10-K 1 PART I Item 1. Business Northern States Power Company ("the Company"), incorporated in 1901 under the laws of Wisconsin as the La Crosse Gas and Electric Company, is an operating public utility company with executive offices at 100 North Barstow Street, Eau Claire, Wisconsin 54702-0008 (Phone: (715) 839-2621). The Company is a wholly-owned subsidiary of Northern States Power Company, a Minnesota corporation ("the Minnesota Company"). The Company is engaged in the generation, transmission, and distribution of electricity to approximately 208,000 retail customers in an area of approximately 18,900 square miles in northwestern Wisconsin, to approximately 9,100 electric retail customers in an area of approximately 300 square miles in the western portion of the Upper Peninsula of Michigan, and to 10 wholesale customers in the same general area. The Company is also engaged in the distribution and sale of natural gas in the same service territory to approximately 68,200 customers in Wisconsin and 4,700 customers in Michigan. In Wisconsin, some of the larger communities the Company provides natural gas to are Eau Claire, Chippewa Falls, La Crosse, Hudson, Menomonie and Ashland. In the Upper Peninsula of Michigan, the largest community to which the Company provides natural gas is Ironwood. In 1994 the Company derived 83 percent of its total operating revenues from electric utility operations and 17 percent from gas utility operations. As of December 31, 1994, the Company had 955 employees including 849 full-time employees. REGULATIONS AND RATES Regulation The Company is experiencing some of the challenges currently common to regulated electric and gas utility companies, namely increasing competition for customers and uncertainties in the future regulatory processes. Currently, as a result of increased competition, and the desire on the part of some customers for choice, the Public Service Commission of Wisconsin ("PSCW") is investigating changes in the structure and regulation of electric and gas utilities. The Company has filed comments with the Commission regarding the future of the electric industry. Some of these comments are included in the Electric Operations section of this report. A proceeding has also been initiated to explore similar issues for the Company's gas operations as well as a review of the purchase gas adjustment clause ("PGAC"). The PSCW and Michigan Public Service Commission ("MPSC") regulate the rates and service of the Company with respect to retail sales within the State of Wisconsin and the State of Michigan, respectively, the issuance of new securities by the Company and various other aspects of the Company's operations. The PSCW also exercises jurisdiction over the construction of certain electric and gas facilities. 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 96.9 percent of the Company's 1994 electric retail revenues from sales and 93.4 percent of its retail gas revenues from sales were subject to PSCW jurisdiction with the remaining retail revenues subject to MPSC jurisdiction. In 1994, the Company's wholesale revenues from sales were approximately 5.8 percent of the Company's electric revenues from sales. Prior to construction of all major projects, the Company is required to obtain various licenses, permits and a certificate of public convenience and necessity from the PSCW. As part of this process, advance plan hearings are held by the PSCW, whereby the Company's generation and transmission construction plans and those of several neighboring utilities are reviewed by the PSCW. 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 reviews each utility's cash position to determine if a current return on construction work-in-progress (CWIP) will be allowed. The PSCW will allow either a return on CWIP or capitalization of AFC at the adjusted overall cost of capital. The Company currently capitalizes the Allowance for Funds Used during Construction (AFC) on production and transmission CWIP at the FERC formula rate and on all other CWIP at the adjusted overall cost of capital. Rate Changes Wisconsin The Company filed a proposal for a new high load factor rate with the PSCW in November, 1994, that became effective January 1, 1995. Under the proposal, qualifying customers would receive a credit on their bills of up to 4.0% depending on their load factor. This is expected to reduce 1995 revenues by approximately $1.5 million. On December 23, 1993, the PSCW issued an order approving a $1.41 million (2.0 percent) increase on an annual basis in the Company's gas rates. A January 1, 1994 effective date was authorized for these rate changes. No change in the retail electric rates was requested. The Company plans to file a submittal in June 1995 as required by the PSCW biennial filing requirement. Wholesale The Company plans to announce market-based pricing options for existing and potential wholesale customers in 1995. The wholesale customers have new opportunities to purchase power from power suppliers other than NSP. With open transmission access, they have the opportunity to purchase power from any producer and request that, on a comparable basis, the power be delivered from the producer to their municipality. In May, 1994, the Company offered its municipal wholesale customers a discount of one to two percent from the FERC authorized rate for a long-term full requirements commitment of five to ten years with comparable cancellation notices. Five of the ten municipal wholesale customers elected to extend their contracts to receive the discounts. The total annual decrease in revenues is approximately $80,000. NSP(MN) and the Company filed open access transmission tariffs with the FERC in March 1994. In accepting the filing, the FERC ruled NSP's tariff would be subject to the requirement that the NSP system offer transmission service to third parties using terms and conditions comparable to its own use of the system. NSP recently reached a settlement in principle with several parties involved in this proceeding and anticipates approval of the stipulation in early 1995. Michigan There were no changes in the Michigan electric or gas base rates during 1994. Fuel and Purchased Gas Adjustment Clauses Wisconsin The Wisconsin automatic retail electric fuel adjustment clause was eliminated for the Company in the electric retail rate order issued by the PSCW dated March 11, 1986. The electric fuel adjustment clause has been 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. The Company's retail gas rate schedules include a purchased gas adjustment clause which provides for inclusion of the current cost of gas including its transportation. The factors applied under the purchased gas adjustment clause are adjusted on an ongoing basis to reflect a reconciliation of gas costs incurred and recovered. Michigan The Company's Michigan retail gas and electric rate schedules include Gas Cost Recovery Factors (GCRF) and Power Supply Cost Recovery Factors (PSCRF), respectively, which are based on a twelve-month projection. 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-collections are refunded and any under-collections are collected, including interest. Wholesale The Company calculates the fuel adjustment factor for the current month based on estimated fuel costs for that month. The fuel adjustment factor is adjusted for over or under collected resale fuel costs from the prior month's actual operations which provide an ongoing true-up mechanism. Demand Side Management The Company continues to implement various Demand Side Management (DSM) programs designed to improve load factor and reduce the Company's power production cost and system peak demands, thus reducing or delaying the need for additional investment in new generation and transmission facilities. The Company currently offers a broad range of DSM programs to all customer sectors, including information programs, rebate and financing programs, and rate incentive programs. In management's opinion, these programs need to respond to customer needs and focus on increasing value of service so that, over the long term, the programs help its customer base become more stable, energy efficient and competitive. During 1994, the Company's programs accomplished approximately 19 Megawatts (MW) of system peak demand reduction in the commercial, industrial and agricultural customer sectors and over 3.5 MW in the residential sector. These impacts were obtained through appliance, lighting, motor, and cooling efficiency and process improvements, peak curtailable and time of use rate applications, and direct load control of water heaters and air conditioners. Since 1986, the Company's DSM programs have achieved 149 MW of summer peak demand reduction, which is equivalent to 15% of its 1994 summer peak demand. A cumulative goal of 200 MW of peak demand reduction by 1997 has been established. The Company continues to focus on improving the cost-effectiveness of its DSM programs through market research studies and program evaluations. ELECTRIC OPERATIONS Competition On Oct. 24, 1992, the President signed into law the Energy Policy Act of 1992 (Energy Act). The Energy Act amends the Public Utility Holding Company Act of 1935 (1935 Act) and the Federal Power Act. Among many other provisions, the Energy Act is designed to promote competition in the development of wholesale power generation in the electric utility industry. It exempts a new class of independent power producers from regulation under the 1935 Act. The Energy Act also allows the FERC to order wholesale "wheeling" by public utilities to provide utility and non-utility generators access to public utility transmission facilities. The provision allows the FERC to set prices for wheeling, which will allow utilities to recover certain costs. The costs would be recovered from the companies receiving the services, rather than the utilities' retail customers. Many states are currently considering retail competition. While the topic of retail competition has been discussed in NSP jurisdictions, no legislation has been formally introduced. However, the PSCW has opened generic docket 05-EI-114 to examine various industry restructuring issues. The PSCW has asked each utility in the state and various other parties for comments regarding retail competition. In response to the PSCW request, the Wisconsin Company filed the following recommendations. Competition should be phased in for retail markets by customer classes, with all customers having choice of supplier by 2001. The generation segment of the industry should be deregulated by 2001. NSP proposes that utilities retain operational control of their transmission and distribution systems and that utilities should be permitted to recover the cost of investments that were authorized under traditional regulation, to the extent that these investments exceed the market price. Finally, utilities and other competitors should have a level playing field for issues such as obligation to serve, eminent domain, requirements for demand side management, funding of social programs, opening of retail markets to competition and other issues. Also, as an outcome of the responses to the PSCW, a task force was formed by the PSCW to analyze the industry restructuring necessary in the State of Wisconsin. A goal of this task force is to have a list of recommended legislative changes to the Wisconsin Legislature for the 1996 session. Retail competition represents yet another development of a competitive electric industry. Management plans to continue its ongoing efforts to be a low-cost supplier of electricity and an active participant in the more competitive market for electricity expected as a result of the Energy Act. The Michigan Public Service Commission has determined that Michigan should recodify statutes governing energy production. They will be working with the governor's office to initiate that process. Michigan also has a retail wheeling experiment, limited to its two largest utilities and customers larger than $ 50 million, currently underway. The Company's customers are not included in this experiment which is currently being challenged in court. NSP System The Company's electric production and transmission systems are interconnected with the production and transmission system of the Minnesota Company. The combined electric production and transmission systems of the Company and the Minnesota Company are hereinafter called the "NSP System." The facilities of the NSP system include coal and nuclear generating plants, hydro, gas fired combustion turbines, waste wood, and waste wood/refuse derived fuel ("RDF") generating plants, an interconnection with 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 the large plants. The NSP System added the Angus Anson 232 MW gas-fired combustion turbines generation facility, located in Sioux Falls, South Dakota on September 24, 1994. Also in 1994, the MN Company signed a long-term power purchase contract with LSP-Cottage Grove for 245 MW of annual capacity for thirty years. The Minnesota Company operates two nuclear generating plants: the single unit, 539 Mw Monticello Nuclear Generating Plant and the Prairie Island Nuclear Generating Plant with two units totaling 1,025 Mw. The Monticello Plant received its 40- year operating license from the 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 Minnesota Company has contracted with the DOE for the disposal of spent nuclear fuel. The DOE charges a quarterly disposal fee based on nuclear electric generation sold. This fee ranges from approximately $10 million to $12 million per year, which NSP recovers from its customers in cost-of-energy rate adjustments or through base rates. In 1985, the Minnesota Company paid the DOE a one-time fee of $95 million for fuel used prior to April 7, 1983. In 1979 the Minnesota Company began expanding the used nuclear fuel storage facilities at its Monticello Plant by replacement of the racks in the storage pool. Also, in 1987, the Company completed the shipment of 1,058 spent fuel assemblies from the Monticello Plant to a General Electric storage facility in Morris, Illinois. As a result, the plant now has sufficient pool storage capacity to operate until 2008. In 1976 the Minnesota Company began expanding the used nuclear fuel storage facilities at its Prairie Island Plant by replacement of the racks in the storage pool. Total capacity was increased from 210 fuel assemblies to 1,386 fuel assemblies. In 1994 the spent nuclear fuel storage facilities at the Minnesota Company's Prairie Island Plant were expected to reach full capacity. In May 1994 additional on-site dry cask fuel storage facilities were approved by the Minnesota Legislature which are expected to provide sufficient storage capacity to operate until at least 2002. Capability and Demand The Company's record peak demand occurred on January 20, 1994, and was recorded at 1,032 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-Continent Area Power Pool ("MAPP"), NSP's reserve requirement is determined jointly with the other parties to the MAPP Agreement. Currently, the reserve requirement equals 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 NSP System carried a reserve margin of 23% in 1994. The Company primarily relies on the Minnesota Company, through the Interchange Agreement (see Electric Operations - Interchange Agreement), for base load generation. Approximately 81 percent of the total kilowatt hour requirements of the Company were provided by the Minnesota Company generating facilities or purchases made by the Minnesota Company for system uses in the year 1994. The Company also has two electric steam generating facilities. One is the Bay Front Generating Plant which is located in Ashland, Wisconsin. The plant is fueled primarily by natural gas, coal and wood residue. Recent modifications to the facility allow for more effective utilization of additional waste wood fuel supplies and have extended the useful life of the facility approximately 20 years from their completion in 1992. In 1992 the Company received authorization from the Wisconsin Department of Natural Resources ("DNR") to burn tire derived fuel on a regular basis. The Company's second electric steam generating plant is the French Island plant located in La Crosse, Wisconsin, which has two fluidized bed boilers modified for the purpose of burning a mixture of waste wood and RDF. The Bay Front plant in Ashland and the French Island steam plant are primarily used on an intermediate load basis. The Company's thermal peaking capability consists of two oil-fired gas turbine peaking plants and a gas and oil turbine peaking plant. The Company also has 19 hydro plants that operate as peaking facilities or run-of-river facilities. Interchange Agreement The electric production and transmission costs of the NSP System are shared by the Company and the Minnesota Company. The cost-sharing arrangement between the companies is the Agreement to Coordinate Planning and Operation and Interchange Power and Energy between Northern States Power (Minnesota) and Northern States Power (Wisconsin) ("Interchange Agreement"). It is a FERC regulated agreement and has been accepted by the PSCW and the MPSC for determination of costs recoverable in rates by the Company for charges from the Minnesota Company in rate cases. Historically the Company's share of the NSP System annual production and transmission costs has been in the 14 to 17 percent range. Revenues received from billings to the Minnesota Company for its share of the Company's production and transmission costs are recorded as electric operating revenues on the Company's income statement. The portions of the Minnesota Company's production and transmission costs that were charged to the Company were recorded as purchased and interchange power expenses and other operation expenses, respectively, on the Company's income statement. (See Note 6 to Financial Statements). Under the Interchange Agreement, the Company could be charged a portion of the cost of an assessment made against the Minnesota Company pursuant to the Price-Anderson liability provisions of the Atomic Energy Act of 1954. (See Note 3 to Financial Statements). Electric Power Pooling Agreements Many of NSP's power purchases from other utilities are coordinated through the regional power organization MAPP, pursuant to an agreement dated March 31, 1972. NSP is one of 49 participants in MAPP consisting of 10 investor-owned systems, eight generation and transmission cooperatives, three public power districts, seven municipal systems and the Department of Energy's Western Area Power Administration, and 20 Associate Participants. The MAPP agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The 1972 MAPP agreement was accepted for filing with the FERC, effective Dec. 1, 1972. Fuel Supply In 1994 the Company shared in the fuel supply costs incurred by the Minnesota Company in accordance with the Interchange Agreement. Coal and nuclear fuel will continue to dominate the NSP System fuel requirements for the generation of electricity. It is expected that approximately 98 percent of the NSP System annual fuel requirements will be provided by these two sources and that 2 percent of NSP's annual fuel requirements for generation will be provided by other fuels (including natural gas, oil, refuse derived fuel, waste materials, and wood) over the next several years. Fuel Use on Btu Basis (Est.) (Est.) 1994 1995 1996 Coal 60.9% 61.1% 63.1% Nuclear 37.4% 37.1% 35.1% Other * 1.7% 1.8% 1.8% * Includes oil, gas, refuse derived fuel and wood Electric Operating Statistics The follow table summarizes the revenues, sales and customers from NSP's electric business: Operating Statistics 1994 1992 1991 1990 y contracted winter peaking supplies thus reducing costs and providing greater reliability. The Company is continuing its pursuit of growth and profitability through expansion of its distribution system and services both inside and outside of its existing service territories. In 1994 the Company extended service to the communities of Fall Creek and Elk Mound. Applications for Certificates of Authority have been filed with the PSCW to serve filed with the PSCW to serve the Township of Pleasant Valley, the Town of Washington, and the Townships of Tainter and Cedar Falls. On March 14, 1995, the Company received approval of its application to provide gas service to Pleasant Valley in the Town of Washington. The Company began limited services under a pilot project approved by the PSCW which allows the Company to take advantage of its unique position in the United States and Canadian supply markets. Examples of non-traditional activities may include: energy management services, sales of unused system supply if profitable, and brokerage of gas not purchased or required for system needs. These non-traditional marketing opportunities are a result of deregulation in the natural gas industry. Traditional regulated services would not have allowed a mark-up on gas costs. ENVIRONMENTAL MATTERS The Wisconsin DNR has been authorized by the United States Environmental Protection Agency to administer the National Pollutant Discharge Elimination System Permits under the Federal Water Pollution Control Act Amendments of 1977. Such permits are required for the lawful discharge of any pollutant into navigable waters from any point source (e.g. power plants). Permits have been issued for all of the Company's affected plants and all plants are in compliance with permit requirements. The DNR has jurisdiction over emissions to the atmosphere from the Company's power plants. The operation of the Company's generating plants substantially conforms to federal and state limitations pertaining to discharges to the air. Occasional, infrequent exceedances of Wisconsin DNR air emission limitations occurred in 1994 at the Company's Bay Front facility. These are being resolved through operating changes and the installation of continuous emission monitors and no agency enforcement action has resulted. The Company presently operates hydro, coal, natural gas, tire-derived fuel, railroad tie, oil-fired, wood and refuse- derived fuel/wood-fired generation equipment. Regulatory approval is required for the construction of generating plants and major transmission lines. Also, additional regulations have been instituted governing the use, transport, disposal and inspection of hazardous material and electrical equipment containing polychlorinated biphenyls. The Company has procedures in place to comply with these regulations. The NSP Wisconsin policy is to proactively prevent adverse environmental impacts, regularly monitor operations to ensure the environment is not adversely affected, and take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. The Company strives to maintain compliance with all applicable environmental laws. Both the Company and the Minnesota Company have received notices for requests for information concerning groundwater contamination at a landfill site in Wisconsin. While neither the Company nor the Minnesota Company have been named potentially responsible parties (PRP's), both companies voluntarily joined a group of other parties to address the contamination at this site. A preliminary estimate of total remediation costs at the site is approximately $6 million. The Company's and the Minnesota Company's share of this cost is currently estimated to be approximately 1%. The Company's share alone is estimated to be $20,000. In addition, the administrator of a group of PRP's has notified the Company that it might be responsible for cleanup of a solid and hazardous waste landfill site. The Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined, it is not feasible to predict the outcome of the matter at this time. On March 2, 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Company that it is a PRP on a creosote/coal tar contamination site in Ashland, WI. The Company has informed the WDNR of its belief that two sites exist. The first site, formerly a coal gas plant site, is NSP property. The second site is adjacent to the NSP site and is not owned by the Company. An existing condition report has been completed on an adjacent site. An estimate of site remediation costs, and the extent of the Company's responsibility, if any, for sharing such costs, is not known at this time. Investigations are underway to determine the Company's responsibility as well as that of predecessor companies contributing to the contamination on the adjacent site. The current estimate of the Company's share of future remediation costs at the NSP site is less than $500,000. This estimate is not based upon a formal remediation investigation and feasability study. To the Company's knowledge, no study has been completed for the adjacent site, that describes remedial alternatives and clean-up cost estimates. The Company intends to seek rate recovery of significant costs it incurs associated with the clean-up of either Ashland Site. In late December 1994, the Company completed installation of a control center monitoring system at the Bay Front generating plant in Ashland, Wisconsin. The control center which will monitor emission from the four generating units, was mandated by the Clean Air Act. The total cost of the project was approximately $1.3 million. CONSTRUCTION AND FINANCING Expenditures for the Company's construction program in 1994 totaled $53 million. The 1995 construction expenditures are estimated to be $55.2 million with approximately $33.7 million for electric facilities, $5.8 million for gas facilities and $15.7 million for general plant and equipment. Expenditures for the Company's construction programs for the next five-year period 1995-1999, are estimated to be as follows: Year Estimated Construction Expenditures 1995 $ 55 million 1996 $ 53 million 1997 $ 59 million 1998 $ 62 million 1999 $ 57 million TOTAL $286 million It is presently estimated that approximately 93 percent of the 1995-1999 construction expenditures will be provided by internally generated funds and the remainder from short-term and long-term external financing. At December 31, 1994, the Company's short-term borrowings outstanding were $41.3 million. The foregoing estimates of 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. During the five years ended December 31, 1994, the Company had gross additions to utility plant in service of approximately $250.3 million. Included in the Company's gross additions is $28.2 million for electric production facilities, $153.7 million for other electric properties, $37.6 million for gas utility properties, and $30.8 million for other utility properties. Retirements during the same period were approximately $37.0 million. Based on studies made by the Company, the weighted average age of depreciable property was 12.5 years at December 31, 1994. EMPLOYEES AND EMPLOYEE BENEFITS At year end 1994 the total number of full- and part-time employees of NSP-Wisconsin was approximately 955. About 430 employees of NSP are represented by one local IBEW labor union. On May 2, 1994, the IBEW members voted to ratify a three year labor agreement retroactive to Jan. 1, 1994. Labor and employee benefit costs are not expected to be materially affected by the terms of the new agreement. NSP recently reviewed employee and retiree benefits and implemented the following changes effective in 1994. These changes support NSP's goal of providing market-based benefits, and did not materially affect employee compensation and benefit costs in 1994. Active nonbargaining medical premium increases: A two-year cost sharing strategy for medical benefits for nonbargaining employees was implemented in 1994. The strategy consisted of employees contributing 10% in 1994 and 20% in 1995 of the total medical cost. 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 outlined. Nonbargaining pension plan lump sum option changes: Prior to 1994, nonbargaining employees had the option to receive their pension in either a lump sum or in monthly installments. Beginning in 1994, nonbargaining employees can choose a lump sum distribution in 25% increments upon termination of employment. Employees taking less than 100 percent will receive the rest of their benefits in monthly installments. At the end of 1994, this benefit was modified to allow a lump sum option only on the portion of pension benefit earned through Dec. 31, 1994. 401(k) changes: NSP currently offers eligible employees a 401(k) Retirement Savings Plan. In 1994, NSP matched employees' pre-tax 401(k) contribution up to $500 per year for nonbargaining employees and up to $400 per year for bargaining. In 1995, NSP's annual match will increase to $700 for nonbargaining employees. Under the terms of the bargaining agreement implemented in 1994, NSP's annual match will increase to $500 in 1995 and $600 in 1996. Wage increases: No base wage scale increases were implemented in January 1994. In 1994 bargaining employees received 3.0% lump sum payment. Effective in 1994, NSP implemented a market-based pay structure for nonbargaining employees. NSP's new pay system uses the latest salary surveys that indicate how local and regional companies pay their employees for comparable positions. In January 1995, nonbargaining employees will receive an average wage scale increase of 3.5%, while bargaining employees will receive a 2% wage base increase and a 1.5% lump sum payment. Item 2. Properties Electric Utility The Company's major electric generating facilities consist of the following: Projected Year 1994-5 Winter Station and Units Fuel Installed Capability (MW) Combustion Turbine: Flambeau Station Gas/Oil 1969 17 (1 unit) Park Falls, WI Wheaton Oil 1973 440 (6 units) Eau Claire, WI French Island Oil 1974 192 (2 units) La Crosse, WI Steam: Bay Front Coal/Wood/ 1960-1974 73 (3 units) Gas Ashland, WI French Island Wood/RDF 1940-1948 29 (2 units) La Crosse, WI Hydro Plants: (19 plants) - Various dates 248 TOTAL 999 At December 31, 1994, the Company owned approximately 2,394 pole miles of overhead electric transmission lines, 8,044 pole miles of overhead electric distribution lines, 37 conduit miles and 1,011 direct buried cable miles of underground electric lines. Virtually all of the land and personal property owned by the Company is subject to the lien of their first mortgage bond indentures pursuant to which they have issued first mortgage bonds. Gas Utility The gas properties of the Company include approximately 1,399 miles of natural gas distribution mains. The Company owns two liquefied natural gas facilities with a combined storage capacity of the equivalent of 400,000 Mcf to supplement the available pipeline supply of natural gas during periods of peak demands. The two liquified natural gas facilities are located in Eau Claire and La Crosse, Wisconsin. In January of 1993, the Company installed temporary propane air facilities with a capacity of 144,000 gallons to further supplement its gas supply in the La Crosse, Wisconsin area during peak periods. Item 3. Legal Proceedings The Company is currently involved in various claims and lawsuits incidental to its business. In the opinion of management, if the Company were ultimately found to be liable in these claims and lawsuits, such liability would not have a material effect on the financial statements of the Company. Item 4. Submission of Matters to a Vote of Security Holders Omitted per conditions set forth in general instruction J (1) and (a) and (b) of Form 10-K for wholly-owned subsidiaries (reduced disclosure format). PART II Item 5. Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters This is not applicable as the Company is a wholly owned subsidiary. Item 6. Selected Financial Data This is omitted per conditions set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations Management's Discussion and Analysis of Financial Condition and Results of Operations is omitted per conditions as set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management's narrative analysis of the results of operations set forth in general instructions J (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). This analysis will primarily set forth the Company's accounting changes and compare its revenue and expense items for the year ended December 31, 1994 with the year ended December 31, 1993. The Company's net income for year ended December 31, 1994 was $38.5 million, up from the $38.0 million earned in the same period of 1993. The 1994 operating income decreased by $0.2 million from the 1993 level. Accounting Changes Postemployment Benefits During 1994, the Company adopted SFAS No. 112 - Employers' Accounting for Postemployment Benefits. SFAS No. 112 requires the accrual of certain employee costs (such as injury compensation and severance) to be paid in future periods. Its adoption did not have a material effect on the Company's results of operations or financial condition. Electric Sales and Revenues Electric revenues for 1994 increased $12.3 million, a 3.4 percent increase from the 1993 revenues. Revenues from retail sales, which accounted for 75 percent of the electric revenues in 1994, increased $8.8 million or 3.2 percent. Residential sales growth in 1994 was 0.9%. Included in the 1994 retail increase is $5.9 million related to the Company's large commercial and industrial customers, some of which expanded their operations, increasing energy needs. Also reflected in the retail revenue increase is a decrease of $0.6 million due to the cooler summer weather of 1994. The Company's wholesale customers accounted for 4.6 percent of the total electric revenues. Wholesale revenues increased $1.4 million or 8.8 percent in 1994. In addition to fuel clause revenues having increased, there was a 5.0 percent growth in sales for resale. Long-term contracts signed with five wholesale customers during 1994 did not materially affect revenues. Another major component (approximately 19.6 percent) of electric revenues is charges billed to the Minnesota Company through the Interchange Agreement (see Part I, Item 1; Business- Electric Operations). Interchange Agreement billings charged to the Minnesota Company increased $1.3 million as a result of increased fuel being burned in the Wisconsin Company to support the systems' increased requirements. Other electric revenues increased $0.8 million in 1994, largely due to an increase in recorded fuel clause adjustments. Gas Sales and Revenues Gas revenues in 1994 increased by $4.0 million or 5.4 percent as compared with 1993. This is the net impact of increased revenues due to the $1.4 million rate increase effective January 1994, increased revenues due to a 1.8% increase in firm sales due to customer and usage growth, and decreased revenues of $1.1 million due to 1994's comparably more moderate winter weather. Operating Expenses and Other Factors Electric Production The cost of interchange power increased $11.6 million or 7.2 percent in 1994 compared to the same period one year ago. This expense represents charges billed from the Minnesota Company through the Interchange Agreement (see Part I, Item 1: Business-Electric Operations). The company's increased electric sales during 1994 over 1993, combined with increased costs per MWH for nuclear and fossil fuels and increased costs associated with capacity charges from the power purchase agreements with Manitoba Hydro-Electric Board, which went into effect in May 1993, resulted in the company's purchased power and fuel purchased under its interchange agreement with its parent to increase by approximately $10.7 million. Total interchange power also increased by $0.4 million as a result of increased operation and maintenance expenses and by $0.5 million as a result of increased fixed charges such as depreciation and property taxes. Fuel for Electric Generation Fuel for electric generation, which represents the Company's portion of the NSP System's fuel generation, increased $2.2 million or 70.0 percent in 1994 from 1993. This is due to the Minnesota Company's decreased fuel generation combined with the Company's increased requirements due to the increased sales in 1994. Gas Purchased for Resale This cost increased $2.0 million or 3.9 percent. A seven percent increase in total gas deliveries was responsible for $3.6 million of increase in 1994. A 1.3 percent decrease in prices resulted in the balance of the change from 1993. Administrative and General, Other Operation and Maintenance The $1.6 million increase in Other Operation expense is partially due to demand side management expense increases ($0.7 million) and increases in transmission expenses charged from the Minnesota Company ($0.3 million). The remaining increases were related to postemployment benefit costs and general increases in operating expenses. Depreciation and Amortization The increase in depreciation between 1994 and 1993 primarily reflects higher levels of depreciable plant, particularly shorter-lived computer equipment. Property and General Taxes The property and general taxes increase is primarily due to higher gross receipts tax (a tax assessed on prior year revenues) as a result of 1993 revenues increasing over 1992 revenues. Income Taxes $2.2 million of the decrease in income taxes in 1994 below 1993 is the result of a non-recurring adjustment to the balance of the tax accruals for prior years due to the recent conclusion by the Internal Revenue Service of audits of all the Company's tax years through 1988. The balance of the change is primarily attributable to the decrease in pretax book income. See Note 8 to the Financial Statements for a detailed reconciliation of effective tax rates and statutory rates. Allowances for Funds Used During Construction (AFC) The differences in AFC for the reported periods are attributable to varying levels of qualifying construction and lower AFC rates associated with increased use of low-cost short-term borrowings. Interest Charges In March 1993, the Company issued $110.0 million of first mortgage bonds due March 1, 2023 with an interest rate of 7-1/4%. The proceeds from these bonds were used to redeem $47.5 million of 9-1/4% bonds, $38.4 million of 9- 3/4%bonds, and $7.8 million of 9-1/4% bonds. In October 1993, the Company issued $40.0 million of first mortgage bonds due October 1, 2003 with an interest rate of 5-3/4%. The proceeds from these bonds were used to redeem $24.3 million of 7-3/4% bonds and $10.8 million of 4-1/2% bonds. These transactions caused decreases in the 1994 interest and amortization charges compared to the charges of 1993 because in 1993 for one year only, all costs associated with the redemption of these bonds were treated on a basis by which all savings of interest due to refinancing was offset by the amortization of the costs as required and approved by the PSCW. In February 1995, the Company purchased $2.9 million of it's 9 1/8 Series bonds at the rate of 101 1/8. Item 8 Financial Statements and Supplementary Data See Item 14(a)-1 in Part IV for financial statements included herein. See Note 12 to the financial statements for summarized quarterly financial data. INDEPENDENT AUDITORS' REPORT Northern States Power Company (Wisconsin): We have audited the accompanying financial statements, of Northern States Power Company (Wisconsin), listed in the accompanying table of contents of Item 14(a)1. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1994 and 1993 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Minneapolis, Minnesota January 27, 1995 Item 8 Financial Statements and Supplementary Data Statements of Income and Retained Earnings Year Ended December 31 (Thousands of dollars) 1994 1993 1992 Operating Revenues Electric $ 374 777 $ 362 473 $ 345 289 Gas 76 715 72 760 61 071 Total 451 492 435 233 406 360 Operating Expenses Purchased and interchange power 174 144 162 510 156 196 Fuel for electric generation 5 414 3 185 2 034 Gas purchased for resale 53 484 51 501 41 814 Administrative and general 26 487 26 842 21 610 Other operation 44 260 43 351 42 254 Conservation 7 211 6 556 5 216 Maintenance 22 385 21 703 21 806 Depreciation and amortization 30 736 28 585 26 832 Property and general taxes 13 710 13 091 12 925 Income taxes 19 077 23 103 22 184 Total operating expenses 396 908 380 427 352 871 Operating Income 54 584 54 806 53 489 Other Income and Deductions Allowance for funds used during construction-equity 671 694 907 Other income and deductions 864 844 1 361 Total Other Income 1 535 1 538 2 268 Income Before Interest Charges 56 119 56 344 55 757 Interest Charges Interest on long-term debt 15 995 16 343 17 269 Other interest and amortization 2 060 2 406 857 Allowance for funds used during construction-debt (481) (411) (569) Total interest charges 17 574 18 338 17 557 Net Income 38 545 38 006 38 200 Retained Earnings, January 1 205 114 192 816 179 510 Dividends (24 826) (25 708)(24 894) Retained Earnings, December 31 $ 218 833 $ 205 114 $ 192 816 See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data Statements of Cash Flow Year Ended December 31 (Thousands of dollars) 1994 1993 1992 Cash Flows from Operating Activities: Net Income $38 545 $38 006 $38 200 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 32 382 33 580 28 179 Deferred income taxes 7 614 7 228 3 089 Investment tax credit adjustments (943) (948) (956) AFC-equity (671) (694) (907) Insurance receivable (3 091) Other (6 076) (2 440) Cash (used for) provided by changes in certain working capital items (9 568) 299 2 438 Net Cash Provided by Operating Activities58 192 77 471 67 603 Cash Flows from Financing Activities: Proceeds from issuance of long-term debt 0 146 587 0 Proceeds from issuance of notes payable-parent company 17 800 0 12 600 Repayment of notes payable-parent company 0 (800) 0 Repayment of long-term debt (990) (136 090) (1 415) Dividends paid to parent (24 826) (25 708) (24 894) Net Cash Used for Financing Activities (8 016) (16 011) (13 709) Cash Flows from Investing Activities: Construction expenditures capitalized (52 639) (59 954) (54 588) Decrease in construction payables (633) (2 143) (2 013) AFC-equity 671 694 907 Other 2 037 (489) 0 Net Cash Used for Investing Activities (50 564) (61 892) (55 694) Net Decrease in Cash (388) (432) (1 800) Cash at Beginning of Period 449 881 2 681 Cash at End of Period $ 61 $ 449 $ 881 Cash (used for) provided by changes in certain working capital items: Accounts receivable-net $ 770 $ (1 597) $ 921 Materials and supplies( (4 708) (453) (647) Accounts payable and accrued liabilities 332 7 633 412 Payables to affiliated companies (2 655) 127 2 444 Income and other taxes accrued (4 174) (2 762) 634 Other 867 (2 649) (1 326) Net $ (9 568) $ 299 $ 2 438 Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $ 15 870 $ 17 440 $ 17 136 Income taxes $18 773 $ 18 825 $ 19 256 See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data Balance Sheets December 31 (Thousands of dollars) 1994 1993 Assets Utility Plant Electric-including construction work in progress: 1994, $14,599; 1993, $16,697 $ 836 665 $ 810 691 Gas 88 350 81 567 Other 54 675 43 279 Total 979 690 935 537 Accumulated provision for depreciation (344 675) (320 938) Net utility plant 635 015 614 599 Other Property and Investments Nonutility property - at cost 3 082 3 157 Accumulated provision for depreciation (365) (364) Other investments - at cost which approximates market 3 974 4 094 Total other property and investments 6 691 6 887 Assets Cash 61 449 Accounts receivable 37 484 38 424 Accumulated provision for uncollectible accounts (538) (708) Materials and supplies - at average cost Fuel 3 413 2 293 Other 12 280 8 692 Accrued utility revenues 16 409 17 230 Prepayments and other 11 030 9 855 Deferred tax asset 1 415 1 254 Total current assets 81 554 77 489 Other Assets Unamortized debt expense 2 928 3 078 Regulatory assets 31 376 30 036 Federal Income tax receivable 3 307 0 Insurance receivable 3 091 0 Other 4 338 4 890 Total deferred debits 45 040 38 004 Total $ 768 300 $ 736 979 See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data December 31 (Thousands of dollars) 1994 1993 Liabilities and Equity Capitalization Common stock-authorized 870,000 shares of $100 par value; issued shares: 1994 and 1993, 862,000 $ 86 200 $ 86 200 Premium on common stock 10 461 10 461 Retained earnings 218 833 205 114 Total common equity 315 494 301 775 Long-term debt 213 700 217 600 Total capitalization 529 194 519 375 Current Liabilities Notes payable - parent company 41 300 23 500 Long-term debt due within one year 2 910 0 Accounts payable 14 415 15 264 Salaries, wages, and vacation pay accrued 6 028 5 481 Payables to affiliated companies (principally parent) 8 982 11 636 Federal income taxes accrued 0 1 606 Other taxes accrued 936 2 492 Interest accrued 5 485 4 823 Other 1 463 1 917 Total current liabilities 81 519 66 719 Deferred Credits Accumulated deferred income taxes 99 748 88 426 Accumulated deferred investment tax credits 22 332 23 653 Regulatory liability 17 961 22 416 Customer advances 5 543 5 071 Other 12 003 11 319 Total deferred credits 157 587 150 885 Commitments and Contingent Liabilities Total $ 768 300 $ 736 979 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"), maintains the accounting records in accordance with either the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) or those prescribed by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC), which systems are the same in all material respects. Investment in Subsidiaries The Company carries its investment in its subsidiaries (Chippewa and Flambeau Improvement Company, 75.86% owned; NSP Lands, Incorporated, 100% owned; and Clearwater Investments, Incorporated, 100% owned) at cost plus equity in earnings since acquisition. The impact of consolidation of these subsidiaries is considered immaterial to the Company's financial position. 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. Insurance Receivable The Company has incurred repair costs on a gas turbine that will be recovered from insurance. These costs have caused the Company to pay out approximately $ 3 million. Federal Income Tax Receivable The Company has filed an amended tax return for the year 1992 which has resulted in a reduction in taxes owed of approximately $3.3 million. The two major items for the Wisconsin Company were the additional deduction for the prepaid Wisconsin Annual License Fee and an additional deduction for a change in Depreciation Expense. Allowance for Funds Used during Construction (AFC) AFC, a non-cash item, is computed by applying a composite pretax rate, representing the cost of capital used to fund utility construction, to qualified Construction Work in Progress (CWIP). The rates used for the FERC calculation were 7.55 percent in 1994, 7.93 percent in 1993 and 8.78 percent in 1992. The rates used for the PSCW calculation were 10.13 percent in 1994, 10.84 percent in 1993 and 11.52 percent in 1992. 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. Related Party Transactions All significant intercompany transactions and balances have been eliminated in consolidation except for intercompany and intersegment profits for sales among the electric and gas utility businesses of the Company, the Minnesota Company and Viking, which are allowed in utility rates. 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 3.45% in 1994, 3.40% in 1993, and 3.38% in 1992. Revenues Customers' meters are read and bills rendered on a cycle basis. The Company accrues the amount of estimated unbilled revenues for services provided from the monthly meter reading date to month-end. The current asset, accrued utility revenues, is being adjusted monthly, with a corresponding adjustment to revenues, to reflect changes in unbilled revenues. Regulatory Deferrals As a regulated utility, the Company accounts for certain income and expense items under the provisions of 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. Income Taxes The Company records income taxes in accordance with Statement of Financial Accounting Standards No. 109 (SFAS 109) - Accounting For Income Taxes. SFAS 109 requires the use of the liability method of accounting for deferred income taxes. Before 1993, the Company followed Statement of Accounting Standards No. 96 (SFAS 96) - Accounting for Income Taxes, resulting in substantially the same accounting for the Company as SFAS No. 109. Income taxes are deferred for temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. Due to the effects of regulation, income tax expense is provided for the reversal of some temporary differences previously accounted for by the flow-through method. Deferred income tax expense for 1994, 1993, and 1992 consists primarily of excess tax depreciation over book depreciation of $4,800,000, $5,413,000, and $5,526,000, respectively. Investment tax credits are deferred and amortized over the estimated lives of the related property. Purchased Tax Benefits The Company purchased tax-benefit transfer leases under the Safe Harbor Lease provisions of the Economic Recovery Tax Act of 1981. For both financial reporting and regulatory purposes, the Company is amortizing the difference between the cost of the purchased tax benefits and the amounts to be realized through reduced current income tax liabilities over the remaining terms of the lease after the initial investments have been recovered. Environmental Costs Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. When a single estimate of the liability cannot be determined, the low end of the estimated range is recorded. Costs are charged to expense (or deferred as a regulatory asset based on expected recovery from customers in future rates) if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures related 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 NSP has been designated as one of several potentially responsible parties, the amount accrued represents NSP's estimated share of the cost. NSP intends to treat any future costs related to decommissioning and restoration of its power plants and substation sites as a removal cost of retirement through plant depreciation expense. 2. Rate Matters The Company filed a proposal for a new high load factor rate with the PSCW in November, 1994, that becomes effective January 1, 1995. Under the proposal, qualifying customers would receive a credit on their bills of up to 3.0% depending on their load factor. This is expected to reduce 1995 revenues by approximately $1.5 million. On December 23, 1993, the PSCW issued an order approving a $1.41 million (2.0 percent) increase on an annual basis in the Company's gas rates. A January 1, 1994 effective date was authorized for these rate changes. No change in the retail electric rates was requested. The Company will file a submittal in June 1995 as required by the PSCW biennial filing requirement. In May, 1994, the Company offered its municipal wholesale customers a discount of one to two percent off the FERC authorized rate for a long-term full requirements commitment between five and ten years with comparable cancellation notices. Five of the ten municipal wholesale customers signed up for the discounts. The total annual decrease in revenues is approximately $80,000. 3. Accounting Changes Postemployment Benefits Effective January 1, 1994, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 112---Employer's Accounting for Postemployment Benefits. This standard required the accrual of certain postemployment costs (such as injury compensation and severance) that are payable in future time periods. The annual expense for costs accrued under SFAS No. 112 is not materially different than amounts recognized under the Company's prior accounting method. The Company has recorded as expense its full liability related to such costs in 1994. 4. Investments Accounted for by the Equity Method NSP has subsidiaries with investments in domestic affordable housing and real estate projects. The equity method of accounting is applied to such investments. 5. Long-Term Debt First Mortgage Bonds - less reacquired bonds of $490 and $0 at December 31, 1994 and 1993, respectively: December 31 December 31 Series due: 1994 1993 Apr. 1, 2021, 9-1/8% $ 48 010 $ 49 000 Mar. 1, 2023, 7 1/4% 110 000 110 000 Oct. 1, 2003, 5 3/4% 40 000 40 000 Total $198 010 $199 000 Less April 1, 2021, 9 1/8% bonds redeemed in February 1995 2 910 Net $195 100 $199 000 City of LaCrosse Resource Recovery Revenue Bonds - Series due Nov. 1, 2011, 7 3/4% 18 600 18 600 Total long-term debt $ 213 700 $ 217 600 The Supplemental and Restated Trust Indenture dated March 1, 1991, permits an amount of established Permanent Additions to be deemed equivalent to the payment of cash necessary to redeem 1% of the highest principal amount of each series of first mortgage bonds (other than pollution control financing) at any time outstanding. This Supplemental and Restated Trust Indenture became effective for the Company on October 1, 1993. On March 16, 1993 the Company issued $110.0 million of first mortgage bonds due March 1, 2023, with an interest rate of 7 1/4%. NSP entered into an interest rate swap agreement with $20.0 million of this first mortgage bonds. This agreement effectively converts the interest costs of this debt issue from fixed to variable rates based on six-month London Interbank Offered Rates (LIBOR) with the rates changing semi-annually, March 1 and September 1. This Series is due March 1, 2023, has a Swap Agreement Term dated March 1, 1998 and had a net effective interest rate of 7.43% at December 31, 1994. Market risks associated with this agreement results from short-term interest rate fluctuations. Credit risk related to non- performance of the counterparties is not deemed significant, but would result in NSP terminating the swap transaction and recognizing a gain or loss, depending on the fair market value of the swap. While such agreements are not reflected on NSP's balance sheets, interest rate swap transactions are recognized as an adjustment of interest expense over the terms of the agreements. The interest rate swaps serve to hedge the interest rate risk associated with fixed rate debt in a declining interest rate environment. This hedge is produced by the tendency for changes in the fair market value of the swap to be offset by changes in the present value of the liability attributable to the fixed rate debt issued in conjunction with the interest rate swap. If the interest rate swap had been terminated at Dec. 31, 1994, $1.7 million would have been payable by NSP while the present value of the fixed rate debt issued with the swaps was $3.1 million below par value. On February 1, 1995, the Company redeemed $2.9 million of its 9 1/8% bonds at 101-1/8%; this amount has, therefore, been classified as current on the December 31, 1994 financial statements. Maturities on capital leases in the next five years are approximately $943,000, $1,034,000, $724,000, $409,000, and $92,000, respectively for the years 1995-1999. Except for minor exclusions, all real and personal property is subject to the lien of the Company First Mortgage Bond Trust Indenture. 6. Commitments and Contingent Liabilities The Company presently estimates capital expenditures will be $55.2 million in 1995 and $286 million for 1995-99. Rentals under operating leases were approximately $1,792,000, $2,651,000, and $2,547,000, for 1994, 1993, and 1992, respectively. Although the Company does not own a nuclear facility, any assessment made against Northern States Power Company (Minnesota), the parent company, ("Minnesota Company") and under the Price- Anderson liability provisions of the Atomic Energy Act of 1954, would be a cost included under the Interchange Agreement (Note 9) and the Company would be charged its proportion of the assessment. Such provisions set a limit of $8.9 billion for public liability claims that could arise from a nuclear incident. The parent company has secured insurance of $200 million to satisfy such claims. The remaining $8.7 billion of exposure is funded by the Secondary Financial Protection Fund, a fund available from assessments by the Federal government in the event of nuclear incidents. The parent company is subject to an assessment of $79.3 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States with a maximum funding requirement of $10 million per reactor during any one year. The NSP Wisconsin policy is to proactively prevent adverse environmental impacts, regularly monitor operations to ensure the environment is not adversely affected, and take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. The Company strives to maintain compliance with all applicable environmental laws. A preliminary allocation has been established for one of the landfills for those contributing any type of wastes to it. Based on the preliminary allocation of costs, the Company's share of one of the landfills would be less than $20,000. An allocation has not yet been made on the second landfill site. On March 2, 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Company that it is a PRP on a creosote/coal tar contamination site in Ashland, WI. The Company has informed the WDNR of its belief that two sites exist. The first site, formerly a coal gas plant site, is NSP property. The second site is adjacent to the NSP site and is not owned by the Company. An existing condition report has been completed on an adjacent site. An estimate of site remediation costs, and the extent of the Company's responsibility, if any, for sharing such costs, is not known at this time. Investigations are underway to determine the Company's responsibility as well as that of predecessor companies contributing to the contamination on the adjacent site. The current estimate of the Company's share of future remediation costs at the NSP site is less than $750,000. This estimate is not based upon a formal remediation investigation and feasability study. To the Company's knowledge, no study has been completed for the adjacent site, that describes remedial alternatives and clean-up cost estimates. The Company intends to seek rate recovery of significant costs it incurs associated with the clean-up of either Ashland Site. 7. Fair Value of Financial Instruments Statement of Financial Accounting Standards No. 107 (SFAS 107) - Disclosures About Fair Value of Financial Instruments became effective in 1992. For cash and investments, the carrying amount approximates fair value. The fair value of the Company's long term debt 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. The estimated fair value of the Company's long term debt (including debt due within one year classified as current) of $216.6 million at December 31, 1994, and $217.6 million at December 31, 1993, is $196.2 million and $233.3 million, respectively. 8. Pension Plans and Other Post Retirement 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. The Company's portion of annual pension costs was $(631,000) for 1994, $1,236,000 for 1993, and $2,400,000 for 1992. Until 1993, for financial reporting and regulatory purposes, the Company's pension expense was determined and recorded under the aggregate cost method, using market value of assets of the trust fund. Statement of Financial Accounting Standards No. 87 - Employers' Accounting for Pensions (SFAS 87) provides that any difference between the pension expense recorded for rate making purposes and the amounts determined under SFAS 87 should be recorded as an asset or liability on the balance sheet. Effective January 1, 1993, for financial reporting and regulatory purposes, the Company's pension expense was determined and recorded under the SFAS-87 method and the Company's accumulated SFAS-87 asset is being amortized over a 15-year period. Net periodic pension costs for the total (the Company and Minnesota Company) plan include the following components: 1994 1993 1992 (Thousands of dollars) Service Cost - benefits earned during the period $ 27 536 $ 25 015 $ 24 080 Interest cost on projected benefit obligation 65 107 71 075 69 853 Actual return on assets (12 668)(152 019)(115 455) Net amortization and deferral (82 114) 66 299 39 019 Net periodic pension cost determined under SFAS 87 (2 139) 10 370 17 497 Expenses recognized (deferred) due to actions of regulators 3 922 5 117 2 741 Pension expense recorded during the period 1 783 15 487 20 238 Portion of expense recognized for early retirement program 0 0 ( 165) Net periodic pension cost recognized for ratemaking $ 1 783 $ 15 487 $ 20 073 The funding status for the total plan is as follows: Actuarial present value of benefit obligation: Vested $ 571 254 $ 655 002 Nonvested 120 420 139 346 Accumulated benefit obligation $ 691 674 $ 794 348 Projected benefit obligation $ 836 957 $974 160 Plan assets at fair value 1 165 584 1 244 650 Plan assets in excess of projected benefit obligation (328 627) (270 490) Unrecognized prior service cost (21 538) (22 580) Unrecognized net (gain) 370 289 315 049 Unrecognized net transitional (asset) 691 767 Net pension liability recorded $ 20 815 $ 22 746 The weighted average discount rate used in determining the actuarial present value of the projected obligation was 8% in 1994 and 7% in 1993. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5% in 1994 and 1993. The assumed long-term rate of return on assets used for cost determinations under SFAS 87 was 8% in 1994, 1993 and 1992. Plan assets consist principally of common stock of public companies and U.S. Government Securities. Effective Jan. 1, 1993, the Company adopted the provisions of SFAS No. 106 - Employers' Accounting for Postretirement Benefits Other Than Pensions. SFAS No. 106 requires that the actuarially determined obligation for postretirement health care and death benefits is to be fully accrued by the date employees attain full eligibility for such benefits, which is generally when they reach retirement age. This is a significant change from the Company's pre-1993 policy of recognizing benefit costs on a cash basis after retirement. In conjunction with the adoption of SFAS No. 106, for financial reporting purposes, NSP elected to amortize on a straight-line basis over 20 years the unrecognized accumulated postretirement benefit obligation (APBO) of approximately $215.6 million (including the Company and Minnesota Company) for current and future retirees. This obligation considered 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity measures not in effect in 1993. Before 1993, NSP funded payments for retiree benefits internally. While the Company generally prefers to continue using internal funding of benefits paid and accrued, there have been some external funding requirements imposed by the Company's regulators, as discussed below, including the use of tax advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1994, consisted of investments in equity mutual funds and cash equivalents. The following table sets forth the total (the Company and Minnesota Company) health care plans funded status at December 31. (Millions of dollars) 1994 1993 APBO: Retirees $132.2 $120.2 Fully eligible plan participants 21.5 18.8 Other active plan participants 79.4 90.8 Total APBO 233.1 229.8 Plan Assets 8.0 6.1 APBO in excess of plan assets 225.1 223.7 Unrecognized net actuarial gain (loss) 2.3 (1.3) Unrecognized transition obligation (194.0) (204.8) Postretirement benefit obligation included in balance sheet $ 33.4 $ 17.6 The assumed health care cost trend rate used in measuring the APBO at Dec. 31, 1994 and 1993, respectively, were 11.0 and 14.1 percent for those under age 65 and 7.5 and 8.0 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 5.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. A one percent increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31, 1994, by approximately 13 percent and service and interest cost components of the net periodic postretirement cost by approximately 16 percent. The assumed discount rate used in determining the APBO was 8 percent for Dec. 31, 1994, 7 percent for Dec. 31, 1993 and 7 percent for Jan. 1, 1993, compounded annually. The assumed long- term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for all periods. While the 1994 assumption changes had no effect on 1994 benefit costs, the effect of the changes in 1995 is expected to be a cost increase of approximately $0.6 million (for the Company and the Minnesota Company). Similarly, the assumption changes made for the Dec. 31, 1993 calculations had no effect on 1993 benefit costs, but decreased 1994 costs by approximately $2 million (for the Company and the Minnesota Company). In 1992, the Company recognized $1.9 million as the cost attributable to postretirement health care and death benefits based on payments made. The net annual periodic postretirement benefit cost recorded for 1994 and 1993 consists of the following components (millions of dollars): 1994 1993 Service cost-benefits earned during the year $ 0.6 0.6 Interest cost (on service cost and APBO) 2.3 2.4 Amortization of transition obligation 1.5 1.5 Return on assets (.2) (.1) Net periodic postretirement health care cost under SFAS No. 106 4.2 4.4 The Company's regulators have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. External funding was 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 in 1993. 401(k) NSP has a contributory, defined contribution Retirement Savings Plan (the Plan), which complies with section 401-K of the Internal Revenue code and covers substantially all employees. The NSP match to this Plan began in 1994 and is required to match a specified amount of employee contributions. The Company's contribution to the Plan in 1994 was $0.3 million. 9. Parent Company and Intercompany Agreements The Company is wholly-owned by Northern States Power Company (Minnesota). The electric production and transmission costs of the NSP system are shared by the Company and the Minnesota Company. A FERC approved agreement (Interchange Agreement) between the Company and the Minnesota Company provides for the sharing of all costs of electric generation and transmission facilities of the NSP System, including capital costs. Billings under the Interchange Agreement and an intercompany gas agreement which are included in the statement of income are as follows: Year Ended December 31 1994 1993 1992 (Thousands of dollars) Operating revenues: Electric $ 73 503 $ 72 162 $ 70 671 Gas 50 56 55 Operating expenses: Purchased &interchg power 174 144 162 510 156 196 Gas purchased for resale 227 267 214 Other operation 12 824 12 515 11 668 10. Regulatory Assets and Liabilities The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheet at Dec. 31: (Thousands of dollars) Amortization Period 1994 1993 AFC recorded in plant on a net-of-tax basis Plant Lives 8 325 8 795 Losses on reacquired debt Term of Debt 10 303 10 857 Conservation and energy management programs Up to 10 years 10 622 8 291 Pensions and other 3-15 years 2 126 2 093 Total Regulatory Assets 31 376 30 036 Excess deferred income taxes collected from customers 2 853 5 914 Investment tax credit deferrals 14 950 15 841 Fuel refunds and other 158 661 Total Regulatory Liabilities 17 961 22 416 The AFC regulatory asset and the tax-related regulatory liabilities result from the Company's adoption of SFAS No. 96 in 1988 and SFAS No. 109 in 1993. The excess deferred income tax liability represents the net amount expected to be reflected in future customer rates based on the collection in prior ratemaking of deferred income tax amounts in excess of the actual liabilities currently recorded by the Company. This excess is the net effect of the use of "flow through" tax accounting in prior ratemaking and the impact of changes in statutory tax rates in 1981, 1986-87 and 1993. This regulatory liability will change each year as the related deferred income tax liabilities reverse. 11. Income Tax Expense The Company is included in the consolidated Federal income tax return filed by the Minnesota Company and files separate state returns for Wisconsin and Michigan. The Company records current and deferred income taxes at the statutory rates as if it filed a separate return for Federal income tax purposes. All tax payments are made directly to the taxing authorities. The total income tax expense differs from the amount computed by applying the Federal income tax statutory rate of 35% to net income before income tax expense. The reasons for the difference are as follows: 1994 1993 1992 (Thousands of dollars) Tax computed at statutory rate $ 20 074 $ 21 387 $20 434 Increases (decreases) in tax from: State income taxes, net of Federal income tax benefit 2 393 3 165 3 037 Allowance for funds used during construction (235) (243) (284) Investment tax credit adjustments - net (943) (948) (956) Use of the flow-through method for depreciation in prior years 551 474 673 Effect of tax rate changes for plant related items (498) (487) (420) Gain on sale of tax benefit transfer leases 0 (88) 0 Non-recurring adjustment for tax accrual of prior years (2 430) Other - net (101) (162) (583) Total income tax expense $ 18 811 $ 23 098 $ 21 901 Effective income tax rate 32.8% 37.8% 36.4% Income tax expense is comprised of the following: Included in income taxes: Current Federal tax expense 8 075 $ 12 919 $15 340 Current state tax expense 2 810 3 180 3 598 Deferred Federal tax expense 7 967 6 173 3 075 Deferred state tax expense 1 168 1 778 1 127 Investment tax credit adjustments - net (943) (948) (956) Total 19 077 23 103 22 184 Included in income deductions: Current Federal tax expense 1 039 875 953 Current state tax expense 216 (90) (123) Deferred Federal and state tax expense (1 521) (790) (1 113) Total income tax expense $ 18 811 $ 23 098 $ 21 901 The components of the Company's net deferred tax liability at Dec. 31 were as follows: (Thousands of dollars) 1994 1993 Deferred tax liabilities: Differences between book and tax bases of property $ 98 526 $ 91 195 Tax benefit transfer leases 4 950 6 146 Regulatory assets 11 626 11 371 Other 3 332 398 Total deferred tax liabilities 118 434 109 110 Deferred tax assets: Deferred investment tax credits 7 409 9 487 Regulatory liabilities 8 955 8 726 Deferred compensation accrued vacation and other reserves not currently deductible 3 155 3 193 Other 582 532 Total deferred tax assets 20 101 21 938 Net deferred tax liability $ 98 333 $ 87 172 The Omnibus Budget Reconciliation Act of 1993 (Act) was signed into law on August 10, 1993, and increased the federal corporate income tax rate from 34 percent to 35 percent retroactive to January 1, 1993. Deferred tax liabilities were increased for the rate change by $2.7 million. However, due to the effects of regulation, earnings were reduced only by immaterial adjustments to deferred tax liabilities related to nonutility operations. 12. Segment Information Year Ended December 31 1994 1993 1992 (Thousands of dollars) Operating revenues: Electric $374 777 $362 473 $345 289 Gas 76 715 72 760 61 071 Total operating revenues $451 492 $435 233 $406 360 Operating income before income taxes: Electric $ 67 164 $ 73 012 $ 70 202 Gas 6 498 4 897 5 471 Total operating income before income taxes $ 73 662 $ 77 909 $ 75 673 Depreciation and amortization: Electric $26 836 $ 25 179 $ 23 870 Gas 3 900 3 406 2 962 Total depreciation & amortization $ 30 736 $ 28585 $26832 Construction expenditures: Electric $ 42 820 $ 49 664 $ 44 332 Gas 9 895 10 258 10 235 Total construction expenditures $ 52 715 $ 59 922 $ 54 567 Net utility plant: Electric $575 059 $560 999 $537 576 Gas 59 956 53 600 47 419 Total net utility plant 635 015 614 599 584 995 Other corporate assets 133 285 122 380 109 474 Total assets $768 300 $736 979 $694 469 13. Short-Term Borrowings The Company had bank lines of credit aggregating $1,000,000 at December 31, 1994. 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 1994 and 1993 there were no bank loans outstanding as the Company obtained short-term borrowings from the Minnesota Company at the Minnesota Company's average daily interest rate, including the cost of their compensating balance requirements. The Company had short-term borrowings of the following for the years ended December 31, 1994 1993 1992 Balance at the end of the period 41 300 23 500 24300 Weighted average interest rate 5.0% 3.3% 3.5% Maximum amount outstanding during the period 45 700 28 200 24 300 Average amount outstanding during the period 13 124 10 693 8 837 Weighted average interest rate during the period 5.0% 3.4% 3.7% 14. Common Stock The Company's common shares have a par value of $100 per share. At December 31, 1994 and 1993, 870,000 shares were authorized and 862,000 shares were issued. 15. Summarized Quarterly Financial Data (Unaudited) Quarter Ended March 31, June 30, September 30 December31 1994 1994 1994 1994 (Thousands of dollars) Operating revenues $ 134 004 $ 100 105 $ 101 100 $ 116 283 Operating income 22 268 7 273 9 416 15 627 Net income 18 306 3 441 4 894 11 904 Quarter Ended March 31, June 30, September 30 December31 1993 1993 1993 1993 (Thousands of dollars) Operating revenues $ 124 285 $ 97 107 $ 97 821 $ 116 020 Operating income 20 080 10 199 7 986 16 541 Net income 15 857 6 062 3 762 12 325 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure During 1994 there were no disagreements with the Company's independent certified public accountants on accounting procedures or accounting and financial disclosures. PART III Part III of Form 10-K has been omitted from this report in accordance with conditions set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries. Item 10. Directors and Executive Officers of the Registrant Item 11. Executive Compensation Item 12. Security Ownership of certain beneficial Owners and Management Item 13. Certain Relationships and Related Transactions PART IV Item 14. Exhibits, Financial Statement Schedules Page and Reports on Form 8-K (a) 1. Financial Statements Included in Part II of this report: Report of Independent Public Accountants. 13 Statements of Income and Retained Earnings for the three years ended December 31, 1994. 14 Statements of Cash Flows for the three years ended December 31, 1994. 15 Balance Sheets, December 31, 1994 and 1993. 16 Notes to Financial Statements. 18 2. Financial Statement Schedules Schedules above 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 December 23, 1987. (Filed as Exhibit 30.01 to Form 10-K Report 10-3140 for the year 1987) 3.02* Copy of the By-Laws of the Company as amended August 19, 1992. (Filed as Exhibit 3.02 to Form 10-K Report 10-3140 for the year 1992) 4.01* Copy of Trust Indenture, dated April 1, 1947, From the Wisconsin Company to First Wisconsin Trust Company. (Filed as Exhibit 7.01 to Registration Statement 2-6982) 4.02* Copy of Supplemental Trust Indenture, dated March 1, 1949. (Filed as Exhibit 7.02 to Registration Statement 2- 7825) 4.03* Copy of Supplemental Trust Indenture, dated June 1, 1957. (Filed as Exhibit 2.13 to Registration Statement 2- 13463) 4.04* Copy of Supplemental Trust Indenture, dated August 1, 1964. (Filed as Exhibit 4.20 to Registration Statement 2- 23726) 4.05* Copy of Supplemental Trust Indenture, dated December 1, 1969. (Filed as Exhibit 2.03E to Registration Statement 2- 36693) 4.06* Copy of Supplemental Trust Indenture, dated September 1, 1973. (Filed as Exhibit 2.01F to Registration Statement 2- 48805) 4.07* Copy of Supplemental Trust Indenture, dated February 1, 1982. (Filed as Exhibit 4.01G to Registration Statement 2- 76146) 4.08* Copy of Supplemental Trust Indenture, dated March 1, 1982. (Filed as Exhibit 4.08 to form 10-K Report 10-3140 for the year 1982) 4.09* Copy of Supplemental Trust Indenture, dated June 1, 1986. (Filed as Exhibit 4.09 to Form 10-K Report 10-3140 for the year 1986) 4.10* Copy of Supplemental Trust Indenture, dated March 1, 1988. (Filed as Exhibit 4.10 to Form 10-K Report 10-3140 for the year 1988) 4.11* Copy of Supplemental and Restated Trust Indenture, dated March 1, 1991. (Filed as Exhibit 4.01K to Registration Statement 33-39831) 4.12* Copy of Supplemental Trust Indenture, dated April 1, 1991. (Filed as Exhibit 4.01 to Form 10-Q Report 10-3140 for the quarter ended March 31, 1991) 4.13* Copy of Supplemental Trust Indenture, dated March 1, 1993. (Filed as Exhibit to Form 8-K Report dated March 3, 1993) 4.14* Copy of Supplemental Trust Indenture, dated October 1, 1993. (Filed as Exhibit 4.01 to Form 8-K Report dated September 21, 1993) 10.01 *Copy of MAPP Agreement, dated March 31, 1972, between the local power suppliers in the North Central States area. (Filed as Exhibit 5.06B to Registration Statement 2- 44530) 10.02* Copy of Interchange Agreement dated September 17, 1984, and Settlement Agreement dated May 31, 1985, between the Company, the Minnesota Company and LSDP. (Filed as Exhibit 10.10 to Form 10-K Report 10-3140 for the year 1985) (b) Reports on Form 8-K On December 20, 1994, a Form 8-K was filed reporting (as Item 4, Changes in Registrant's Certifying Accountant and Item 7, Financial Statements and Exhibits), the Company's change in Certifying Accountant. SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto authorized. NORTHERN STATES POWER COMPANY /s/ John A. Noer President and Chief Executive Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. /s/ John A. Noer (Principal Executive Officer) /s/ /s/ M. N. Gregerson H. Lyman Bretting Vice President-Customer Services Director /s/ /s/ A. G. Schuster P. M. Gelatt Vice President Director Power Delivery and Generation /s/ /s/ Patrick D. Watkins Wayne E. Harrison Vice President-Corporate Services Director /s/ /s/ John P. Moore, Jr. Loren L. Taylor General Counsel and Secretary Director /s/ /s/ Kenneth J. Zagzebski Ray A. Larson, Jr. Controller Director (Principal Accounting Officer) /s/ /s/ Neal A. Siikarla Larry G. Schnack Treasurer Director (Principal Financial Officer) 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 John A. Noer President and Chief Executive Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. John A. Noer President and Director (Principal Executive Officer) M. N. Gregerson H. Lyman Bretting Vice President-Customer Services Director A. G. Schuster P. M. Gelatt Vice President Director Power Delivery and Generation Patrick D. Watkins Wayne E. Harrison Vice President-Corporate Services Director John P. Moore, Jr. Loren L. Taylor General Counsel and Secretary Director Kenneth J. Zagzebski Ray A. Larson, Jr. Controller Director (Principal Accounting Officer) Neal A. Siikarla Larry G.Schnack Treasurer Director (Principal Financial Officer) 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, 1994 Commission file number: 10-3140 Northern States Power Company, a Wisconsin corporation, meets the conditions set forth in general instruction J (1) (a) and (b) of Form 10-K and is therefore filing this form with the reduce disclosure format. (In general instruction J(2) Northern States Power Company (Exact name of registrant as specified in its charter) Wisconsin 39-0508315 (State or other jurisdiction of (I.R.S. employer identification number) incorporation or organization) 100 North Barstow Street 54702-0008 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code (715) 839-2621 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 23, 1995 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 Regulation . . . . . . . . . . . . . . . . . . . .. . 1 Rate Changes . . . . . . . . . . . . . . . . . . .. . 2 Fuel and Purchased Gas Adjustment Clauses. . . . .. . 3 Demand Side Management . . . . . . . . . . . . . .. . 3 ELECTRIC OPERATIONS Competition. . . . . . . . . . . . . . . . . .. . . . 4 NSP System . . . . . . . . . . . . . . . . . .. . . . 4 Capability and Demand. . . . . . . . . . . . .. . . . 5 Interchange Agreement. . . . . . . . . . . . .. . . . 6 Electric Power Pooling Agreements. . . . . . .. . . . 6 Fuel Supply. . . . . . . . . . . . . . . . . .. . . . 6 Electric Operating Statistics . . . . . . . .. . . . 7 GAS OPERATIONS . . . . . . . . . . . . . . . . .. . . . 7 ENVIRONMENTAL MATTERS . . . . . . . . . . . .. . . . . 8 CONSTRUCTION AND FINANCING . . . . . . . . . . . . . . 9 EMPLOYEES AND EMPLOYEE BENEFITS. . . . . . . .. . . . . 10 Item 2 Properties . . .. . . . . . . . . . . . . . . . . . . . 12 Item 3 Legal Proceedings. . .. . . . . . . . . . . . . . . . . 12 Item 4 Submission of Matters to a Vote of Security Holders . . .. . . . . . . . . . . . 13 PART II Item 5 Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters. . . . . . . . 14 Item 6 Selected Financial Data. . . . . . . . . . . . . . . . . 14 Item 7 Management's Discussion and Analysis . . . . . . . . . . 14 Item 8 Financial Statements and Supplementary Data. . . . . . . 17 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . 32 PART III Item 10 Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . 33 Item 11 Executive Compensation . . . . . . . . . . . . . . . . . 33 Item 12 Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . 33 Item 13 Certain Relationships and Related Transactions . . . . . 33 PART IV Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . . . . . . . . . 34 SIGNATURES . . . .. . . . . . . . . . . . . . . . . . . . . . . . 36