-----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, TcMQpwvqOpGxsTuXceQ4L1iQLGp5K1wY4+5TcciruvYniQVpS/v5DA0amuj07yGu YcT4XjDDg5Ph2z0+49V7Ww== 0000072909-98-000004.txt : 19980331 0000072909-98-000004.hdr.sgml : 19980331 ACCESSION NUMBER: 0000072909-98-000004 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980330 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO /WI/ CENTRAL INDEX KEY: 0000072909 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 390508315 STATE OF INCORPORATION: WI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-03140 FILM NUMBER: 98579131 BUSINESS ADDRESS: STREET 1: 100 N BARSTOW ST CITY: EAU CLAIRE STATE: WI ZIP: 54702 BUSINESS PHONE: 7158392592 MAIL ADDRESS: STREET 1: P O BOX 8 CITY: EAU CLAIRE STATE: WI ZIP: 54702-008 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) X Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (fee required) or Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (no fee required) For the fiscal year ended December 31, 1997 Commission file number: 10-3140 Northern States Power Company, a Wisconsin corporation, meets the conditions set forth in general instruction I (1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format. (In general instruction I(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) 839-2416 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No . Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date. Class Outstanding at March 24, 1998 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 REGULATION AND RATES Utility Industry Restructuring Status 1 Construction Authorization 2 Ratemaking Principles in Wisconsin and Michigan 3 Fuel and Purchased Gas Adjustment Clauses 3 Rate Matters by Jurisdiction 4 ELECTRIC OPERATIONS Competition 6 NSP System 7 Capability and Demand 8 Demand Side Management 8 Interchange Agreement 9 Electric Power Pooling Agreements 9 Fuel Supply 9 Electric Operating Statistics 10 GAS OPERATIONS 10 ENVIRONMENTAL MATTERS 12 CONSTRUCTION AND FINANCING 13 EMPLOYEES AND EMPLOYEE BENEFITS 14 Item 2 Properties 15 Item 3 Legal Proceedings 16 Item 4 Submission of Matters to a Vote of Security Holders 16 PART II Item 5 Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters 17 Item 6 Selected Financial Data 17 Item 7 Management's Discussion and Analysis 18 Item 8 Financial Statements and Supplementary Data 19 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 34 PART III Item 10 Directors and Executive Officers of the Registrant 35 Item 11 Executive Compensation 35 Item 12 Security Ownership of Certain Beneficial Owners and Management 35 Item 13 Certain Relationships and Related Transactions 35 PART IV Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 36 SIGNATURES. . 38 EXHIBITS (EXCERPT) Statement pursuant to Private Securities Litigation Reform Act of 1995 39 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, Wis. 54703 (Phone: (715) 839-2416). The Company is a wholly-owned subsidiary of Northern States Power Company, a Minnesota corporation (the Minnesota Company or NSPM). NSPM and its subsidiaries collectively are referred to herein as NSP. The Company is engaged in the generation, transmission, and distribution of electricity to approximately 206,700 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 ten wholesale customers in the same general area. The Company is also engaged in the distribution and sale of natural gas in the same service territory to approximately 72,100 customers in Wisconsin and 4,900 customers in Michigan. In 1997, the Company derived 81 percent of its total operating revenues from electric utility operations and 19 percent from gas utility operations. As of Dec. 31, 1997, the Company had 873 full-time equivalent employees including 761 full-time employees. As discussed in the Form 8-K filed on May 19, 1997, NSPM and Wisconsin Energy Corporation (WEC) announced on May 16, 1997 that they mutually agreed to terminate the proposed merger of the two companies. As a result, the Company expensed approximately $900,000 of accumulated merger-related costs during the second quarter of 1997. Except for the historical information contained herein, the matters discussed in this Form 10-K are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including their impact on capital expenditures; business conditions in the energy industry; competitive factors; unusual weather; changes in federal or state legislation; and the other risk factors listed from time to time by the Company in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this report on Form 10-K. REGULATION AND RATES Utility Industry Restructuring Status Some states have begun to allow retail customers to choose their electricity supplier, and many other states are considering retail access proposals. NSP believes that retail competition will result in more innovative services and lower prices to all customers if the transition is managed in a thoughtful manner. NSP supports fair and equal treatment for all competitors, recovery of utilities' investments made under traditional regulation and a reduction of personal property taxes for NSPM. NSP supports a plan that would take two or three years to resolve these issues and develop infrastructure, and another two or three years to phase in customers' choice. In 1996, the Public Service Commission of Wisconsin (PSCW) issued its report to the legislature on restructuring the electric industry. The report included a 32-step work plan to achieve specified elements with the ultimate goal of opening a retail market to competition by the year 2001. Work began on twelve of the 32 steps in 1996. Some of these were completed, some continue to be worked on and some were rescheduled to begin in 1997. After receiving comments on the restructuring work plan in July 1997, the PSCW consolidated the 32-step work plan into a 7-step work plan. However, due to the summer of 1997's electrical reliability concerns in eastern Wisconsin, the PSCW indicated that industry restructuring efforts should be subordinate to, and compatible with, reliable electric supply. The PSCW maintains that the development of a strong Independent System Operator (ISO) remains of primary importance to retail competition. As a result of the reliability issue in 1997, the PSCW will focus on the development of a utility infrastructure necessary to assure reliable electric service and the removal of barriers to competition at the wholesale level first. In late 1997, the PSCW stated that although many parties have concluded that retail competition is a foregone conclusion, the PSCW never indicated that retail competition was inevitable, nor that it was in the public interest. At present, a definite timeline has not yet been established for the implementation of retail competition. In March 1998 the Governor of Wisconsin (Governor) proposed reliability legislation that, if enacted, will make dramatic changes in the state's energy industry and take a number of steps toward industry restructuring. This proposal will streamline the state's regulatory process and authorize some form of a merchant plant market. This proposal will also require, prior to June 30, 2000, transmission system owners to either transfer control of transmission system assets to an ISO or divest of assets to an independent transmission owning entity. NSP cannot predict the final contents of any such legislation or ultimate impact on NSP. In restructuring the natural gas industry, the PSCW reviewed four proposed models. The chosen model included deregulation of the gas purchasing and transportation functions by market segment as competition becomes effective and sustainable. The PSCW then separated restructuring into three phases. In Phase I, the PSCW found it necessary to completely separate the gas purchasing activities associated with providing regulated services from those associated with providing unregulated services and to develop standards of conduct to apply to opportunity gas sales and utilities' relationships with their affiliates. The focus of Phase II was to develop Standards of Conduct (SOC) intended to ensure that interested market participants have the opportunity to purchase released pipeline capacity and gas supply, and that the releasing utility receives the best price for the sale. In situations in which a gas utility has a gas marketing affiliate, additional restrictions between the utility and its affiliate are necessary to ensure fair treatment of all market participants and to prevent cross-subsidization. Phase III focused on three main issues: (1) identifying regulatory or structural barriers that may prohibit competition; (2) identifying standards to determine the level of competitiveness of the market and the level of necessary regulation and; (3) identifying conditions to impose on marketers serving formerly regulated markets. In this phase, it was also decided that gas marketers should be registered or certified and that consumer protection and customer service policy issues must be addressed before any markets are deregulated. The PSCW then ordered the formation of six work groups to address the following: Capacity Policy, Market Registration/Certification, Legislation, End-Use Price Reporting, Market-Based Pricing for Large Volume Customers, and Consumer Protection and Essential Services. These groups will continue to meet over the coming years to address the various issues. On Jan. 14, 1998 the Michigan Public Service Commission (MPSC) issued an order regarding electric retail competition. The MPSC concluded that all customers who want to participate in open access should have the opportunity to do so and that those customers who do not participate should not pay higher rates because of open access. The order directed the large Michigan utilities to make 2 1/2 percent of their electric load eligible for open access in each year from 1997 through 2001. All remaining Michigan electric customers would be given access in 2002. It also stated that the phase-in schedule applied to all customer classes, that a bidding process would be used to allocate the open access capacity, that loads of less than one megawatt (Mw) would be allowed to participate through an aggregator, and that prudently incurred stranded costs would be recovered. That plan was unsuccessfully challenged by the affected Michigan utilities, and the courts upheld the MPSC's authority to implement retail competition. The Company, along with the other smaller Michigan utilities, is in the process of proposing a delayed open access timeline for its customers. The timing of regulatory actions regarding electric and gas restructuring and their impact on the Company and the industry cannot be predicted at this time and may be significant. Construction Authorization Prior to the construction of a major electric project, the Company is required to obtain various licenses and permits, including either a certificate of authority (CA) or a certificate of public convenience and necessity (CPCN), from the PSCW. In 1996, the minimum project expenditure requiring a CA rose generally from $3 million to $3.3 million. Any transmission projects involving equipment with a capacity less than 100 Kilovolts (Kv), costing less than $3.3 million, and less than 10 miles in length, may no longer be subject to the full PSCW approval process. A proposal to increase this limit to $5 million is pending before the PSCW. Before a major electric generation or transmission 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 plant construction plans are reviewed. The Company filed an Advance Plan most recently in early 1998, and the PSCW's decision is expected in mid 1998. In eastern Wisconsin, which is not served by the Company, the compound effect of simultaneous generating facility outages and a transmission system already near capacity raised the possibility of rolling blackouts and system instability in that area during 1997. The PSCW and the Governor's office are studying proposed amending requirements for new electric generation and transmission facilities to promote the production and movement of more electricity to the state. Ratemaking Principles in Wisconsin and Michigan The PSCW and MPSC regulate the rates and service of the Company with respect to retail sales within the State of Wisconsin and the State of Michigan, respectively, and various other aspects of the Company's operations. The PSCW also exercises jurisdiction over the construction of certain electric and gas facilities and the issuance of new securities. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) with respect to its sales to wholesale electric customers and certain other aspects of its operations, including the licensing and operation of hydro projects and the Company's Interchange Agreement (see Electric Operations-Interchange Agreement). Approximately 92.7 percent of the Company's 1997 revenues from sales were subject to PSCW jurisdiction. Of the 92.7 percent, 71.6 percent was generated from electric retail revenues and the remaining 21.1 percent from retail gas revenues. The Company's wholesale revenues from sales subject to FERC jurisdiction were approximately 3.9 percent of the Company's 1997 revenues from sales with the remaining 3.4 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 deviated from this biennial filing requirement while the proposed merger of NSP and WEC was pending. 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 current return on CWIP or capitalization of Allowance for Funds Used During Construction (AFC) at the adjusted overall cost of capital. The Company currently capitalizes AFC on production and transmission CWIP at the FERC formula rate and on all other CWIP at the adjusted overall cost of capital. Fuel and Purchased Gas Adjustment Clauses Wisconsin The Wisconsin automatic retail electric fuel adjustment clause was eliminated for the Company in the electric retail rate order issued by the PSCW in 1986. The electric fuel adjustment clause was replaced by a procedure which compares actual monthly and anticipated annual fuel costs with those costs which were included in the latest retail electric rates approved by the PSCW. If the comparison results in a difference outside a range of eight percent for the first month, five percent for the second month, or two percent for the remainder of the year, the PSCW may hold hearings limited to fuel costs and revise rates. This is subject to two year approval under the biennial rate case process. Effective Jan. 1, 1996, the fuel costs that are monitored include demand costs for sales, purchased power costs, and transmission wheeling expenses, which had been excluded prior to that date. On June 9, 1997 the Company filed for an interim fuel cost surcharge to its retail electric rates under the fuel rules provisions of the Wisconsin Statutes. The surcharge was requested because fuel and purchased power costs had risen beyond the amount included in the Company's current rates due to unplanned and extended outages at NSPM's nuclear generating stations and higher than projected costs to transmit electricity purchased from other utilities to the Company's service territory. Effective Sept. 25, 1997 the PSCW authorized the Company to increase rates through a fuel cost surcharge of $0.00043 per Kilowatt-hour (Kwh) to all Wisconsin retail electric customers, which produced approximately $574,000 of additional electric revenue in 1997. The surcharge represents less than one percent of current rates and is the first rate increase implemented since January 1993. The surcharge will continue in effect on an interim basis until the next rate order is issued and is subject to refund pending final PSCW review. Gas rate schedules include a purchased gas adjustment (PGA) clause that provides for rate adjustments to compensate for any difference between the current price of purchased gas and the price of purchased gas already included in rates. The current month's factor is based on the estimated purchased gas costs for that month. In March 1996, the PSCW conducted a generic hearing to consider alternative incentive-based gas cost recovery mechanisms to replace the current purchased gas adjustment clause (PGA). In November 1996, the PSCW issued an order with general guidelines for incentive-based gas cost recovery mechanisms as well as "modified one-for-one" gas cost recovery mechanisms. All major gas utilities in Wisconsin were required to file a proposal to replace their current PGA. On Sept. 29, 1997 the Company filed its proposal with the PSCW. In the Company's proposal, allowable gas commodity cost recovery would be based on a benchmark index which is, in turn, based on the market price of gas. The allowable cost recovery of the remaining components of the cost of gas (for example, fixed pipeline transportation costs, supply reservation costs, and other costs approved by the FERC) would be based on actual costs incurred, as is the case with the Company's current PGA. The PSCW's decision is expected in June 1998. If the Company's proposal is approved, the financial impact of the new gas cost recovery mechanism will be substantially the same as with the current PGA. Approximately 70 percent of the Company's gas revenues represent recovery of gas costs through the PGA mechanism. 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-recoveries are refunded and any under-recoveries are collected, including interest. On Aug. 25, 1997, the MPSC approved the Company's application to reinstate a Power Supply Cost Recovery (PSCR) factor for Michigan electric customers in 1998. On Sept. 29, 1997, the Company filed its request for a 1998 PSCR factor of $.00172 per Kwh which would produce about $250,000 of additional revenue in 1998. The Company had suspended the PSCR during 1997 while the merger between NSPM and WEC was pending. The PSCR provides for recovery of the cost of fuel for electric generating plants and for purchased electricity. Wholesale For the eight wholesale customers on the W-1 wholesale rate, the Company calculates the fuel adjustment factor for the current month based on estimated electric fuel costs for that month. The fuel adjustment factor is adjusted for over- or under- collected fuel costs allocable to wholesale customer sales from the prior month's actual operations which provide an ongoing true-up mechanism. The remaining two wholesale customers have fixed rate contracts which do not have a fuel adjustment factor. Rate Matters by Jurisdiction Wisconsin The Company filed retail electric and gas rate cases with the PSCW on Nov. 14, 1997 for the test year 1998. The Company requested a 4.3 percent increase, approximately $12.7 million annually, in retail electric rates and a 1.9 percent or $1.7 million decrease in retail gas rates. The Company has requested that these changes take effect during the second quarter of 1998. Network Transmission Service (NTS) is a form of transmission service that was created under FERC Order No. 888 (as discussed later). Under NTS, NSP and other participating utilities share the net cost of operating and maintaining the regional transmission network that NSP uses based on each participants' share of the network load. The additional cost of participating in this regional network had not been included in the Company's 1997 Wisconsin rates. In July 1997 the Company received authorization from the PSCW to defer NTS costs related to Wisconsin retail electric customers that were incurred after the May 23, 1997 request, subject to review by the PSCW. Through Dec. 31, 1997, $1.7 million of NTS costs had been deferred. Recovery of deferred NTS costs has been sought in the Company's 1998 Wisconsin retail electric rate case. In its order regarding the Company's 1997 rates, the PSCW denied current rate recovery of the federal government's assessment for the decommissioning and decontamination of federal uranium enrichment facilities based on a court decision involving another utility that these assessments were unlawful. However, the PSCW did state that they would allow future rate recovery of these costs with interest if the courts ultimately decided the assessments must be paid. The Company continued to pay the assessments and has deferred $564,000 as of Dec. 31, 1997 as a regulatory asset. On May 6, 1997, the United States Court of Appeals reversed the lower court's earlier decision that these assessments were unlawful. Accordingly, the Company has requested recovery of current and deferred assessments in its 1998 retail electric rate filing. On Dec. 31, 1997, the Company requested permission to implement an amortization method of asset recovery for certain qualifying equipment classified as General Plant. The method being proposed was generically approved by the PSCW on Dec. 19, 1989. Historically, the Company has adhered to the concept of retirement units and has maintained an individual Continuing Property Record (CPR) for all such equipment. The proposed method does not require unitization nor the recording of individual items of property in the CPR. It allows for recording of the total cost of the capital equipment acquired in a year as a vintaged group. The current list of units of property will be maintained. Capital versus expense determinations for the qualifying equipment will remain unchanged. The Company would adopt amortization periods within the range certified by the PSCW. Application of the certified amortization periods as proposed by the Company would result in an annual increase in depreciation expense of approximately $400,000 based upon estimated property balances for 1998. The increase in depreciation has been included in the 1998 Wisconsin retail rate filing. Michigan There were no changes in the Michigan Electric or Gas base rates during 1997. The Company is currently assessing its need to file for a change in rates during 1998. FERC-Gas The Company's Eau Claire Liquefied Natural Gas (LNG) `peak shaving' plant stores LNG that can be used to supplement the Company's natural gas supply during periods of high demand. In the past this plant was also used to supplement the gas supply of other utilities and, as a result, was subject to FERC jurisdiction. Since the Company no longer provides this service to other utilities, it filed an application with the FERC to abandon its jurisdiction over the Eau Claire LNG plant, which would leave the PSCW with sole jurisdiction. In June 1997 the FERC dismissed the filing in its entirety. In late October 1997, the FERC voted to grant (in part) the Company's request for a rehearing of the filings seeking abandonment of the FERC's jurisdiction over the Eau Claire LNG plant. In September 1997, the FERC ruled that Kansas gas producers must refund improperly collected Kansas ad valorem tax collected from 1982 to 1988 plus interest to its customers. During this period, Northern Natural Gas (NNG) had bought gas from Kansas producers and resold it to the Company under terms that require NNG to pass any refund from the producer back to the Company. In December 1997 NNG received one $30 million refund and, in turn, refunded $538,000 to the Company. However, the Kansas producers are appealing the FERC order and are also pursuing federal legislation to overturn the FERC order. In February 1998, the FERC ruled that the Kansas producers could place disputed refunds in escrow and that pipelines such as NNG could recollect refunded amounts if final refunds are less than those already paid. In July 1997, NSP and thirteen other parties appealed a July 1995 FERC order regarding rate treatment of a Great Lakes Gas Transmission Company (GLGT) expansion project. GLGT transports natural gas for the Company. In the early 1990's GLGT completed two expansion projects which did not improve service to the Company but which quadrupled the `rate base' (which is GLGT's investment in facilities - and a factor in calculating the rate the Company pays GLGT for transmitting gas). The FERC's July 1995 order allowed GLGT to increase its rates to recover the cost of these expansion projects which increased the Company's transport costs on GLGT's system by 61 percent annually, and to add surcharges for services received since November 1991. The Company and other parties to the appeal requested that the cost of the expansion projects be recovered only from customers who benefit from them and not from all GLGT customers. In January 1998, the District of Columbia Court of Appeals ruled that the July 1995 FERC order was lawful. The additional transportation costs have been recovered through the Purchased Gas Adjustment clause to the Company's rates, so there was no impact on the Company's earnings. In February 1997, the FERC issued its order on remand in the appeals of FERC Order No. 636 (restructuring interstate natural gas pipeline rates and services). The decisions most significant to the Company are that the FERC affirmed its decision to allow 100 percent recovery of a pipeline's prudently incurred stranded costs created by restructuring and that existing shippers need only agree to a five year contract extension to obtain a right of first refusal on continued access to the shipper's expiring capacity. Originally, the FERC required a 20 year commitment. FERC-Electric In response to changes in the wholesale electric market, the Company is providing discounts and negotiated services to be competitive. Due to these changes, 1997 revenues decreased from 1996 by $0.8 million. All ten municipal wholesale customers have current power supply arrangements under which they will purchase the majority of their power supply requirements from the Company. In 1996 the FERC issued Orders No. 888 and 889, which have had a significant impact on wholesale electric markets by giving competitors the ability to transmit electricity through utilities' transmission systems. Order No. 888 granted nondiscriminatory access to transmission service. Order No. 889 ensures a fair market by imposing standards of conduct on transmission system owners, by requiring separation of the power supply function from the transmission system operation function and by mandating the posting of transmission availability and pricing information on an electronic bulletin board. In 1997, the FERC issued orders clarifying Orders No. 888 and 889 in response to rehearing requests from market participants. These clarifying orders are currently being appealed in federal court. NSP has made the necessary filings with the FERC and believes it is taking the proper steps to comply with the new rules as they become effective. On Feb. 17, 1998 NSP filed a rate application with the FERC to update its rates for point-to-point transmission service. As filed, the proposed rates increase annual transmission revenues by approximately $4 million. The FERC's Order No. 888 requires utilities to offer, among other services, NTS to qualifying customers. Under NTS, NSP and other qualifying regional utilities share the total annual costs of operating and maintaining the regional transmission network which NSP uses, net of related network revenues, based on each company's share of the total network load. Each FERC regulated utility files a transmission tariff containing cost information that is used as the basis for NTS rates. NSP reviewed the information from other participating utilities and commenced negotiations with them regarding the final amount to be paid by NSP for participating in NTS for 1997. NSP has recorded a liability for what management believes is a reasonable estimate of the net cost of participating in NTS for 1997. On March 2, 1998, NSP filed with the FERC a revision to update its NTS costs to match those in the February 17 filing for point-to point transmission service. This filing is expected to support reductions in NSP's NTS costs. Both of these tariff changes are subject to FERC approval. The approval process is lengthy but interim rates could be in effect as early as May 1, 1998. As discussed previously, the PSCW has approved the regulatory deferral of the share of NSP's NTS costs which apply to Wisconsin retail electric customers, effective in 1997. ELECTRIC OPERATIONS The Company's electric production and transmission systems are interconnected with the production and transmission system of NSPM. The combined electric production and transmission systems of the Company and NSPM are hereinafter called the "NSP System". Competition The Company's electric sales are subject to competition in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, other private utilities and independent power producers. Electric service also increasingly competes with other forms of energy. The degree of competition may vary from time to time, depending on relative costs and supplies of other forms of energy. Although the Company cannot predict the extent to which its future business may be affected by supply, relative cost or promotion of other electricity or energy suppliers, the Company believes that it will be in a position to compete effectively. In October 1992, President Bush signed into law the Energy Policy Act of 1992 (Energy Act). The Energy Act amends the Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act. Among many other provisions, the Energy Act is designed to promote competition in the development of wholesale power generation in the electric utility industry. It exempts a new class of independent power producers from regulation under the PUHCA. The Energy Act also allows the FERC to order wholesale "wheeling" by public utilities to provide utility and non-utility generators access to public utility transmission facilities. The provision allows the FERC to set prices for wheeling, which will allow utilities to recover certain costs. The costs would be recovered from the companies receiving the services, rather than the utilities' retail customers. The market-based power agreement filings with FERC and the open access orders issued by FERC (as discussed in "Regulation and Rates," herein) reflect the trend toward increasing transmission access under the Energy Act. The Energy Act is a catalyst for comprehensive and significant changes in the operation of electric utilities, including increased competition. The Act's reform of the PUHCA promotes creation of wholesale non-utility power generators and authorizes the FERC to require utilities to provide wholesale transmission services to third parties. The legislation allows utilities and nonregulated companies to build, own and operate power plants nationally and internationally without being subject to restrictions that previously applied to utilities under the PUHCA. Management believes this legislation will increase competition in the electric energy markets. NSP plans to be a competitively priced supplier of electricity and an active participant in the competitive market for electricity. The NSP System is experiencing a continuing increase in the number of requests for the use of its transmission facilities as power marketers continue to enter the electric industry. In 1997, NSP filed 61 transmission service agreements for FERC approval. Also, as of Dec. 31, 1997, 73 customers, including NSP's own Energy Marketing area and other independent power brokers, were registered to buy transmission service from NSP. Many states are currently considering proposals to increase competition in the supply of electricity. The Company believes the transition to a more competitive electric industry will be beneficial for all consumers. It is likely that retail competition will provide more innovative services and lower prices. The Company supports an orderly transition to an open, fair and efficient competitive energy market for all customers and suppliers. As discussed previously in "Regulation and Rates," regulators in Wisconsin and Michigan are currently considering what actions they should take regarding electric industry competition, including restructuring. The Company believes that, under such restructuring plans, utilities should retain direct operational responsibility of their transmission and distribution systems, and that utilities should be permitted to recover the cost of their investments made under traditional regulation, including any "stranded costs." The timing of regulatory actions regarding restructuring and their impact on the Company cannot be predicted at this time and may be significant. NSP System The NSP System includes coal, natural gas, waste wood, refuse derived fuel (RDF) and nuclear steam generating plants, gas and oil fired combustion turbines, hydroelectric 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. NSPM operates two nuclear generating plants: the single unit, 539 Mw Monticello Nuclear Generating Plant and the Prairie Island Nuclear Generating Plant with two units having a total capacity of 1,025 Mw. The Monticello Plant received its 40-year operating license from the Nuclear Regulatory Commission (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 Monticello plant has sufficient temporary storage for used fuel to operate until 2010. With the additional on-site dry cask fuel storage facilities approved by the Minnesota Legislature in 1994, the Prairie Island plant is expected to have sufficient temporary storage capacity to operate until 2007. NSPM has contracted with the U.S. Department of Energy (DOE) for the disposal of used nuclear fuel. The DOE charges a quarterly disposal fee based on nuclear electric generation sold. While the DOE has contracted to begin accepting used nuclear fuel in 1998, it has indicated it may not actually be ready until after 2010. Consequently, NSPM may have to rely on on-site or contracted off-site facilities for storage of used fuel to continue operations of its nuclear plants until a DOE disposal or storage facility is ready. (See related legal proceedings under Item 3 - Legal Proceedings, herein.) Capability and Demand The Company's record peak demand occurred on July 17, 1997, and was 1,093 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 Mid American Power Pool (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). The Company primarily relies on plants operated by NSPM for base load generation. Approximately 80 percent of the total Kwh requirements of the Company were provided by NSPM generating facilities or purchases made by NSPM for system use in the year 1997. The Company has two steam generating facilities. One is the Bay Front Generating Plant which is located in Ashland, Wis. The plant is fueled primarily by natural gas, coal and wood residue. Recent modifications to the facility allow for more effective utilization of additional waste wood fuel supplies and have extended the useful life of the facility approximately 20 years from their completion in 1992. In 1992 the Company received authorization from the Wisconsin Department of Natural Resources (WDNR) to also burn tire derived fuel at the Ashland plant on a regular basis. The Company's second steam generating plant is the French Island plant located in La Crosse, Wis., which has two fluidized bed boilers modified to burn 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. Most of the Company's thermal generating capacity is with combustion turbine units that are called into service during periods of high demand for electricity, or "peaking plants". The 6 unit, 443 Mw Wheaton plant is located near Eau Claire, Wis. During the third quarter of 1997, the Company converted units 2 and 4 of the Wheaton generating facility to operate on both oil and natural gas. Previously, the units operated on oil exclusively. The conversion, which cost approximately $3 million, will decrease the cost of producing electricity and reduce plant emissions. There are also two combustion turbines at the French Island plant which have a combined capability of 192 Mw, and one 17 Mw unit at Park Falls, Wis. The Company also has 19 hydro plants with a projected capability of 249 Mw. 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, incentive programs, and rate incentive programs. In management's opinion, these programs respond to customer needs and focus on increasing the value of service that will, over the long term, reduce the company's capital requirements and help its customer base become more stable, energy efficient and competitive. During 1997, the Company's programs accomplished approximately 21 Mw of system peak demand reduction in the commercial, industrial and agricultural customer sectors and over 2.2 Mw in the residential sector. These impacts were obtained through appliance, lighting, motor, and cooling efficiency and process improvements, peak curtailable and time-of-use rate applications and direct load control of water heaters and air conditioners. Since 1986, the Company's retail DSM programs have achieved 219 Mw of summer peak demand reduction, exceeding the Company's goal of reducing summer peak demand by 200 Mw by the end of 1997. This is equivalent to almost 20 percent of the Company's 1997 summer peak demand. The Company continues to focus on improving the cost-effectiveness of its DSM programs through market research studies and program evaluations. Since Jan. 1, 1996, the Company has been allowed to expense rather than defer and amortize certain DSM program expenditures. Expenditures incurred prior to 1996 continue to be amortized. The electricity market is expected to become competitive in the future, and utilities' ability to implement DSM programs may no longer exist. The Company remains committed to helping customers manage their energy costs, so it and the PSCW have been and will continue to encourage the development of a competitive market for energy efficiency programs. The Company anticipates that, in the future, it will act as a facilitator between customers and providers of energy-efficiency services. Interchange Agreement The electric production and transmission costs of the NSP System are shared by the Company and NSPM. The cost-sharing arrangement between the companies is the Agreement to Coordinate Planning and Operation and Interchange Power and Energy between the Company and NSPM (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 NSPM 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 NSPM 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 NSPM'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 NSPM 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. The NSP System is one of 70 members, 21 associate members and eight regulatory participants in MAPP. The MAPP agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The most recent MAPP agreement, converting MAPP to a Regional Transmission Group, was approved by the FERC Sept. 12, 1996 and has been in effect since Nov. 1, 1996. Fuel Supply In 1997 the Company shared in the fuel supply costs incurred by NSPM in accordance with the Interchange Agreement. Coal and nuclear fuel is expected to provide approximately 96 percent of the energy required to fuel NSP System generating plants over the next several years and that the remaining energy requirements will be provided by natural gas, oil, refuse derived fuel, waste materials, renewable sources, and wood. The actual fuel mix for 1997, and the estimated fuel mix for 1998 and 1999, are as follows: Fuel Use on Btu Basis (Est.) (Est.) 1997 1998 1999 Coal 62.2% 60.4% 59.6% Nuclear 33.9% 36.0% 36.8% Other 3.9% 3.6% 3.6% Electric Operating Statistics The following table summarizes the revenues, sales and customers from the Company's electric business, excluding sales to NSPM and miscellaneous revenues:
Operating Statistics 1997 1996 1995 1994 1993 Electric Revenue (thousands) Residential $ 117 490 $ 118 557 $ 121 073 $ 115 949 $ 114 718 Commercial and industrial 175 438 169 189 169 416 165 639 158 085 Total retail 292 928 287 746 290 489 281 588 272 803 Sales for resale 16 429 17 391 17 902 17 414 16 009 Total $ 309 357 $ 305 137 $ 308 391 $ 299 002 $ 288 812 Sales (millions of kilowatt-hours) Residential 1 681 1 706 1 718 1 642 1 627 Commercial and industrial 3 528 3 405 3 327 3 212 3 045 Total retail 5 209 5 111 5 045 4 854 4 672 Sales for resale 455 458 456 438 417 Total 5 664 5 569 5 501 5 292 5 089 Customer accounts (Dec. 31) Residential 184 921 183 036 181 151 178 473 176 066 Commercial and industrial 31 002 30 695 30 388 29 704 29 088 Total retail 215 923 213 731 211 539 208 177 205 154 Sales for resale 10 10 10 10 10 Total 215 933 213 741 211 549 208 187 205 164
In early 1998, officials of Fort James Corp. announced that its Ashland, Wis. paper mill will close on or about March 21. The mill is the third largest employer in Ashland County and is one of the Company's ten largest electric and gas customers with revenues in excess of $2 million. The effect of losing this customer has been included in the 1998 rate filing. GAS OPERATIONS During 1997, 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 Order No. 636, which significantly changed the services available to, and provided by, local distribution companies and interstate pipelines. The Company is now relying entirely on third party suppliers for its natural gas supply needs, and is utilizing the pipelines only for transportation and storage services. The natural gas supply network throughout North America has been transformed into an integrated gas transportation grid enabling the Company to purchase natural gas from numerous suppliers, obtain contracts for transportation service on directly connected and upstream pipelines, and to flexibly deliver the supplies to the Company's gas service territory. In addition, the Company has directly contracted for underground storage and owns and operates liquefied natural gas and propane-air peak shaving facilities. The Company's diversified supply and transportation contracts, as well as underground storage and peak shaving facilities, provide the Company with the ability to meet customer needs with reliable and economic natural gas supply. The PSCW is continuing to investigate the need to change natural gas regulation in Wisconsin as a result of changes in the structure of natural gas utility pipeline services provided to all gas utilities. The PSCW is advocating a market model in which gas costs will be deregulated by segment, where competition is effective. Distribution service will remain regulated. The Company continues to hold annual and/or winter peaking transportation contracts with Northern Natural Gas Company, Great Lakes Transmission Limited Partnership, Northern Border Pipeline Company, Viking Gas Transmission Company (Viking), another subsidiary of NSPM, and TransCanada Pipeline, LTD. The Company's ability to operate in a competitive gas market was expanded through NSPM's acquisitions of Viking in June 1993 and the formation of an energy services business, Cenerprise Inc. (now Energy Masters International, Inc. or EMI), in October 1993. Viking allows NSP continued access to competitive interstate natural gas transportation. EMI 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. In January 1997, the PSCW adopted "Standards of Conduct" for retail natural gas utilities (LDCs) serving Wisconsin consumers. The standards are similar to, but much more extensive than, the standards of conduct FERC has imposed on Viking under Order No. 497 and on NSP's wholesale electric transmission functions under Order No. 889. The PSCW standards require separation of the LDC delivery function from any affiliate which engages in "gas functions" and impose extensive reporting and other administrative requirements. The Company filed its compliance plan in February 1997. The Company signed a 10-year contract with the U.S. Army to build, own, and operate a natural gas system at Fort McCoy, a regional U.S. Army training center near Sparta, Wis. At the end of January 1998, $820,000 of the approximately $2.0 million total cost of the project had been spent. The Company began providing gas to 169 buildings that were already served by the Fort's existing natural gas distribution system on Feb. 2, 1998, and by July 1998 an additional 746 services should be added as the Fort's propane equipment is converted to use natural gas. The contract should produce about $1.7 million of additional revenue each year. The Company has received orders from the PSCW allowing the Company to treat the investment as utility property and to include the cost of gas purchased for the project in the PGA. The project is expected to be complete in July 1998. In 1997 the Company signed a purchase agreement to acquire Natural Gas, Inc., a privately owned natural gas utility serving 1,900 customers in the New Richmond, Wis. area. The transaction will be structured as a tax-free reorganization for income tax purposes and a pooling of interests for accounting purposes. PSCW approval is required, and a decision is expected to be received by July 1998. Gas Operating Statistics The following table summarizes the revenues, sales and customers from the Company's gas business, excluding sales to NSPM and miscellaneous revenues (including purchased gas adjustments):
1997 1996 1995 1994 1993 Revenues (thousands) Residential $39 989 $41 382 $37 251 $34 297 $32 564 Commercial & Industrial 49 459 47 033 43 189 40 404 38 990 Total $89 448 $88 415 $80 440 $74 701 $71 554 Sales (thousands of mcf) Residential 5 848 6 457 5 873 5 316 5 293 Commercial & Industrial 13 132 13 557 13 078 11 750 11 650 Total 18 980 20 014 18 951 17 066 16 943 Customer Accounts (Dec. 31) Residential 68 631 65 868 63 176 60 194 57 530 Commercial & Industrial 8 809 8 657 8 377 8 012 7 625 Total 77 440 74 525 71 553 68 206 65 155
ENVIRONMENTAL MATTERS The Company's policy is to proactively prevent adverse environmental impacts, regularly monitor operations to ensure the environment is not adversely affected, and to take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. The Company strives to maintain compliance with all applicable environmental laws. The WDNR has been authorized by the United States Environmental Protection Agency to administer the National Pollutant Discharge Elimination System Permits under the Federal Water Pollution Control Act Amendments of 1977. Such permits are required for the lawful discharge of any pollutant into navigable waters from any point source (e.g. power plants). Permits have been issued for all of the Company's applicable plants and all plants are in compliance with permit requirements. The Company presently operates hydro, coal, natural gas, tire-derived fuel, railroad tie, oil-fired, wood and refuse-derived fuel/wood-fired generation equipment. The WDNR has jurisdiction over emissions to the atmosphere from the operation of this equipment at the Company's power plants. The operation of the Company's generating plants substantially conforms to federal and state limitations pertaining to discharges into the air. Regulatory approval is required for the construction of generating plants and major transmission lines. Also, additional regulations have been instituted governing the use, transport, disposal and inspection of hazardous material and electrical equipment containing polychlorinated biphenyls (PCB's). The Company has procedures in place to comply with these regulations. The administrator of a group of PRPs has notified the Company that it might be responsible for the cleanup of solid and hazardous waste landfill sites in Eau Claire, Rice Lake, and Amery, Wis. The Company contends that it did not contribute significant amounts of waste to these landfills. Based on this minimal contribution, the Company does not expect that significant liability will occur. However, because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to predict the outcome of the matter at this time or any potential future impact on the Company's financial condition or operating results. In 1997 the WDNR named the Company as one of three Responsible Parties for creosote and coal tar contamination at an Ashland, Wis. site adjacent to Lake Superior. The site has three distinct portions - the Company portion of the site, the Kreher Park portion of the site and the Chequamegon Bay (of Lake Superior) portion of the site. The Company portion of the site, formerly a coal gas plant site, is Company property. The Kreher Park portion of the site is adjacent to the Company portion of the site and is not owned by the Company. The Chequamegon Bay portion of the site is adjacent to the Kreher Park portion of the site and is not owned by the Company. The Company is discussing its potential involvement in the Kreher Park and Chequamegon Bay portions of the site with WDNR and the City of Ashland. WDNR's consultant is preparing a remedial option study for the entire Ashland site, which includes the Company's portion and the two other adjacent portions. Until this study is completed and more information is known concerning the extent of the final remediation required by the WDNR, the remediation method selected, the related costs, the various parties involved and the extent of the Company's responsibility, if any, for sharing the costs, the ultimate cost to the Company and timing of any payments related to the Ashland site are not determinable. As of Dec. 31, 1997, the Company had recorded an estimated liability of $880,000 for future remediation costs for the Company owned portion of the site. Actual costs incurred through 1997 were $646,000. The PSCW authorized recovery of the amount paid through 1995, $353,000, over a two year period beginning in 1997. Based on the PSCW decision to allow recovery of remediation costs incurred, the Company recorded a regulatory asset of $1,526,000 (of which $176,500 has been amortized to expense as of Dec. 31, 1997). The ultimate cleanup and remediation cost at the Ashland site and the extent of the Company's responsibility, if any, for sharing such costs are not known at this time, but may be significant. In 1996, the Company received a Letter of Non-compliance (LON) from the WDNR for failing to meet the emission guidelines for carbon monoxide (CO) at its Bay Front generating facility. The Company worked with the WDNR to establish mutually agreed-upon CO emission limits for the Bay Front facility. The Company has been advised by WDNR staff that, based on monitoring during 1997, the plant is in compliance with the new emission limits. The Company has now been advised in writing that the LON has been formally closed. No enforcement action or fines resulted from the LON. In 1996, the Company received a Notice of Violation (NOV) from the WDNR stating that emissions from the Company's French Island facility had exceeded allowable levels for dioxin. The Company's initial investigation and response, including a re-test of Unit No. 1, resulted in the WDNR clearing the NOV on Unit No. 1 in September 1996. In October 1996, the Company received a letter from the WDNR reiterating the outstanding NOV on Unit No. 2 and requesting a written response. The Company responded by providing a written response to the WDNR setting forth the Company's plans for bringing the emissions levels back into compliance. By year end 1997, subsequent compliance tests had demonstrated that dioxins no longer exceeded acceptable limits. The Company expects that by early 1998 the WDNR will formally close the NOV. No fines are expected. In late 1996, the Company completed installation of continuous emission monitors for carbon monoxide (CO) at the French Island Generating facility in La Crosse, Wis. The continuous emissions system which will monitor CO emissions from the two generating units was mandated by the Air Pollution Control Permit issued by the WDNR in 1994. In December 1997, nearly 160 nations adopted the "Kyoto Protocol to the United Nations Framework Convention on Climate Change" (the Kyoto Protocol). The Kyoto Protocol obligates developed nations to meet certain emissions targets; specific limits vary from country to country. If the Kyoto Protocol is approved internationally and the U.S. is a party, the Kyoto Protocol would impose, during the first commitment period of 2008 - 2012, a binding obligation on the U.S. to reduce its emissions of carbon dioxide, methane and nitrous oxide to a level 7 percent below 1990 levels and its emissions of hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride by 7 percent below 1990 or 1995 levels. The Kyoto Protocol must be ratified by the U.S. Senate in order for the U.S. to become a party to the protocol. Major provisions of the Kyoto Protocol, such as an international emissions trading program, have yet to be developed. Until they are developed the impact on NSP cannot be predicted. CONSTRUCTION AND FINANCING During the five years ended Dec. 31, 1997, the Company had gross additions to utility plant in service of approximately $262.1 million. Included in the Company's gross additions is $25.7 million for electric production facilities, $152.9 million for other electric properties, $36.3 million for gas utility properties, and $47.2 million for other utility properties. Based on studies made by the Company, the weighted average age of depreciable property was 14.5 years at Dec. 31, 1997. Expenditures for the Company's construction programs for the five-year period 1998-2002, are estimated to be as follows: Year Estimated Construction Expenditures (millions of dollars) 1998 $68 1999 78 2000 90 2001 80 2002 69 TOTAL $385 The largest projects included in these estimates are to construct a new 230 Kv electric transmission line between Chisago County, Minn. and Amery, Wis. and a new 161 Kv line between Stone Lake, Wis. and the Bay Front Generating Plant in Ashland, Wis., and to rebuild transmission lines between Baldwin and Abbotsford, Wis. These projects' estimated total cost is $73 million, of which about $6.8 million will be spent in 1998. The 1998 construction expenditures are estimated to include approximately $50.1 million for electric facilities, $6.6 million for gas facilities and $11.0 million for general plant and equipment. It is presently estimated that approximately 77 percent of the 1998-2002 construction expenditures will be provided by internally generated funds, with the remainder from issues of common stock equity and short-term debt to NSPM, and long-term debt to external investors. At Dec. 31, 1997, the Company's short-term borrowing payable to NSPM were $45.3 million. The PSCW has authorized up to $80.0 million of short-term borrowing. The Company currently projects the need for $10 million of common stock equity from NSPM in 1998 and $50 million of long-term debt in 1999 to finance the estimated construction expenditures for the 1998-2002 construction program. The foregoing estimates of future construction expenditures, internally generated funds and external financing requirements can be affected by numerous factors, including load growth, competition, inflation, changes in the tax laws, rate relief, earnings and regulatory actions. Major electric and gas utility projects are currently subject to the jurisdiction of the PSCW and require its approval. Hence, the above estimated construction program and financing program could change from time to time due to variations in these other factors. Bond Ratings The Company's first mortgage bonds are currently rated AA by Standard and Poor's Corporation, AA by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. On July 15, 1997, Moody's Investors Service upgraded the credit ratings of the Company's first mortgage bonds from A1 to Aa3, and the unsecured resource recovery bonds guaranteed by the Company from A2 to A1. The Company's financial and competitive position were among the factors cited for the upgrade. These ratings are the opinions of the rating agency and an explanation of the significance of these ratings may be obtained from them. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency. EMPLOYEES AND EMPLOYEE BENEFITS At year end 1997, the total number of full- and part-time employees of the Company was 873. About 400 employees of the Company are represented by one local of the International Brotherhood of Electrical Workers under a three year collective bargaining agreement which was ratified by the Company's union membership on April 10, 1997. All provisions of this new agreement were effective retroactively to Jan. 1, 1997 and extend to Dec. 31, 1999. Recent changes to the Company's employee and retiree benefits, which support a broad NSP goal of providing market-based benefits, include: Retiree medical premium increases: Retiree medical premiums were increased in 1994 for existing and future retirees. For existing qualifying retirees, pension benefits have been increased to offset some of the premium increase. For future retirees, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing gradually each year to a total of 40 percent in 1999. 401(k) changes: The Company currently offers eligible employees a 401(k) Retirement Savings Plan. Since 1994, the Company has been matching employees' pre-tax 401(k) contributions. Such matching contributions were $0.5 million in 1997, based on matching up to $900 per year for each nonbargaining employee and up to $700 per year for each bargaining employee. Matching contributions for bargaining employees will increase to a maximum of $800 per year in 1998 and $900 per year in 1999. Wage increases: The Company uses data from surveys of other local and regional companies to determine the rate of compensation for its nonbargaining employees. In 1997 and 1998 non bargaining employees received average wage increases of 4 percent and 3.2 percent, respectively. Bargaining employees received 2 percent per year wage increases in 1997 and 1998 under the new collective bargaining agreement. Item 2 - Properties Electric Utility The Company's major electric generating facilities consist of the following: Year 1997-8 Winter Station and Units Fuel Installed Capability (Mw) Combustion Turbine: Flambeau Station Gas/Oil 1969 17 Park Falls, WI (1 unit) Wheaton Gas/Oil 1973 443 Eau Claire, WI (6 units) French Island Oil 1974 192 La Crosse, WI (2 units) Steam: Bay Front Coal/Wood/ 1945-1960 75 Ashland, WI Gas (3 units) French Island Wood/RDF 1940-1948 29 La Crosse, WI (2 units) Hydro Plants: (19 plants) Various dates 249 TOTAL 1 005 At Dec. 31, 1997, the Company owned approximately 2,390 pole miles of overhead electric transmission lines, 8,462 pole miles of overhead electric distribution lines, 39 conduit miles and 1,078 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 its first mortgage bond indentures pursuant to which the Company has issued first mortgage bonds. Gas Utility The gas properties of the Company include approximately 1,620 miles of natural gas distribution mains. The Company owns two LNG facilities with a combined storage capacity of 400,000 Million Cubic Feet (Mcf) to supplement the available pipeline supply of natural gas during periods of peak demands. The two LNG facilities are located in Eau Claire and La Crosse, Wis. The La Crosse LNG facility is currently nonoperational. In January 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, Wis. area during peak periods. This propane air facility was not operational during the 1995-96 winter, but has been in service since. 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. NSP and other affected parties have commenced lawsuits against the DOE to require the DOE to meet their contractual obligations (including damages for nonperformance) and to request authority to place in escrow payments currently being made to the DOE for the permanent disposal program. The U.S. Court of Appeals for the District of Columbia circuit ruled favorably for NSP on the first lawsuit and NSP and other utilities are currently analyzing claims against the DOE for costs incurred as a result of the DOE's failure to meet its statutory and contractual obligations. No ruling has been made on the second lawsuit regarding escrow of payments. With the dry cask storage facilities approved in 1994 for the Prairie Island nuclear generating plant, NSP believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least 2007. The Monticello nuclear plant has storage capacity sufficient to continue operations until 2010. Storage availability to permit operation beyond these dates is not assured at this time. In the meantime, NSP is investigating all of its alternatives for used fuel storage until a DOE facility is available, including pursuing the establishment of a private facility for the interim storage of used nuclear fuel as part of a consortium of electric utilities. If on-site temporary storage at NSP's nuclear plants reaches approved capacity, NSP could seek interim storage at this or another contracted private facility, if available. For a discussion of environmental proceedings, see "Environmental Matters" under Item 1, incorporated herein by reference. For a discussion of proceedings involving the Company's utility rates, see "Regulation and Rates" under Item 1, incorporated herein by reference. Item 4 - Submission of Matters to a Vote of Security Holders None PART II Item 5 - Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters This is not applicable as the Company is a wholly owned subsidiary. Item 6 - Selected Financial Data This is omitted per conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). Item 7 - Management's 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 I (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 I (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 Dec. 31, 1997 with the year ended Dec. 31, 1996. The Company's net income for year ended Dec. 31, 1997 was $37.4 million, down from the $38.7 million earned in the same period of 1996. The 1997 operating income decreased $3.0 million from the 1996 level. Electric Sales and Revenues Electric Revenues in total increased $5.8 million in 1997. Sales to customers increased $3.9 million or 1.3 percent in 1997 as compared to 1996 primarily due to higher sales levels and a fuel-related rate increase. Total electric sales volumes increased 1.7 percent in 1997 as compared to 1996 due to customer and sales growth, partially offset by less favorable weather in 1997. The Company was allowed to increase rates to reflect an interim fuel cost surcharge effective Sept. 25, 1997 as discussed in the Fuel and Purchased Gas Adjustment Clauses section. The remaining $1.9 million increase in electric revenues relates to higher Interchange Agreement billings to NSPM as discussed in Note 6 to the Financial Statements. Gas Sales and Revenues Gas Revenues in 1997 increased $1.0 million or 1.2 percent as compared with 1996 primarily due to natural gas-related price increases, net of lower sales levels. Total gas sales volumes decreased 5.2 percent in 1997 from 1996 primarily due to unfavorable winter weather in 1997. More than offsetting the sales decline were higher costs per unit of purchased gas, as discussed below, which are reflected in customer rates through the purchased gas adjustment clause mechanism. Operating Expenses and Other Factors Purchased and Interchange Power and Fuel for Electric Generation together increased $11.1 million or 6.2 percent in 1997 from 1996 mainly due to additional power purchases from NSPM and the usage of higher cost peaking plants to support increased sales levels. These power purchases from NSPM were generally more expensive than 1996 due to unplanned and extended outages at NSPM's nuclear generating stations in 1997. Gas Purchased for Resale increased $2.8 million or 4.9 percent in 1997 primarily due to higher costs per unit of gas partially offset by reduced purchases to support lower sales volumes. Other Operation, Maintenance, and Administrative and General expenses together decreased $5.2 million or 5.9 percent in 1997 as compared to 1996 primarily due to reduced employee benefit expenses as discussed in Note 5 to the Financial Statements, lower employee levels, and lower transmission expense billings from NSPM. Partially offsetting these decreases were increased customer service expenses in 1997. Depreciation and Amortization increased $2.1 million or 5.8 percent in 1997 from 1996 due to increases in the Company's plant in service. Income tax decreased $0.6 million in 1997 from 1996 reflecting lower pretax operating income in 1997. Other income (expense)-net increased $0.5 million (net of income tax effects) in 1997 from 1996 primarily due to higher subsidiary company earnings and a tax settlement. In September 1997, the Company received $825,000 of a $1.8 million refund of tax and interest due from the State of Wisconsin. The refund resulted from a favorable court decision regarding a disputed tax issue. The Company expects to receive the balance of the refund in mid 1998. Partially offsetting these increases was the pretax write-off of approximately $900,000 of deferred merger-related costs resulting from the termination of the proposed merger between NSPM and WEC in May 1997. Other interest and amortization (before AFC) decreased $1.2 million or 6.6 percent in 1997 from 1996. A decrease in interest paid to NSPM for short-term borrowings and a reversal of interest previously accrued on the tax issue in dispute with the State of Wisconsin were partially offset by higher interest expense on long-term debt. Technology Changes for the year 2000 Like many other companies, NSP expects to incur significant costs to modify or replace existing technology, including computer software, for uninterrupted operation in the year 2000 and beyond. In 1996, NSP's Board of Directors approved funding to address development and remediation efforts related to the year 2000. A committee made up of senior management is leading NSP's initiatives to identify year 2000 related issues and remediate business processes as necessary in 1998. Testing of computer software modifications and other remediated processes is scheduled for 1999. NSP is also working with major suppliers so that NSP does not experience business interruptions due to year 2000 issues in the suppliers' business processes. The amount of additional development and remediation costs necessary after 1997 for the Company to prepare for the year 2000 is estimated to be approximately $900,000. In 1997 the Company expensed approximately $105,000 for this modification effort. Accounting Changes Effective Jan. 1, 1998, the Company changed its method of accounting for pension costs under SFAS No. 87. The new method was adopted to reduce the volatility of accrued pension costs by amortizing actuarial gains and losses related to pension asset performance over the longest period allowed by SFAS No. 87. The effect of this change is expected to be a decrease in pension costs (represented by an increase in pension accrual credits) of approximately $2.5 million in 1998, including $1.8 million related to periods prior to the change. Item 8 - Financial Statements and Supplementary Data See Item 14(a)-1 in Part IV for financial statements included herein. See Note 10 to the financial statements for summarized quarterly financial data. REPORT OF INDEPENDENT ACCOUNTANTS To The Shareholder of Northern States Power Company (Wisconsin): In our opinion, the accompanying balance sheets and the related statements of income and retained earnings and of cash flows present fairly, in all material respects, the financial position of Northern States Power Company, a Wisconsin corporation, at Dec. 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended Dec. 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. /s/ PRICE WATERHOUSE LLP Minneapolis, Minnesota Feb. 2, 1998
Statements of Income and Retained Earnings Year Ended December 31 (Thousands of dollars) 1997 1996 1995 Operating Revenues Electric $ 382 859 $ 377 073 $ 381 040 Gas 89 790 88 756 78 058 Total 472 649 465 829 459 098 Operating Expenses Purchased and interchange power 179 708 173 492 173 743 Fuel for electric generation 10 023 5 165 4 703 Gas purchased for resale 61 195 58 347 52 356 Other operation 45 534 46 920 46 534 Maintenance 19 734 19 617 20 780 Administrative and general 17 845 21 814 25 264 Conservation and demand side management 8 935 9 117 7 674 Depreciation and amortization 37 815 35 731 33 097 Property and general taxes 14 140 14 332 14 109 Income taxes 24 120 24 688 24 662 Total operating expenses 419 049 409 223 402 922 Operating Income 53 600 56 606 56 176 Other Income (Expense) Allowance for funds used during construction-equity 246 339 445 Other income and deductions-net of applicable income taxes 1 253 677 1 698 Total Other Income (Expense)-Net 1 499 1 016 2 143 Income Before Interest Charges 55 099 57 622 58 319 Interest Charges Interest on long-term debt 16 322 15 918 16 038 Other interest and amortization 1 688 3 406 3 548 Allowance for funds used during construction-debt (328) (399) (484) Total interest charges 17 682 18 925 19 102 Net Income 37 417 38 697 39 217 Retained Earnings, January 1 234 751 221 638 218 833 Dividends paid to parent on common stock (27 997) (25 584) (36 412) Retained Earnings, December 31 $ 244 171 $ 234 751 $ 221 638 See Notes to Financial Statements.
Statements of Cash Flows Year Ended December 31 (Thousands of dollars) 1997 1996 1995 Cash Flows from Operating Activities: Net Income $37 417 $38 697 $39 217 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 38 991 36 665 34 180 Deferred income taxes 4 372 1 736 1 839 Deferred investment tax credits recognized (880) (910) (936) Allowance for funds used during construction - equity (246) (339) (445) Insurance receivable 3 091 Cash provided by (used for) changes in certain working capital items (1 491) (2 633) 7 282 Cash used for changes in other assets and liabilities (3 293) (2 691) (1 064) Net Cash Provided by Operating Activities 74 870 70 525 83 164 Cash Flows from Investing Activities: Capital expenditures (53 580) (49 403) (51 173) Increase (decrease) in construction payables 899 (118) (457) Allowance for funds used during construction - equity 246 339 445 Other (615) (897) (1 606) Net Cash Used for Investing Activities (53 050) (50 079) (52 791) Cash Flows from Financing Activities: Issuances (repayment) of short-term debt due to parent - net 6 000 (11 600) 9 600 Proceeds from issuance of long-term debt 82 691 Redemption of long-term debt, including reacquisition premiums (65 992) (3 375) Dividends paid to parent (27 997) (25 584) (36 412) Net Cash Used for Financing Activities (21 997) (20 485) (30 187) Net Increase (decrease) in cash and cash equivalents (177) (39) 186 Cash and cash equivalents beginning of period 208 247 61 Cash and cash equivalents end of period $ 31 $ 208 $ 247 Cash provided by (used for) changes in certain working capital items: Accounts receivable-net $ 2 149 $ 2 883 ($ 6 188) Materials and supplies (3 980) (1 447) 3 442 Accounts payable and accrued liabilities (4 197) 668 1 241 Payables to affiliated companies 137 2 087 4 475 Income and other taxes accrued 134 (4 007) 417 Other 4 266 (2 817) 3 895 Net ($1 491) ($2 633) $ 7 282 Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $ 16 581 $ 18 556 $ 15 389 Income taxes (net of refunds received) $ 20 673 $ 26 977 $ 17 333 See Notes to Financial Statements.
Balance Sheets December 31 (Thousands of dollars) 1997 1996 Assets Utility Plant Electric-including construction work in progress: 1997, $14,904; 1996, $11,948 $ 931 752 $ 894 143 Gas-including construction work in progress: 1997, $1,561; 1996, $1,569 105 362 99 817 Other-including construction work in progress: 1997, $6,769; 1996, $4,835 70 892 67 262 Total 1 108 006 1 061 222 Accumulated provision for depreciation (426 723) (395 619) Net utility plant 681 283 665 603 Current Assets Cash 31 208 Accounts receivable 38 758 41 151 Accumulated provision for uncollectible accounts (656) (901) Unbilled utility revenues 16 376 21 074 Materials and supplies - at average cost Fuel 12 073 7 780 Other 5 604 5 918 Prepayments and other 12 135 11 703 Total current assets 84 321 86 933 Other Assets Regulatory assets 35 634 37 102 Other investments 8 166 7 433 Nonutility property - net of accumulated depreciation: 1997, $328; 1996, $327 2 752 2 799 Unamortized debt expense 1 761 1 855 Federal income tax receivable 3 307 3 307 Long-term prepayments and deferred charges 7 411 4 099 Total other assets 59 031 56 595 Total Assets $ 824 635 $ 809 131 Liabilities and Equity Capitalization Common stock-authorized 870,000 shares of $100 par value; issued shares: 1997 and 1996, 862,000 $ 86 200 $ 86 200 Premium on common stock 10 461 10 461 Retained earnings 244 171 234 751 Total common stock equity 340 832 331 412 Long-term debt (net of unamortized discount of $1,825 in 1997 and $1,912 in 1996) 231 775 231 688 Total capitalization 572 607 563 100 Current Liabilities Notes payable - parent company 45 300 39 300 Accounts payable 13 844 16 493 Payables to affiliated companies (principally parent) 15 682 15 544 Salaries, wages, and vacation pay accrued 6 089 6 417 Taxes accrued 1 775 1 641 Interest accrued 4 187 4 459 Other 4 897 5 558 Total current liabilities 91 774 89 412 Other Liabilities Accumulated deferred income taxes 105 850 100 898 Accumulated deferred investment tax credits 18 970 20 024 Regulatory liabilities 19 306 19 409 Customer advances 8 192 7 334 Benefit obligations and other 7 936 8 954 Total other liabilities 160 254 156 619 Commitments and Contingent Liabilities (see Note 8) Total Liabilities and Equity $ 824 635 $ 809 131 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 (NSPM), maintains its 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 percent owned; NSP Lands, Incorporated, 100 percent owned; and Clearwater Investments, Incorporated, 100 percent owned) at cost plus equity in earnings since acquisition. The impact of consolidating these subsidiaries would be immaterial. Related Party Transactions The Company's financial statements include intracompany transactions and balances related to sales among the electric and gas utility businesses of the Company as well as intercompany transactions with NSPM and Viking Gas Transmission Company (a wholly-owned subsidiary of NSPM), including intercompany profits which are allowed in utility rates. See Note 6 for further discussion of intercompany transactions with NSPM. 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 3.61 percent in 1997, 3.57 percent in 1996, and 3.48 percent in 1995. Allowance for Funds Used during Construction (AFC) AFC, a non-cash item, is computed by applying a composite pretax rate, representing the cost of capital used to fund utility construction, to qualified Construction Work in Progress (CWIP). The Company used the FERC calculation for production and transmission property and the PSCW calculation for other qualified CWIP. The rates used for the FERC calculation were 5.68 percent in 1997, 5.70 percent in 1996, and 6.20 percent in 1995. The rates used for the PSCW calculation were 10.00 percent in 1997, 10.03 percent in 1996, and 10.13 percent in 1995. The amount of AFC capitalized as a construction cost in CWIP is credited to other income and interest charges. AFC amounts capitalized in CWIP are included in utility rate base for establishing utility service rates. Revenues Revenues are recognized based on products and services provided to customers each month. Because utility customer meters are read and billed on a cycle basis, unbilled revenues are estimated and recorded for services provided from the monthly meter-reading dates to month-end. Regulatory Deferrals As a regulated utility, the Company accounts for certain income and expense items under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 - Accounting for the Effects of Certain Types of Regulation. In doing so, certain costs which would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits which would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistent with ratemaking treatment as established by regulators. Note 7 describes the components of regulatory assets and liabilities. Income Taxes Under the liability method used by the Company, income taxes are deferred for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. Due to the effects of regulation, current income tax expense is provided for the reversal of some temporary differences previously accounted for by the flow- through method. Also, regulation has created certain regulatory assets and liabilities related to income taxes, as summarized in Note 7. The Company is included in the consolidated Federal income tax return filed by NSPM 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 NSPM and charged back to the Company. Investment tax credits were deferred and are being amortized over the estimated lives of the related property. Purchased Tax Benefits The Company purchased tax-benefit transfer leases under the Safe Harbor Lease provisions of the Economic Recovery Tax Act of 1981. For both financial reporting and regulatory purposes, the Company is amortizing the difference between the cost of the purchased tax benefits and the amounts to be realized through reduced current income tax liabilities over the remaining terms of the leases after the initial investments have been recovered. Derivative Financial Instruments As discussed in Note 2, the Company had 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 was recorded as an adjustment to interest expense each period over the term of the agreement. The agreement expired March 1, 1998. Environmental Costs Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense (or deferred as a regulatory asset based on expected recovery from customers in future rates) if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use (such as pollution control equipment), the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where the Company has been designated as one of several potentially responsible parties, the amount accrued represents the Company's estimated share of the cost. The Company intends to treat any future costs related to decommissioning and restoration of its power plants and substation sites, where operation may extend indefinitely, as a capitalized removal cost of retirement in utility plant. Depreciation expense levels currently recovered in rates include a provision for an estimate of removal costs. 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. Reclassifications Certain reclassifications have been made to the 1996 and 1995 financial statements to conform with the 1997 presentation. These reclassifications had no effect on net income or earnings per share. 2. Long-term Debt
Dec. 31 Dec. 31 1997 1996 Long-term debt includes the following issues: (Thousands of dollars) First Mortgage Bonds: Series due: Oct. 1, 2003, 5 3/4% $ 40 000 $ 40 000 March 1, 2023, 7 1/4% 110 000 110 000 Dec. 1, 2026, 7 3/8% 65 000 65 000 Total First Mortgage Bonds 215 000 215 000 City of La Crosse Resource Recovery Revenue Bonds - Series due Nov. 1, 2021, 6% 18 600 18 600 Total long-term debt $ 233 600 $ 233 600
Except for minor exclusions, all real and personal property is subject to the lien of the Company's first mortgage bonds. The Supplemental and Restated Trust Indenture dated March 1, 1991, and effective Oct. 1, 1993 permits an amount of established permanent additions to be deemed equivalent to the payment of cash necessary to redeem one percent of the highest principal amount of each series of first mortgage bonds (other than resource recovery financing) at any time outstanding. Interest Rate Swap Agreement The Company had entered into an interest rate swap agreement which expired March 1, 1998 for $20 million of the 7 1/4 percent series of first mortgage bonds. This agreement effectively converted the interest rates for $20 million of this debt issue from fixed to variable based on the six-month London Interbank Offered Rate (LIBOR) adjusted semi-annually on March 1 and September 1. The net effective interest rate under the swap agreement was 7.96 percent at Dec. 31, 1997. Market risks associated with this agreement resulted from short-term interest rate fluctuations. Credit risk related to non-performance of the counterparties was not deemed significant, but would have resulted in NSP terminating the swap transaction and recognizing a gain or loss, depending on the fair market value of the swap. Such agreements are not reflected on the Company's balance sheets. The interest rate swap serves to hedge the interest rate risk associated with fixed rate debt in a declining interest rate environment. This hedge is produced by the tendency for changes in the fair market value of the swap to be offset by changes in the present value of the liability attributable to the fixed rate debt issued in conjunction with the interest rate swap. If the interest rate swap had been terminated at Dec. 31, 1997, $74,000 would have been payable by the Company while the present value of the related fixed rate debt issued with the swaps was $320,000 above carrying value. Fair Value of Debt The estimated fair value of the Company's long term debt at December 31, 1997 and 1996 is $234.9 million and $227.7 million, respectively. This fair value is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. Capital Lease Obligations Amounts due under capital lease obligations are approximately $441,000, $128,000, $14,000, $0, and $0, respectively, for the years 1998-2002. 3. Short-Term Borrowings The Company had bank lines of credit aggregating $1 million at Dec. 31, 1997. 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 1997 and 1996 there were no bank loans outstanding as the Company obtained short-term borrowings from NSPM at NSPM's average daily interest rate, including the cost of their compensating balance requirements. The PSCW has authorized the Company to make short-term borrowings up to $80.0 million. At Dec. 31, 1997 and 1996, the Company had $45.3 million and $39.3 million, respectively, in short-term borrowings from NSPM outstanding. The weighted average interest rates on all short-term borrowings as of Dec. 31, 1997 and 1996, were 5.68 percent and 5.62 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 percent to net income before income tax expense. The reasons for the difference are as follows:
1997 1996 1995 Tax computed at statutory rate 35.0% 35.0% 35.0% Increases (decreases) in tax from: State income taxes, net of Federal income tax benefit 3.7 4.6 5.2 Investment tax credits recognized (1.5) (1.4) (1.4) Other - net 1.2 0.7 (0.8) Effective income tax rate 38.4% 38.9% 38.0% Income tax expense is comprised of the following: (Thousands of Dollars) Included in Utility operating expenses: Current Federal tax expense $ 15 550 $ 18 293 $ 17 772 Current state tax expense 3 671 3 838 4 546 Deferred Federal tax expense 4 688 2 790 2 679 Deferred state tax expense 1 092 677 601 Deferred investment tax credit adjustments (880) (910) (936) Total 24 121 24 688 24 662 Included in Other income and deductions - net: Current Federal tax expense 1 942 1 299 691 Current state tax expense (1 345) 326 130 Deferred Federal tax expense (1 408) (1 385) (1 264) Deferred state tax expense 0 (346) (178) Total income tax expense $ 23 310 $ 24 582 $ 24 041
The components of the Company's net deferred tax liability at December 31 (including current and noncurrent amounts) were as follows:
(Thousands of dollars) 1997 1996 Deferred tax liabilities: Differences between book and tax bases of property $ 106 242 $ 103 771 Tax benefit transfer leases 108 1 638 Regulatory assets 12 227 12 690 Other 4 857 3 782 Total deferred tax liabilities 123 434 121 881 Deferred tax assets: Deferred investment tax credits 7 597 8 014 Regulatory liabilities 7 725 7 729 Deferred compensation, accrued vacation and other reserves not currently deductible 618 2 310 Other 585 1 260 Total deferred tax assets 16 525 19 313 Net deferred tax liability $ 106 909 $ 102 568
5. Pension Plans and Other Post Retirement Benefits The Company offers the following benefit plans to its benefit employees, of whom approximately 52 percent are represented by one local labor union under a collective-bargaining agreement which expires Dec. 31, 1999. Pension Benefits Employees of the Company participate in the Northern States Power Company Pension Plan. This noncontributory defined benefit pension plan covers substantially all employees. Benefits are based on a combination of years of service, the employees highest average pay for 48 consecutive months and Social Security benefits. It is the Company's policy to fully fund the actuarially determined pension costs recognized for ratemaking purposes, subject to the limitations under applicable employee benefit and tax laws. Plan assets consist principally of common stock of public companies, corporate bonds and U.S. government securities. The following table sets forth the funded status of the pension plan, including amounts allocable to the Company, as of December 31:
(Thousands of dollars) 1997 1996 Company Company Total Plan Portion Total Plan Portion Actuarial present value of benefit obligation: Vested $ 701 219 $ 91 579 $ 660 920 $ 84 924 Nonvested 165 004 18 260 147 278 16 332 Accumulated benefit obligation $ 866 223 $ 109 839 $ 808 198 $ 101 256 Projected benefit obligation $1 048 251 $ 128 222 $ 993 821 $ 120 886 Plan assets at fair value 1 978 538 234 304 1 634 696 196 089 Plan assets in excess of projected benefit obligation 930 287 106 082 640 875 75 203 Unrecognized prior service cost 18 663 2 336 19 734 2 469 Unrecognized net actuarial gain (953 825) (102 160) (651 368) (77 174) Unrecognized net transitional asset (463) (57) (539) (67) Net pension asset recorded $ (5 338)$ 6 201 $ 8 702 $ 431
Since Jan. 1, 1993, for financial reporting and regulatory purposes, the Company's pension expense has been 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:
1997 1996 1995 (Thousands of dollars) Service cost - benefits earned during the period $ 3 062 $ 3 390 $ 2 844 Interest cost on projected benefit obligation 8 926 8 618 8 662 Actual return on allocated share of plan assets (49 959) (12 353) (10 994) Net amortization and deferral 32 201 (2 727) (1 567) Net periodic pension cost determined under SFAS No. 87 (5 770) (3 072) (1 055) Expenses recognized due to actions of regulators 90 90 90 Net periodic pension cost (credit) recognized for ratemaking $ (5 680) $ (2 982) $ (965)
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7 percent at Dec. 31, 1997 and 7.5 percent at Dec. 31, 1996. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was five percent in 1997 and 1996. The assumed long- term rate of return on assets used for cost determinations under SFAS No. 87 was nine percent for 1997, 1996, and 1995. Assumption changes decreased 1997 pension costs by $800,000 and increased 1996 pension costs by approximately $1.4 million. Assumption changes are expected to decrease 1998 pension credits by approximately $700,000. Postretirement Health Care The Company participates in NSPM's contributory health and welfare benefit plan that provides health care and death benefits to substantially all employees after their retirement. The plan is intended to provide for sharing the costs of retiree health care between the Company and retirees. For employees retiring after Jan. 1, 1994, a six- year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40 percent in 1999. In conjunction with the 1993 adoption of SFAS No. 106 - Employers' Accounting for Postretirement Benefits Other Than Pensions, the Company elected to amortize on a straight-line basis over 20 years the unrecognized accumulated postretirement benefit obligation (APBO) of approximately $29.5 million for current and future retirees of the Company. Before 1993, NSP funded payments for retiree benefits internally. While the Company generally prefers to continue using internal funding of benefits paid and accrued, there have been some external funding requirements imposed by the Company's regulators, as discussed below, including the use of tax advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1997 consisted of investments in equity mutual funds and cash equivalents. The following table sets forth the funded status of the health care plan, including amounts allocable to the Company, as of December 31.
(Thousands of dollars) 1997 1996 Company Company Total Plan Portion Total Plan Portion APBO: Retirees $149 081 $ 23 637 $144 180 $ 22 166 Fully eligible plan participants 21 245 3 236 23 438 3 447 Other active plan participants 108 904 13 189 101 065 12 065 Total APBO 279 230 40 062 268 683 37 678 Plan Assets at Fair Value 19 784 10 553 15 514 8 285 APBO in excess of plan assets 259 446 29 509 253 169 29 393 Unrecognized net actuarial loss (14 408) (3 071) (12 467) (2 057) Unrecognized transition obligation (161 700) (22 112) (172 480) (23 586) Postretirement benefit liability recorded $ 83 338 $ 4 326 $ 68 222 $ 3 750
The assumed health care cost trend rates used in measuring the APBO at Dec. 31, 1997 and 1996, respectively, were 9.2 and 9.8 percent for those under age 65 and 6.8 and 7.1 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 Dec. 31, 1997, by approximately 14.5 percent and service and interest cost components of the net periodic postretirement cost by approximately 15.4 percent. The assumed discount rate used in determining the APBO was 7 percent for Dec. 31, 1997 and 7.5 percent for Dec. 31, 1996, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was eight percent for 1997, 1996, and 1995. Assumption changes had an immaterial effect on results of operations. The Company's share of net annual periodic postretirement benefit costs under the plan consists of the following components (thousands of dollars):
1997 1996 1995 Service cost-benefits earned during the year $ 644 $ 804 $ 686 Interest cost (on service cost and APBO) 2 694 2 700 2 761 Amortization of transition obligation 1 474 1 474 1 474 Actual return on Company's share of plan assets (874) (632) (301) Net amortization and deferral 211 221 Net periodic postretirement health care costs $4 149 $4 567 $4 620
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 NSPM's contributory, defined contribution Retirement Savings Plan (the Plan), which complies with section 401(k) of the Internal Revenue code and covers substantially all Company employees. Employer matching contributions under this Plan began in 1994, and are required to match a specified amount of employee contributions. The Company's matching contribution to the Plan was $0.5 million in 1997, 1996 and 1995. 6. Parent Company and Intercompany Agreements The Company is wholly-owned by NSPM. The electric production and transmission costs of the NSP system are shared by the Company and NSPM. A FERC approved agreement (Interchange Agreement) between the Company and NSPM 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 1997 1996 1995 (Thousands of dollars) Operating revenues: Electric $ 71 262 $ 69 337 $ 70 251 Gas $45 $39 $43 Operating expenses: Purchased and interchange power $179 708 $173 492 $173 743 Gas purchased for resale $231 $216 $205 Other operation $11 972 $13 685 $13 791
7. Regulatory Assets and Liabilities The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheet at December 31: (Thousands of dollars) Amortization Period 1997 1996 AFC recorded in plant on a net-of-tax basis Plant Lives* $ 9 768 $ 9 928 Losses on reacquired debt Term of Related Debt 12 533 13 341 Conservation and energy management programs Up to 8 years* 8 842 10 604 Environmental costs As allowed in rates 1 913 1 405 Unrecovered purchased gas costs 1 year 0 722 Pensions and other Mainly 10 years 2 578 1 102 Total Regulatory Assets $ 35 634 $ 37 102 Excess deferred income taxes collected from customers $ 3 898 $ 3 420 Investment tax credit deferrals 12 694 13 412 Other 2 714 2 577 Total Regulatory Liabilities $ 19 306 $ 19 409 * Earns a return on investment in the ratemaking process.
8. Commitments and Contingent Liabilities Commitments The Company presently estimates capital expenditures will be $68 million in 1998 and $385 million for 1998-2002. Rentals under operating leases were approximately $1,080,000, $1,704,000, and $1,644,000 for 1997, 1996, and 1995, respectively. Future commitments under these leases generally decline from current levels. Purchased Gas Contracts The Company has contracts providing for the purchase and delivery of a significant portion of its current natural gas requirements. These contracts, which expire in various years between 1999 and 2011, require minimum contractual purchases and deliveries of natural gas. In total, the Company is committed to the minimum purchase of approximately $119 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 No. 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 natural gas available and suppliers are expected to continue to provide reliable natural gas supplies, risk of loss from non-performance under these contracts is not considered significant. In addition, the Company's risk of loss (in the form of increased costs) from market price changes in natural gas is mitigated through the cost-of-gas adjustment provision of the ratemaking process, which provides for recovery of prudently incurred natural gas costs. Nuclear Contingencies Although the Company does not own a nuclear facility, any assessment made against NSPM 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. NSPM has secured insurance of $200 million to satisfy such claims. The remaining $8.7 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSPM is subject to an assessment of $79 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States with a maximum funding requirement of $10 million per reactor during any one year. Environmental Contingencies The Company potentially may be involved in the cleanup and remediation at four sites. Three sites are solid and hazardous waste landfill sites in Eau Claire, Rice Lake and Amery, Wis. The Company contends that it did not contribute significant amounts of waste to these landfills. Based on this minimal contribution, the Company does not expect that significant liability will occur. However, because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to predict the outcome of these matters at this time. The fourth site, in Ashland, Wis., contains creosote and coal tar contamination. In 1997, the WDNR notified the Company that it is one of three Responsible Parties for creosote and coal tar contamination at the Ashland site. The Ashland site has three distinct portions--the Company portion, the Kreher Park portion and the Chequamegon Bay (of Lake Superior) portion. The Company portion of the site, formerly a coal gas plant site, is Company property. The Kreher Park portion is adjacent to the Company site and is not owned by the Company. The Chequamegon Bay portion is adjacent to the Kreher Park portion and is not owned by the Company. The Company is discussing its potential involvement in the Kreher Park and Chequamegon Bay portions with the WDNR and the City of Ashland. In February 1996, the Company received from the WDNR's consultant a draft report of the results of a remediation action options feasibility study for the Kreher Park portion of the Ashland site. The draft report contains several remediation options that were scored by the consultant across a variety of parameters. Two options scored the most technologically and economically feasible, and one of those is the lowest-cost option for remediation at the Kreher Park portion of the site. The draft report estimates that this option, which would involve capping the property and some limited groundwater treatment, would cost approximately $6 million. In 1996, the WDNR completed a sediment contamination investigation of the impacted area of the Chequamegon Bay portion of the site to determine the extent and nature of the contamination. Contamination of the near shore area has been confirmed by the study. WDNR's consultant is preparing a remedial option study for the entire Ashland site, which includes the Company's portion and the two adjacent portions. Until this study is completed and more information is known concerning the extent of the final remediation required by the WDNR, the remediation method selected, the related costs, the various parties involved and the extent of the Company's responsibility, if any, for sharing the costs, the ultimate cost to the Company and timing of any payments related to the Ashland site are not determinable, but may be significant. As of Dec. 31, 1997, the Company had recorded an estimated liability of $880,000 for future remediation costs for the Company owned portion of the site. Actual costs incurred through 1997 were $646,000. The PSCW authorized recovery of the amount paid through 1995, $353,000, over a two year period beginning in 1997. Based on the PSCW decision to allow recovery of remediation costs incurred, the Company recorded a regulatory asset of $1,526,000 (of which $176,500 has been amortized to expense as of Dec. 31, 1997). 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 1997 1996 1995 (Thousands of dollars) Operating income before income taxes: Electric $ 68 536 $ 69 730 $ 72 595 Gas 9 185 11 564 8 243 Total operating income before income taxes $ 77 721 $ 81 294 $ 80 838 Depreciation and amortization: Electric $ 32 510 $ 30 857 $ 28 752 Gas 5 305 4 874 4 345 Total depreciation and amortization $ 37 815 $ 35 731 $ 33 097 Construction expenditures: Electric $ 46 744 $ 42 519 $ 42 843 Gas 6 836 6 884 8 330 Total construction expenditures $ 53 580 $ 49 403 $ 51 173 Identifiable assets: Electric utility $674 939 $661 585 $654 130 Gas utility 91 609 91 557 86 021 Total identifiable assets 766 548 753 142 740 151 Other corporate assets 58 087 55 989 50 747 Total assets $824 635 $809 131 $790 898
10. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended Mar. 31, June 30, Sept. 30, Dec. 31, 1997 1997 1997 1997 (Thousands of dollars) Operating revenues $138 249 $103 796 $104 341 $126 263 Operating income $ 17 259 $ 9 353 $ 11 225 $ 15 763 Net income $ 12 608 $ 4 645 $ 8 242 $ 11 922
Quarter Ended Mar. 31, June 30, Sept. 30, Dec. 31, 1996 1996 1996 1996 (Thousands of dollars) Operating revenues $138 730 $101 678 $100 366 $125 055 Operating income $ 17 341 $ 9 902 $ 11 379 $ 17 984 Net income $ 12 919 $ 5 432 $ 6 799 $ 13 547
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure During 1997 there were no disagreements with the Company's independent certified public accountants on accounting procedures or accounting and financial disclosures. PART III Part III of Form 10-K has been omitted from this report in accordance with conditions set forth in general instructions I (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 and Reports on Form 8-K (a) 1. Financial Statements Page Included in Part II of this report: Report of Independent Accountants for the years ended Dec. 31, 1997 and 1996. 20 Statements of Income and Retained Earnings for the three years ended Dec. 31, 1997. 21 Statements of Cash Flows for the three years ended Dec. 31, 1997. 22 Balance Sheets, Dec. 31, 1997 and 1996 23 Notes to Financial Statements. 25 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 3.01* Restated Articles of Incorporation as of Dec. 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 Aug. 19, 1992. (Filed as Exhibit 3.02 to Form 10-K Report 10-3140 for the year 1992) 4.01* Copy of Trust Indenture, dated April 1, 1947, From the Company to Firstar Trust Company (formerly 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 Aug. 1, 1964. (Filed as Exhibit 4.20 to Registration Statement 2-23726) 4.05* Copy of Supplemental Trust Indenture, dated Dec. 1, 1969. (Filed as Exhibit 2.03E to Registration Statement 2-36693) 4.06* Copy of Supplemental Trust Indenture, dated Sept. 1, 1973. (Filed as Exhibit 2.03F to Registration Statement 2-49757) 4.07* Copy of Supplemental Trust Indenture, dated Feb. 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 Oct. 1, 1993. (Filed as Exhibit 4.01 to Form 8-K Report dated September 21, 1993) 4.15* Copy of Supplemental Trust Indenture, dated Dec. 1, 1996. (Filed as Exhibit 4.01 to Form 8-K Report dated Dec. 12, 1996) 10.01* Copy of Interchange Agreement dated Sept. 17, 1984, and Settlement Agreement dated May 31, 1985, between the Company, the Minnesota Company and LSDP. (Filed as Exhibit 10.10 to Form 10-K Report 10-3140 for the year 1985) 27.01 Financial Data Schedule 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995. (b) Reports on Form 8-K - The following report on Form 8-K was filed either during the three months ended December 31, 1997, or between Dec. 31, 1997 and the date of this report. 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 March 25, 1998 /s/ John A. Noer President and Chief Executive Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. /s/ /s/ John A. Noer H. Lyman Bretting President and Chief Executive Director (Principal Executive Officer) /s/ /s/ Roger D. Sandeen P. M. Gelatt Controller Director (Principal Accounting Officer) /s/ /s/ Neal A. Siikarla Ray A. Larson, Jr. Treasurer Director (Principal Financial Officer) /s/ Larry G. Schnack Director /s/ Loren L. Taylor Director EXHIBIT INDEX Method of Exhibit Filing No. Description DT 27.01 Financial Data Schedule DT 99.01 Statement pursuant to Private Securites Litigation Reform Act of 1995. DT = Filed electronically with this direct transmission. EX-27 2
UT EXHIBIT 27.01 This schedule contains summary financial information extracted from the Statements of Income and Retained Earnings, Balance Sheets and Statements of Cash Flows and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1997 DEC-31-1997 PER-BOOK 681,283 10,918 84,321 48,113 0 824,635 86,200 10,461 244,171 340,832 0 0 231,775 45,300 0 0 0 0 0 0 206,728 824,635 472,649 24,120 394,929 419,049 53,600 1,499 55,099 17,682 37,417 0 37,417 27,997 16,322 74,870 43.41 43.41 The Company has had no dilutive securities outstanding during the last three years. Adopting SFAS No. 128 "Earnings per Share" did not change previously reported earnings per share.
EX-99 3 Exhibit 99.01 Northern States Power Company Cautionary Factors The Private Securities Litigation Reform Act of 1995 (the Act) provides a new "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been and will be made in written documents and oral presentations of Northern States Power Company, a Wisconsin Corporation (the Company). Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used in the Company's documents or oral presentations, the words "anticipate", "estimate", "expect", "objective", "possible", "potential" and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward- looking statements, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: Economic conditions including inflation rates and monetary fluctuations; Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Company has a financial interest; Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services; Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight; Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, or the Company; or security ratings; Factors affecting operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints; Employee work force factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages; Increased competition in the utility industry, including: industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market; Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options; Social attitudes regarding the utility and power industries; Cost and other effects of legal and administrative proceedings, settlements, investigations and claims; Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets; Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors pursuant to the Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made by the Company prior to the effective date of the Act. -----END PRIVACY-ENHANCED MESSAGE-----