 Fuel Supply 12 Electric Operating Statistics 13 GAS OPERATIONS 13 ENVIRONMENTAL MATTERS 15 CONSTRUCTION AND FINANCING 17 EMPLOYEES AND EMPLOYEE BENEFITS 17 Item 2 Properties 18 Item 3 Legal Proceedings 19 Item 4 Submission of Matters to a Vote of Security Holders 19 PART II Item 5 Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters 20 Item 6 Selected Financial Data 20 Item 7 Management's Discussion and Analysis 20 Item 8 Financial Statements and Supplementary Data 22 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 38 PART III Item 10 Directors and Executive Officers of the Registrant 39 Item 11 Executive Compensation 39 Item 12 Security Ownership of Certain Beneficial Owners and Management 39 Item 13 Certain Relationships and Related Transactions 39 PART IV Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 40 SIGNATURES . . . . . 43 EXHIBITS (EXCERPT) Unaudited Pro Forma Financial Information 44 -----END PRIVACY-ENHANCED MESSAGE-----