-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, GeTyRL4Bj4zLj44ObzET8trbquAN5xjlfgDAHTM4U2k7PVIn5grUndYuD7gmTuSI 7ykfLRaIulrWd46zE18JJw== 0000061339-98-000003.txt : 19980401 0000061339-98-000003.hdr.sgml : 19980401 ACCESSION NUMBER: 0000061339-98-000003 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980331 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: MADISON GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000061339 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 390444025 STATE OF INCORPORATION: WI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 000-01125 FILM NUMBER: 98579934 BUSINESS ADDRESS: STREET 1: 133 S BLAIR ST STREET 2: PO BOX 1231 CITY: MADISON STATE: WI ZIP: 53701 BUSINESS PHONE: 6082527923 MAIL ADDRESS: STREET 1: POST OFFICE BOX 1231 CITY: MADISON STATE: WI ZIP: 53701-1231 10-K405 1 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 For the fiscal year ended: December 31, 1997 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from: _________ to _________ Commission File Number 0-1125 MADISON GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) WISCONSIN (State or other jurisdiction of incorporation or organization) 39-0444025 (IRS Employer Identification No.) 133 South Blair Street Post Office Box 1231 Madison, Wisconsin 53701-1231 (Address of principal executive offices, including ZIP code) (608) 252-7000 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Securities registered pursuant to Section 12(g) of the Act: Common, Par Value $1 Per Share (Title of Class) 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 by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes X No State the aggregate market value of the voting stock held by nonaffiliates of the Registrant: $359,783,690 based on a closing bid price of $22.375 on March 1, 1998 (the record date for the Annual Meeting of Shareholders). The number of shares outstanding of each of the issuer's classes of common stock, as of the close of the period covered by this report, was 16,079,718 of Common Stock, Par Value $1 Per Share. List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. - - 1997 Annual Report to Shareholders (Parts I, II, and IV) - - Definitive Proxy Statement filed on March 23, 1998 (Parts I and III) PART I. Item 1. Business General Description of Business The registrant, Madison Gas and Electric Company (the Company), a Wisconsin corporation organized as such in 1896, is a public utility engaged in the generation and transmission of electric energy and in its distribution in Madison and its environs (250 square miles) and in the purchase, transportation, and distribution of natural gas in Columbia, Crawford, Dane, Iowa, Juneau, Monroe, and Vernon counties, Wisconsin (1,325 square miles). Exhibit No. 21 herein provides a description of the Company's wholly owned subsidiaries. In January 1997, the Company's two gas marketing subsidiaries, Great Lakes Energy Corp. (GLENCO) and American Energy Management, Inc. (AEM), formed a joint venture with another gas marketing company. The joint venture will market natural gas and energy services to industrial and commercial customers in the Great Lakes region. The joint venture is called National Energy Management, L.L.C. and is based in Chicago. (See Item 7, page II-6, and Item 8, page F-17, for further discussion.) The Company is subject to regulation by the Public Service Commission of Wisconsin (PSCW) as to rates, accounts, issuance of securities, plant and transmission line siting, and in other respects. The Federal Energy Regulatory Commission (FERC) has jurisdiction, under the Federal Power Act, over certain accounting practices of the Company and in certain other respects. The Nuclear Regulatory Commission (NRC) has jurisdiction over the operation of the Kewaunee Nuclear Power Plant (Kewaunee). The Company has a 17.8 percent ownership interest in Kewaunee. The other owners are Wisconsin Public Service Corporation (WPSC), which operates Kewaunee, and Wisconsin Power and Light Company (WPL). The Company is also subject to regulation with regard to air quality, water quality, and solid waste (see I-6 and I-7) and may be subject to regulation with regard to other environmental matters by various federal, state, and local authorities including the Wisconsin Department of Natural Resources (DNR), which has jurisdiction over air and water quality, solid and hazardous waste standards, and which regulates the electric generating operations of the Company with respect to pollution and environmental control matters. The Company has met the requirements of current environmental regulations. Unknown additional expenditures may be required for pollution control equipment and for the modification of existing plants to comply with future unknown environmental regulations. For example, the ongoing issue of global warming could result in significant compliance cost for carbon dioxide emission reductions. Except as set forth below, the amounts of such expenditures and the period of time over which they may be required to be made are not known. The Company is unable to predict whether compliance with future pollution control regulations would involve curtailments of operations or reductions in generating capacity or efficiency of present generating facilities or delays in the construction and operation of future generating facilities. Under both the National Environmental Policy Act and the Wisconsin Environmental Policy Act, the Company must obtain the necessary authorizations or permits from regulatory agencies for any new projects or other major actions significantly affecting the quality of the human environment after all aspects of the proposed project or action are subjected to a complete environmental review and a detailed environmental impact statement is issued. Electric Operations At December 31, 1997, the Company supplied electric service to 122,843 customers, of whom 109,658 were located in the cities of Fitchburg, Madison, Middleton, and Monona, and 13,185 in adjacent areas. Of the total number of customers, 106,349 were residential and 16,357 were commercial. For 1997, residential and commercial electric service revenues comprised 35 and 49 percent, respectively, of total electric revenues. The remaining electric revenues during 1997 were from industrial sales (7 percent), sales to public authorities including the University of Wisconsin (9 percent), and sales to other utilities (1 percent). The electric operations accounted for 62 percent of the total revenues of the Company. See Item 2 for a description of the Company's electric utility plant. The Company is a member of Mid-America Interconnected Network, Inc. (MAIN), a regional reliability group. Membership in this group permits better utilization of reserve generating capacity and coordination of long-range system planning and day-to-day operations. MAIN seeks to maintain adequate planning generation reserve margins as a group in the range of 15 to 22 percent. The Company is also a member of the Midcontinent Area Power Pool (MAPP) Regional Transmission Committee (RTC). The RTC members pool their transmission systems together allowing each member to easily utilize the combined system to access economical energy across the Upper Midwest. Each member is then compensated for the energy flows on their individual transmission system. In February 1996, the PSCW submitted a report to the State Legislature on electric utility restructuring in Wisconsin. Included in the report was a 32-step work plan and time line summarizing expected restructuring activities. During the summer of 1997, Wisconsin and Illinois experienced electric supply shortages due to outages of a number of nuclear plants in Illinois and Wisconsin, including Kewaunee. The electric reliability crisis caused the PSCW to revise its previous plans for restructuring the electric industry. In October 1997, the PSCW stated that retail competition cannot occur until all the safeguards are in place to protect consumers. Also, prior to any significant restructuring, reliability concerns must be addressed. This conclusion was consistent with plans proposed by the Company and a broad coalition of customers. (See Item 7, page II-9, Electric Industry Trend for further discussion.) Fuel supply and generation The Company estimates its net kilowatt-hour requirements for 1998 will be provided from the following sources: 68 percent from fossil-fueled steam plants, 21 percent from a nuclear-fueled steam plant, 10 percent from low-cost power purchases, and 1 percent from a combination of natural gas- and oil-fired combustion turbines. The Company has a 22 percent ownership interest in the Columbia Energy Center (Columbia). The other owners are WPL, which operates Columbia, and WPSC. The first (Columbia I) and second (Columbia II) units at Columbia were placed in commercial operation in 1975 and 1978, respectively. The Columbia co-owners' coal inventory supply for Columbia I and Columbia II increased from 30 days on December 31, 1996, to 55 days on December 31, 1997, due to: (1) the lower-than-normal inventory levels at the end of 1996; (2) the cooler-than-normal summer in 1997; and (3) the warmer-than-normal temperatures in November and December 1997. The co-owners' goal is to maintain approximately a 40-day inventory. Columbia, with two 527-megawatt units, uses coal from the Wyoming-Montana coal fields. One hundred percent (100%) of the low-sulfur coal supply for these units comes from Powder River Basin sources in Montana and Wyoming. About 200 megawatts of the Company's electric generating capacity is provided by the Blount Generating Station (Blount) (see I-10). The Company is able to burn a variety of coals, natural gas, and other fuels such as paper-derived fuel at Blount. The Kewaunee plant, a 562-megawatt pressurized water reactor plant, began commercial operation in 1974. The Kewaunee operating license expires in 2013. Kewaunee returned to service on June 12, 1997, after having been out of service since September 21, 1996, for refueling, routine maintenance, and repair of the two steam generators. The Kewaunee steam generator tubes sustained damage as a result of repairs performed on the tubes in 1988 through 1991. Tubes were repaired by inserting sleeves (tubes within tubes) in the original steam generator tubes. The most recent repair was undertaken when cracking was discovered in previously repaired tubes. The repair consisted of removing old sleeves and inserting new slightly longer sleeves which cover the areas of concern in the original steam generator tubes. The new sleeves will be inspected during the next refueling and maintenance outage, which is scheduled for the fall of 1998. Kewaunee is operating at 97 percent of rated capacity because certain steam generator tubes have been removed from service rather than repaired. Kewaunee operated for 238 consecutive days before being removed from service on February 6, 1998, for repair of a reactor coolant pump seal. The plant was returned to service on February 13, 1998. Additional replacement power costs in the amount of about $1.0 million per month due to the extended Kewaunee outage were recovered through a customer surcharge during the period March 6, 1997, through July 1, 1997. The co-owners of Kewaunee filed an application with the PSCW in November 1997 for a customer surcharge to recover costs associated with the 1997 steam generator repairs. The Company's portion of these costs is approximately $1.8 million (excluding carrying costs). The Company requested recovery of these costs through a customer surcharge which would be collected over a four-month period in 1998. The PSCW approved, at its open meeting on March 19, 1998, the Company's request for a customer surcharge relating to recovery of 1997 steam generator repair costs. Public hearings were held in January 1998 regarding the application filed with the PSCW requesting replacement of the steam generators at Kewaunee. A decision by the PSCW is expected in late March or early April. The Company opposes replacement of the steam generators at Kewaunee. Replacement of steam generators must be approved by the PSCW and is estimated to cost $89.0 million (the Company's share would be 17.8 percent or $15.8 million), excluding additional replacement purchased power costs associated with an extended shutdown. The NRC's Systematic Assessment of Licensee Performance for Kewaunee for the period February 19, 1995, through February 15, 1997, was received in 1997. The report evaluated Kewaunee's performance in four categories: operations, maintenance, engineering, and plant support. Maintenance was ranked "superior," and the other areas were rated as "good." The NRC stated that Kewaunee's overall performance was generally characterized by effective management involvement and interdepartmental communication and a clear emphasis on quality by the staff. Areas for improvement that were identified were: timely evaluation of errors by personnel, adequacy of procedures and equipment for monitoring equipment performance, and the timely resolution of plant-identified deficiencies. On July 14, 1997, the NRC assessed a $50,000 penalty against Kewaunee. The penalty was the result of an NRC inspection in January 1997 where the NRC questioned the procedures and equipment used to conduct routine operational tests on several pumps. In response, the procedures were updated to improve the test methods and more sensitive equipment was obtained. All safety-related pumps in the plant were then retested and found to be operating within standards. The federal government has the responsibility to dispose of or permanently store spent nuclear fuel. Spent nuclear fuel is currently being stored at Kewaunee. With minor plant modifications, Kewaunee should have sufficient fuel storage capacity until the end of its licensed life in 2013. Legislation is being considered on the federal level to provide for the establishment of an interim storage facility as early as 2002. Permanent storage pursuant to the Nuclear Waste Policy Act of 1982 (Nuclear Policy Act) is discussed below. The Midwest Compact Commission on June 26, 1997, halted development in Ohio of a six-state, regional disposal facility for low-level radioactive waste. The Commission cited dwindling regional waste volumes, continued access to existing disposal facilities, and potentially high development costs as the primary reasons for the decision. A site at Barnwell, South Carolina, continues to be available for the storage of low-level radioactive waste from Kewaunee. In addition, because of technological advances, waste compaction, and the reduction of waste generated, Kewaunee has on-site, low-level radioactive waste storage capacity sufficient to store low-level waste expected to be generated over a ten-year period. The PSCW has directed the owners of Kewaunee to develop depreciation and decommissioning cost levels based on full recovery by the end of 2002 versus recovery by license expiration in 2013. This was prompted by the uncertainty regarding the expected useful life of the plant without steam generator replacement. At December 31, 1997, the net carrying amount of the Company's investment in Kewaunee was approximately $19.1 million. The current cost of the Company's share of the estimated costs to decommission Kewaunee, assuming early retirement, ($78.8 million) exceeds the fair market value of decommissioning trust assets at December 31, 1997, ($59.2 million) by $19.6 million. Decommissioning costs are based on a site-specific study performed in 1992 using immediate dismantlement as the method of decommissioning. Decommissioning costs as studied are assumed to inflate at an average rate of 6.0 percent. Physical decommissioning is expected to occur during the period 2014 through 2021 with additional expenditures being incurred during the period 2022 through 2039 related to the storage of spent nuclear fuel at the plant site. Nuclear decommissioning costs are being accrued to an end-of- service life of 2002 for Kewaunee. These costs are currently recovered from customers in rates and are deposited in external trusts. For 1997, the decommissioning costs recovered in rates were $4.9 million. (See page II-8 for further discussion of Kewaunee.) The co-owners purchase uranium concentrates, conversion services, enrichment services, and fabrication services for nuclear fuel assemblies at Kewaunee. New fuel assemblies replace used assemblies that are removed from the reactor every 18 months and placed in storage at the plant site pending removal by the United States Department of Energy (DOE). Uranium concentrates, conversion services, and enrichment services are purchased at spot market prices, through a bid process, or using existing contracts. A uranium inventory policy requires that sufficient inventory exist for up to two reactor reloads of fuel. At December 31, 1997, 960,000 pounds of yellowcake or its equivalent were held in inventory for Kewaunee. Two contracts are in place to provide conversion services for Kewaunee nuclear fuel for reloads in 1998 and 2000. A contract with COGEMA, Inc., provides a fixed quantity of enrichment services through the year 2001. Additional enrichment services will be acquired under a contract with the United States Enrichment Corporation which is in effect for the life of Kewaunee or by purchases on the spot market. A contract with Siemens Power Corporation provides fuel fabrication services through March 15, 2001, for Kewaunee. This contract contains force majeure and termination provisions. If, for any reason, Kewaunee was forced to suspend operations permanently, fuel-related obligations are as follows: (1) there are no financial penalties associated with the present uranium supply, conversion service, and enrichment agreements; and (2) the fuel fabrication contract contains force majeure and termination for convenience provisions. As of the end of 1997, the maximum exposure would not be expected to exceed $550,000. Uranium inventories could be sold on the spot market. The Nuclear Policy Act requires that the DOE accept, transport, and dispose of spent nuclear fuel beginning no later than January 31, 1998. The DOE has announced that it will delay the acceptance of spent nuclear fuel beyond 1998. The nuclear utilities have been supported by a decision of the United States Court of Appeals for the District of Columbia Circuit in their claim that they may pursue the remedies provided in the DOE standard contract in the event the DOE does not perform its duty to dispose of spent nuclear fuel by the January 31, 1998, deadline. The Energy Policy Act of 1992 requires that the federal government and nuclear utilities fund the decontamination and decommissioning of the government's three gaseous diffusion plants in the United States. The Company is required to pay approximately $250,000 per year (adjusted for inflation) through the year 2007. The co-owners, as well as other nuclear utilities, have filed suit in the United States Court of Federal Claims disputing the decontamination and decommissioning assessment. The suit has been stayed pending the outcome of the Yankee Atomic Electric Company (Yankee Atomic) appeal. Yankee Atomic has received an adverse decision in the United States Court of Appeals for the Federal Circuit and has filed a petition for certiorari with the United States Supreme Court. Air quality Phase II of the federal Clean Air Act amendments of 1990 sets stringent SO2 and nitrogen oxide emission limitations which may result in increased capital and operating and maintenance expenditures. Phase II emission compliance strategies could include the following: fuel switching, emission trading, purchased power agreements, new emission control devices, or installation of new fuel-burning technologies and clean-coal technologies. There is a Wisconsin acid rain law which imposes limitations of SO2 emissions on the major utilities. Blount and the Company's share of Columbia are required to meet a combined SO2 emission rate of 1.20 pounds of SO2 per million Btu. No capital costs are anticipated to meet compliance with this standard. The federal Clean Air Act amendments of 1990 require the EPA to perform certain studies concerning hazardous air emissions from electric utilities. Regulation of power plants for these emissions may occur as a result of these studies. The DNR hazardous air emission regulations currently exempt fossil-fuel combustion. The Company believes all of its plants to be in full compliance with all material aspects of present air-pollution control regulations. Water quality The Company is subject to water quality regulation by the DNR. These regulations include both categorical-effluent discharge standards and general water quality standards. The regulations limit discharges from the Company's plants into Lake Michigan and other Wisconsin waters. The categorical-effluent discharge standards require each discharger to use effluent treatment processes equivalent to categorical "best practicable" or "best available" technologies under compliance schedules established pursuant to the federal Water Pollution Control Act. The DNR has published categorical regulations for chemical discharges from steam electric generating plants. The Company is in compliance with applicable standards. Solid waste The Company is listed as a potentially responsible party on the roster of generators for the Refuse Hideaway Landfill in Middleton, Wisconsin, and the Lenz Oil site in Lemont, Illinois. The Refuse Hideaway Landfill was used for the disposal of fly-ash sludge from 1980 to 1984. The Lenz Oil Site was operated for several years as a facility for the storage and processing of waste oil. The Environmental Protection Agency (EPA) has placed the two sites on the national priorities Superfund list of sites requiring clean up under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The scope of liability under CERCLA is very broad. A group of companies is currently negotiating with the EPA on the cleanup of the sites. In the opinion of management and legal counsel, the Company's share of the final cleanup costs will not result in any materially adverse effects on the operations, cash flows, or financial position of the Company. Significant insurance recovery may also be available for the cleanup. From 1855 through the 1950s, the Company and its predecessors operated a manufactured gas plant at the present site of Blount. The plant used coal and oil to produce a low-Btu gas used primarily for residential cooking and heating. Wastes from the gas manufacturing process included light oils and tars. These materials were either recycled into the gas manufacturing process or sold for other uses such as asphalt manufacturing. The residual tars and oils from the operation of the plant may have impacted the site near the gas holders. The Company has been monitoring the groundwater and soils in cooperation with the DNR for several years. In the opinion of management and legal counsel, the resolution of this matter will not result in any materially adverse effect on the operations or financial position of the Company. The City of Madison has identified the Company as a possible potential responsible party for the remediation of the Demetral Landfill. Waste materials disposed of at the site by the Company consisted of fly ash and bottom ash from the combustion of coal to generate electricity. The Company and many others used the landfill in the early 1950s. The Company has the potential to incur liability costs associated with its use of this landfill. In the opinion of management and legal counsel, the resolution of this matter will not result in any materially adverse effect on the operations or financial position of the Company. Gas Operations On December 31, 1997, the Company supplied natural gas service to 107,226 customers in the cities of Elroy, Madison, Middleton, Monona, Fitchburg, Lodi, Verona, and Viroqua; 22 villages; and all or parts of 41 townships. Revenues received from residential and commercial customers accounted for 55 and 37 percent, respectively, of the total gas revenues for 1997. The gas operations accounted for 38 percent of the total revenues of the Company. Revenues from transportation service accounted for 2 percent of the total gas revenues for 1997. Sales and revenues from best-efforts rate schedules accounted for 3 and 2 percent of total retail sales and revenues, respectively. The Company has the ability to peak shave through use of a propane-air gas manufacturing plant for which it had on hand adequate fuel supplies for its peak-shaving requirements during the 1997 to 1998 heating season. In addition, the Company can curtail gas deliveries to its interruptible customers. Approximately 8 percent of gas sold in 1997 was sold to interruptible customers. Gas supply The Company has physical interconnections with both ANR Pipeline Company (ANR) and Northern Natural Gas Company (NNG). The Company's primary service territory, which includes Madison and the surrounding area, receives deliveries at four ANR gate stations and one NNG gate station. The Company also receives deliveries at NNG gate stations located in the communities of Viroqua, Elroy, and Crawford County. Interconnections with two major pipelines provide competition in interstate pipeline service and a more reliable and economical supply mix including gas from Canada and the United States Mid-Continent and Gulf/Offshore regions. By contract, a total of 5,576,600 dekatherms can be injected into ANR's storage fields from April 1 through October 31. These gas supplies are then available for withdrawal during the subsequent heating season of November 1 through March 31. ANR's storage fields are located in Michigan. Use of storage provides the Company with the ability to purchase gas supplies during the summer season when prices are normally lowest and withdraw these supplies during the winter season when gas prices are typically higher. Storage allows the Company greater ability to meet daily load fluctuations. During the winter months, when the demand of its customers is highest, the Company is primarily concerned with meeting its obligation to its firm customers. Long-term firm supply contracts, supplies in storage injected during the summer, and firm supplies purchased for the winter period are utilized to meet customer demand. These gas supplies are contracted for prior to the heating season so price levels can be locked in to assure reliability of supply and stability in pricing. The prior heating season (November 1996 and continuing through March 1997) was colder than normal. Demand for natural gas remained high during the summer (April 1997 through October 1997) as gas was injected into storage to replenish inventories. Gas prices also remained relatively high. The beginning of the current heating season (starting November 1997 through March 1998) has been warmer than normal and caused storage levels to be somewhat higher than normal. Regarding transportation of supply, the Company has firm transportation service on ANR for a maximum daily quantity of 33,618 dekatherms. The Company's NNG maximum daily quantity for firm transportation service is 48,719 dekatherms. The Company also holds 2,457 dekatherms of firm transportation service into Viroqua's NNG gate station and firm transportation service of 1,432 dekatherms into Crawford County's NNG gate station. General The Company's business is seasonal to the same extent as other Upper Midwest electric and natural gas utilities. The Company had 669 permanent employees at December 31, 1997. Information regarding Company executive officers is included under Item 10 of this report, page III-1, which information is incorporated herein by reference. Item 2. Properties The following table presents the generating capability in service at December 31, 1997:
Commercial Net Operation Capability No. of Plants Date Fuel (Megawatt) Units Steam plants Columbia 1975 & 1978 Low-sulfur coal 232 (1,2) 2 Kewaunee 1974 Nuclear 93 (1,3) 1 Blount (Madison) 1957 & 1961 Coal/gas 98 2 1938 & 1942 Gas 40 2 1949 Coal/gas 23 1 1964-1968 Gas/oil 35 4 Combustion turbines 1964-1973 Gas/oil 88 5 Total 609
(1) Base load generation (2) Company's 22 percent share of two 527-mw units located near Portage, Wisconsin (3) Company's 17.8 percent share of 525-mw unit located near Kewaunee, Wisconsin Major electric transmission and distribution lines and substations in service at December 31, 1997, are as follows:
MILES Lines Overhead Lines Underground Lines Transmission 345 kV 124 - 138 kV 96 3 69 kV 64 20 Distribution 13.8 kV and 1,022 748 under Substation Installed Capacity (kVA) Transmission (22) 4,132,350 Distribution (33) 361,700
Gas facilities include 1,886 miles of distribution mains and one propane air plant capable of producing a maximum daily capacity of 9,000 dekatherms of natural gas equivalent. Item 3. Legal Proceedings None. Item 4. Results of Votes of Security Holders No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year. PART II. Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters The principal market in which the common stock of the Company is traded is The Nasdaq National Stock Market (Nasdaq) under the symbol MDSN. The approximate number of stockholders of record on January 31, 1998, was 18,383. The Company's transfer agent and registrar is Harris Trust and Savings Bank, Chicago, Illinois. The high and low sales prices for the common stock on Nasdaq and the dividends paid per common share for each quarter for the past two fiscal years are shown below.
Common stock price range Dividends per 1997 share High Low 1997 First quarter $21 3/4 $18 1/2 $0.320 Second quarter $21 1/4 $19 1/2 $0.320 Third quarter $21 1/4 $19 7/8 $0.323 Fourth quarter $23 3/4 $19 5/8 $0.323 Common stock price range Dividends per 1996 share High Low 1996 First quarter $27 1/2 $23 1/8 $0.317 Second quarter $25 3/4 $21 1/2 $0.317 Third quarter $23 3/4 $21 1/2 $0.320 Fourth quarter $22 3/8 $19 5/8 $0.320
Item 6. Selected Financial Data
For the years ended December 31, (In thousands of dollars, except per-share amounts) 1997 1996 1995 1994 1993 Summary of Operations Operating Revenues: Electric . . . . . . . . . . . . $163,123 $152,747 $153,554 $149,665 $147,201 Gas . . . . . . . . . . . . . . . 101,525 100,544 95,036 95,307 96,932 Total . . . . . . . . . . . . . 264,648 253,291 248,590 244,972 244,133 Operating expenses . . . . . . . . 212,921 200,486 191,725 187,469 187,717 Other general taxes . . . . . . . . 8,797 8,736 8,709 8,619 8,222 Income tax items . . . . . . . . . 11,940 12,553 14,285 14,822 13,964 Net operating income . . . . . . 30,990 31,516 33,871 34,062 34,230 Other (loss)/income (including allowance 2,272 (14,177) 1,635 2,146 2,118 for funds used during construction) Income before interest expense . 33,262 17,339 35,506 36,208 36,348 Interest expense . . . . . . . . . 10,739 10,912 11,536 11,197 11,673 Net income . . . . . . . . . . . 22,523 6,427 23,970 25,011 24,675 Preferred dividends . . . . . . . . - - 64 471 489 Earnings on common stock . . . . 22,523 6,427 $23,906 $24,540 $24,186 Average shares outstanding . . . . 16,080 16,080 16,080 16,080 16,055 Earnings per share . . . . . . . $1.40 $0.40 $1.49 $1.53 $1.51 Dividends paid per share . . . . $1.287 $1.273 $1.260 $1.247 $1.227 Ratio of earnings to fixed charges* 4.02 2.71 4.23 4.49 4.15 At December 31, Assets Electric . . . . . . . . . . . . . $313,855 $315,022 $327,053 $323,870 $328,048 Gas . . . . . . . . . . . . . . . . 118,339 116,723 119,968 118,210 114,626 Assets not allocated . . . . . . . 39,596 52,424 46,855 45,679 22,690 Total . . . . . . . . . . . . . . $471,790 $484,169 $493,876 $487,759 $465,364 Capitalization Common shareholders' equity . . . . $180,923 $179,089 $193,137 $189,489 $184,995 Redeemable preferred stock . . . . - - - 5,100 5,400 Long-term debt . . . . . . . . . . 129,923 128,886 129,048 130,800 120,396 Short-term debt . . . . . . . . . . 33,500 29,750 20,500 28,600 23,500 Total Capitalization . . . . . . $344,346 $337,725 $342,685 $353,989 $334,291 *For the purpose of computing the ratio of earnings to fixed charges, earnings have been calculated by adding to income before interest expense, current and deferred federal and state income taxes, investment tax credits deferred and restored charged (credited) to operations, and the estimated interest component of rentals. Fixed charges represent interest expense, amortization of debt discount, premium and expense, and the estimated interest component of rentals.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations GENERAL The following discussion and analysis provides information which management believes is relevant to an assessment and understanding of Madison Gas and Electric Company's (the Company) consolidated results of operations and financial condition. The discussion should be read in conjunction with the consolidated financial statements and notes thereto. Certain matters that are discussed in the Management's Discussion and Analysis are forward-looking statements and can generally be identified by words such as "believes," "anticipates," or "expects." These forward-looking statements are subject to certain risks or uncertainties which could cause actual results to differ materially from those currently anticipated. RESULTS OF OPERATIONS Earnings overview Consolidated earnings for the Company were $1.40 per share in 1997 despite mild weather and an extended outage at the Kewaunee Nuclear Power Plant (Kewaunee). As a result of Kewaunee being out of service for the first half of the year, the Company had to replace the generation normally provided by Kewaunee with more expensive purchased power. The Company also faced regional power shortages during the summer of 1997, incurring extra expenses for actions taken by the Company to prevent power outages for the Company's customers. The Company was the only major utility in Wisconsin that did not interrupt service to any of its customers. Earnings from core utility operations were $1.48 per share in 1996, but the consolidated earnings were negatively impacted by the following items: a one-time charge of $10.4 million (after tax) to reflect the current value of the Company's investments in its gas marketing subsidiaries, a one-time charge of $1.6 million (after tax) resulting from a refund to natural gas customers under a sharing mechanism between Great Lakes Energy Corp. (GLENCO) and the Company, and operating losses of $5.4 million (after tax) from the Company's gas marketing subsidiaries. Consolidated earnings per share for the Company were $0.40 in 1996. Consolidated earnings for the Company were $1.49 per share in 1995. Above-normal temperatures experienced during the summer months helped offset the negative impacts of a 3.3 percent electric rate decrease which was effective January 1, 1995. Electric sales and revenues Electric retail sales for 1997 increased 2.9 percent from 1996 despite the cooler-than-normal temperatures experienced in the summer. The increase in retail sales is due to an increase in the number of electric customers and average usage per retail customer. The electric sales breakdown by customer class is shown in the table below: Electric Sales Megawatt % Hours 1997 1996 Change Residential 720,576 725,471 (0.7) Commercial 1,420,347 1,381,043 2.8 Industrial 307,485 289,903 6.1 Other 332,995 305,962 8.8 Total Retail 2,781,403 2,702,379 2.9 Resale - Utilities 64,914 26,815 142.1 Total Sales 2,846,317 2,729,194 4.3 Electric revenues increased $10.4 million or 6.8 percent in 1997 compared to 1996. The increase reflects higher electric sales, a 3.1 percent increase in electric rates effective August 20, 1997, and an interim rate surcharge of 0.507 cents per kilowatt-hour related to the extended outage at Kewaunee which was in effect from March through June (see Item 8, page F-16, Note 3). Electric retail sales for 1996 increased slightly from 1995. This, too, can be attributed to an increase in the number of electric customers. Electric revenues decreased slightly in 1996 compared to 1995. Gas sales and revenues Total gas therms delivered by the Company decreased 4.9 percent in 1997 compared to 1996, largely reflecting the warmer weather throughout the winter months of 1997. Total heating degree days (as measured by the number of degrees the mean daily temperature is below 65 degrees Fahrenheit) decreased 9.7 percent for the winter heating season (January through March, November and December) of 1997 when compared to 1996. The table below shows total gas deliveries by customer class: Therms Delivered % Thousands 1997 1996 Change Residential 87,664 96,062 (8.7) Commercial and 87,717 93,723 (6.4) Industrial Total Retail System 175,381 189,785 (7.6) Transport 40,947 37,707 8.6 Total Gas Deliveries 216,328 227,492 (4.9) Despite the decrease in gas delivered in 1997, gas revenues increased by 1.0 percent when compared to 1996. The increase in revenues, despite a decrease in gas deliveries, was due primarily to higher-unit gas costs, specifically during the first quarter. These costs were passed on to customers through the Purchased Gas Adjustment Clause (PGAC) (see Regulatory and Accounting Issues, page II-10). A gas rate increase of 3.5 percent went into effect August 20, 1997, which also contributed to the increased revenues. Gas delivered to customers in 1996 increased 3.3 percent compared to 1995, and revenues increased $5.5 million or 5.8 percent during the same period. This was mainly attributable to the increase in gas deliveries due to the colder weather experienced during the first quarter of 1996. Electric fuel and natural gas costs Electric fuel and purchased power costs increased $6.4 million or 16.7 percent in 1997 compared to the same period a year ago. As previously mentioned, this was due to the increased purchased power costs associated with replacing generation lost from the extended outage at Kewaunee. Kewaunee normally provides approximately 25 percent of the generation requirements of the Company. Higher generation costs during July due to the unavailability of power resulting from the regional power shortages also increased fuel and purchased power costs in 1997 compared to 1996. The Company's electric margin (revenues less fuel and purchased power) increased $4.0 million or 3.5 percent during 1997 compared to 1996. Electric fuel and purchased power costs increased $2.3 million or 6.4 percent from 1995 to 1996. This increase is also due to the higher cost of replacement power from the extended outage at Kewaunee. Kewaunee was removed from service in September 1996 for scheduled refueling and maintenance work and did not return to service until June 1997. The electric margin decreased $3.1 million or 2.6 percent during 1996 compared to 1995. This decrease in the electric margin was a result of the increase in replacement purchased power costs related to the extended outage at Kewaunee. Natural gas costs decreased $0.9 million or 1.4 percent from 1997 compared to 1996 due mainly to the decrease in gas delivered caused by the warm winter weather. Gas margin (revenues less natural gas purchased) increased by $1.9 million or 5.6 percent in 1997 compared to 1996. This was a result of continued customer growth and the rate increase mentioned previously. Natural gas costs increased $8.5 million or 14.8 percent during 1996 compared to 1995. The cold first quarter and the subsequent demand for natural gas increased the cost per therm accordingly. The cost per therm in 1996 increased $0.04 or 13.4 percent over 1995. Other operating expenses Operations and maintenance (O&M) expenses increased $4.2 million or 5.9 percent in 1997 compared to 1996. The primary reasons are the higher repair costs for Company-owned generation due to the extended outage of Kewaunee. The co-owners of Kewaunee received authorization from the Public Service Commission of Wisconsin (PSCW) to defer a majority of the costs for steam generator repairs (see Item 8, page F-16, Note 3). O&M expenses decreased $2.8 million or 3.8 percent during 1996 compared to 1995. Depreciation and amortization expense increased $2.8 million or 11.0 percent for the year ended 1997 compared to the same period a year ago. This increase is due, in part, to the accelerated depreciation of Kewaunee. Depreciation expense related to decommissioning costs increased $1.8 million or 37.9 percent in 1997 compared to 1996 because of the acceleration of decommissioning of Kewaunee. The PSCW approved accelerated depreciation and decommission funding for Kewaunee based on its service life ending at the end of 2002. Other nonoperating expenses The Company's nonutility income for 1997 was $0.8 million compared to operating losses of $5.4 million in 1996. The Company's two gas marketing subsidiaries, GLENCO and American Energy Management Inc. (AEM), formed a joint venture effective January 1, 1997, with another gas marketing company to market natural gas and energy services to industrial and commercial customers in the Great Lakes region. The joint venture is called National Energy Management, L.L.C., and is based in Chicago. The Company recorded a one-time charge in 1996 of $10.4 million (after tax) to properly reflect the current value of the Company's investments in its gas marketing subsidiaries and reorganizing these activities for the future (see Item 8, page F-17, Note 4). Electric and gas operations outlook The Company anticipates electric and gas customer growth at a compound rate of 1 to 2 percent over the next five-year period ending December 31, 2002. The service territory remains well- insulated against economic downturns. The Company expects to remain a strong competitor in a restructured electric industry because of its low generation costs, competitive rates, low percentage of industrial customers, and lower risk of stranded investments in power plants. The Company continues to offer competitive rates and services to meet the needs of its customers in a deregulated natural gas market. LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities Cash provided by operating activities decreased $7.5 million or 15.5 percent in 1997 compared to 1996. This is mainly due to the reduction in current payables of the Company's gas marketing subsidiaries, GLENCO and AEM. Cash provided by operating activities decreased $2.5 million or 4.9 percent in 1996 compared to 1995. Capital requirements and investing activities The Company's liquidity is primarily affected by the requirement of its ongoing construction program. Capital expenditures in 1997 were $21.6 million. It is anticipated that capital expenditures will be $46 million in 1998. The major capital projects for 1998 include the wind energy project in northeastern Wisconsin, which will cost about $14 million, and Company-owned backup generation projects costing about $3 million. The backup generation projects will help maintain electric reliability. Estimated capital expenditures for the years 1999 through 2002 will average $33 million per year. Capital expenditures and nuclear fuel estimated for 1998, actual for 1997, and the average for the three-year period 1994 through 1996 are shown below: Expenditures for Construction and Nuclear Fuel (Thousands of Dollars)
For the years ended 1998 Annual Average December 31: Estimated 1997 1994 to 1996 Electric Production $17,977 38.7% $ 5,005 23.1% $ 1,911 8.5% Transmission 2,065 4.5 1,602 7.4 1,151 5.1 Distribution and General 12,034 25.9 8,287 38.3 8,965 39.8 Nuclear Fuel 4,228 9.1 1,394 6.4 2,752 12.2 Total Electric 36,304 78.2 16,288 75.2 14,779 65.6 Gas 6,441 13.9 4,427 20.5 5,908 26.3 Common 3,655 7.9 920 4.3 1,812 8.1 TOTAL $46,400 100.0% $21,635 100.0% $22,499 100.0%
Financing activities and capitalization matters In April 1997, the Company purchased on the open market $3.8 million of its First Mortgage Bonds. In June 1997, the Company entered into a fixed interest rate agreement for $5.0 million maturing June 2004. At December 31, 1997, bank lines of credit available to the Company were $52 million. Bank lines are generally used to support the Company's commercial paper issued which represents a primary source of short-term financing. The Company's dealer- issued commercial paper carries the highest ratings assigned by Moody's Investors Service and Standard & Poor's Corporation. The Company's existing bonds are rated AA by Standard & Poor's and Aa2 by Moody's Investors Service. Kewaunee Nuclear Power Plant The Company has a 17.8 percent ownership interest in Kewaunee, which it owns jointly with two other utilities. Kewaunee is operating with a license that expires in 2013. Kewaunee returned to service in June 1997, after having been out of service since September 1996, for refueling, routine maintenance, and repair of the steam generators. Kewaunee is currently operating at 97 percent of rated capacity because certain steam generator tubes have been removed from service rather than repaired. Additional replacement power costs due to the extended outage were recovered through a customer surcharge from March 6, 1997, through July 1, 1997 (see Item 8, page F-16, Note 3). Effective March 20, 1997, the Kewaunee co-owners received authorization from the PSCW to defer all costs associated with the resleeving repair of the steam generators. The co-owners of Kewaunee have received approval from the PSCW on their requested rate recovery of these deferred costs through a customer surcharge (see Item 8, page F-16, Note 3). Public hearings were held in January 1998 regarding the application filed with the PSCW requesting replacement of the steam generators at Kewaunee. A decision by the PSCW is expected in late March or early April. The Company opposes replacement of the steam generators at Kewaunee. Electric industry trend In February 1996, the PSCW submitted a report to the State Legislature on electric utility restructuring in Wisconsin. Included in the report was a 32-step work plan and time line summarizing expected restructuring activities. During the summer of 1997, Wisconsin and Illinois experienced electric supply shortages due to outages of a number of nuclear plants in Illinois and Wisconsin, including Kewaunee. The electric reliability crisis caused the PSCW to revise its previous plans for restructuring the electric industry. In October 1997, the PSCW stated that retail competition cannot occur until all the safeguards are in place to protect consumers. Also, prior to any significant restructuring, reliability concerns must be addressed. This conclusion was consistent with plans proposed by the Company and a broad coalition of customers. The new plan focuses on the construction of a generation and transmission infrastructure by all Wisconsin utilities to increase the amount of power in the state and the state's ability to obtain electricity from other regions. The PSCW plans to remove any barriers to open access to the transmission system that currently exist and to move forward in its efforts to develop a strong state and regional Independent System Operator (ISO). This would assure that the transmission system is operated safely, reliably, and with open and nondiscriminatory access. Also in its revised plan, the PSCW plans to explore new ways to promote the development of renewable energy sources. The Company is in the process of building a $14 million wind generation project which will allow its customers to purchase blocks of energy produced with renewable resources. The PSCW has not set a date for retail competition and has concluded that any decision to go to retail competition in the electric industry remains to be made in the future. The Company cannot predict what impact future PSCW actions may have on its future financial condition, cash flows, or results of operations. However, the Company believes it is well-positioned to compete in a deregulated market. Regulatory and accounting issues The Company's recent rate order authorized a gas cost recovery mechanism that allows recovery of pipeline capacity, Federal Energy Regulatory Commission (FERC)-approved/mandated charges, and supply demand costs. Under the new mechanism, gas commodity costs will be compared to a monthly benchmark equal to the first- of-the-month index plus adders reflecting the effects on pricing for reliability, flexibility, weather, and variable transportation costs. If actual costs are below the benchmark, full recovery is allowed. Gas commodity costs above the benchmark will be reviewed by the PSCW. A target will also be determined for capacity release. Capacity release above the target will be shared 60 percent with the ratepayers and 40 percent with the shareholders. Any shortfalls in capacity release will be shared 40 percent with the ratepayers and 60 percent with the shareholders. The restructuring of the electric industry could affect the eligibility of the Company to continue applying Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Under this situation, continued deferral of certain regulatory asset and liability amounts on the Company's books may no longer be appropriate as allowed under SFAS No. 71. The Company is unable to predict whether any adjustments to regulatory assets and liabilities will occur in the future. The PSCW's restructuring plan specifically recognizes the need to allow recovery for commitments made under prior regulatory regimes. Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to be Disposed Of." This statement requires that long-lived assets and certain identifiable intangibles held and used by the Company be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. SFAS No. 121 also requires that assets to be disposed of be reported at the lower of the carrying amount or the fair value less costs to sell. Adoption of this statement did not have a material impact on the Company's financial position, results of operations, or cash flows. In February 1997, SFAS No. 128, "Earnings Per Share," was issued. SFAS No. 128 simplifies the standards for computing earnings per share and requires the presentation of two new amounts, basic and diluted earnings per share. The Company has retroactively adopted this standard for all prior periods reported. In June 1997, SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information," was issued. SFAS No. 131 requires that public business enterprises report certain information about operating segments in complete sets of financial statements of the Company and in condensed financial statements of interim periods issued to shareholders. The objective of requiring disclosures about segments of an enterprise and related information is to provide information about different types of business activities in which the Company engages and the different economic environments in which it operates in order to help users of financial statements better understand the Company's performance, assess its prospects for future net cash flows, and make more informed judgments about the Company as a whole. Mergers In May 1995, Northern States Power Company (NSP) and Wisconsin Energy Corporation (WEC) announced a proposed $6 billion merger. A company called Primergy Corporation (Primergy) was contemplated to be formed as a result of the merger. On May 14, 1997, the FERC rejected the merger as filed, citing concerns over dominance in the Midwest power and transmission markets. The FERC stated that Primergy would be able to dominate the eastern Wisconsin and upper Michigan power generation market. On May 16, 1997, the Board of Directors from both NSP and WEC agreed to terminate their merger agreement. Inflation The current financial statements report operating results in terms of historical cost. Even though the statements provide a reasonable, objective, quantifiable statement of financial results, they do not evaluate the impact of inflation. For ratemaking purposes, projected normal operating costs include impacts of inflation recoverable in revenues. However, electric and gas utilities, in general, are adversely impacted by inflation because depreciation of the utility plant is limited to the recovery of historical costs. Thus, cash flows from the recovery of existing utility plant, to a certain extent, may not be adequate to provide replacement of plant investment. Environmental issues Phase II of the Federal Clean Air Act amendments of 1990 sets stringent SO2 and nitrogen oxide emission limitations, which generally take effect January 1, 2000. These may result in increased expenditures. Phase II emission compliance strategies for the Company include the following: fuel switching, emission trading, purchased power agreements, new emission control devices, or installation of new fuel-burning technologies and clean coal technologies. Phase II emission compliance strategies and their costs are currently being evaluated. The Company expects no major capital expenditures as a result of Phase II. The Company is listed as a potentially responsible party on the roster of generators for the Refuse Hideaway Landfill in Middleton, Wisconsin, and the Lenz Oil site in Lemont, Illinois. The Refuse Hideaway Landfill was used for the disposal of fly-ash sludge from 1980 to 1984. The Lenz Oil Site was operated for several years as a facility for the storage and processing of waste oil. The Environmental Protection Agency (EPA) has placed the two sites on the national priorities Superfund list of sites requiring clean up under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The scope of liability under CERCLA is very broad. A group of companies is currently negotiating with the EPA on the cleanup of the sites. In the opinion of management and legal counsel, the Company's share of the final cleanup costs will not result in any materially adverse effects on the operations, cash flows, or financial position of the Company. Significant insurance recovery may also be available for the cleanup. Year 2000 The Company has established a Year 2000 project coordinator and a Year 2000 compliance team to identify our systems, equipment, and operations that will be impacted by the year 2000. These actions are necessary to ensure that the systems and applications will recognize and process the year 2000 and beyond. The Year 2000 team has started to identify the major areas that will be impacted by the year 2000 and initial conversion efforts are under way. The Company is working with suppliers, dealers, financial institutions, and others with which it does business to coordinate year 2000 conversion. The Company is estimating a cost of $2.9 million to become Year 2000 compliant. Item 8. Financial Statements and Supplementary Data Index of Consolidated Financial Statements, Footnotes, and Supplementary Data Responsibility for Financial Statements F-1 Report of Independent Accountants F-2 Consolidated Statements of Income and Retained Income F-3 Consolidated Statements of Cash Flows F-4 Consolidated Balance Sheets F-5 Consolidated Statements of Capitalization F-6 Notes to Consolidated Financial Statements F-7 - F-20 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Responsibility for Financial Statements The management of Madison Gas and Electric Company is responsible for the preparation and presentation of the financial information in this Annual Report. The following financial statements have been prepared in accordance with generally accepted accounting principles consistently applied and reflect management's best estimates and informed judgments as required. To fulfill these responsibilities, management has developed and maintains a comprehensive system of internal operating, accounting, and financial controls. These controls provide reasonable assurance that the Company's assets are safeguarded, transactions are properly recorded, and the resulting financial statements are reliable. An internal audit function assists management in monitoring the effectiveness of the controls. The Report of Independent Accountants on the financial statements by Coopers & Lybrand L.L.P. appears on page F-2. The responsibility of the independent accountants is limited to the audit of the financial statements presented and the expression of an opinion as to their fairness. The Board of Directors maintains oversight of the Company's financial situation through its monthly review of operations and financial condition and its selection of the independent accountants. The Audit Committee, comprised of all Board members who are not employees or officers of the Company, also meets periodically with the independent accountants and the Company's internal audit staff who have complete access to and meet with the Audit Committee, without management representatives present, to review accounting, auditing, and financial matters. Pertinent Items discussed at the meetings are reviewed with the full Board of Directors. /s/ David C. Mebane Chairman, President and Chief Executive Officer /s/ Terry A. Hanson Vice President - Finance Report of Independent Accountants To the Shareholders and Board of Directors, Madison Gas and Electric Company: We have audited the accompanying consolidated balance sheets and statements of capitalization of MADISON GAS AND ELECTRIC COMPANY and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income and retained income and cash flows for the years ended December 31, 1997, 1996, and 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits 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, the financial statements referred to above present fairly, in all material respects, the financial position of Madison Gas and Electric Company and subsidiaries as of December 31, 1997 and 1996, and the consolidated results of their operations and their cash flows for the years ended December 31, 1997, 1996, and 1995, in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand L.L.P. Milwaukee, Wisconsin February 6, 1998 Consolidated Statements of Income and Retained Income (Thousands of dollars, except per-share amounts)
For the years ended December 31 1997 1996 1995 CONSOLIDATED STATEMENT OF INCOME Operating Revenues: Electric $163,123 $152,747 $153,554 Gas 101,525 100,544 95,036 Total Operating Revenues 264,648 253,291 248,590 Operating Expenses: Fuel for electric generation 30,764 26,676 28,017 Purchased power 14,008 11,687 8,048 Natural gas purchased 65,079 66,021 57,488 Other operations 62,018 58,178 61,499 Maintenance 12,735 12,414 11,858 Depreciation and amortization 28,317 25,510 24,815 Other general taxes 8,797 8,736 8,709 Income tax items 11,940 12,553 14,285 Total Operating Expenses 233,658 221,775 214,719 Net Operating Income 30,990 31,516 33,871 AFUDC - equity funds 28 40 57 Other income, net 1,445 1,517 549 Writedown of nonregulated gas - (10,400) - subsidiaries, net Non-utility operating (loss)/income, net 784 (5,355) 1,000 Income Before Interest Expense 33,247 17,318 35,477 Interest Expense: Interest on long-term debt 9,641 9,815 10,331 Other interest 1,098 1,097 1,205 AFUDC - borrowed funds (15) (21) (29) Net Interest Expense 10,724 10,891 11,507 Net Income 22,523 6,427 23,970 Preferred stock dividends - - 64 Earnings on Common Stock $ 22,523 $ 6,427 $ 23,906 Earnings Per Share of Common Stock (basic and diluted) (Average shares outstanding - 16,079,718 for all years) $1.40 $0.40 $1.49 CONSOLIDATED STATEMENTS OF RETAINED INCOME Balance - Beginning of Year $50,451 $64,499 $60,851 Add - Net income 22,523 6,427 23,970 Deduct - Cash dividends on common stock (20,689) (20,475) (20,258) (Dividends per share were $1.29, $1.27, and $1.26, respectively) Preferred stock dividend - - (64) Balance - End of Year $52,285 $50,451 $64,499 The accompanying notes are an integral part of the above statements.
Consolidated Statements of Cash Flows (Thousands of dollars, except per-share amounts)
For the years ended December 31, 1997 1996 1995 Operating Activities: Net income $22,523 $ 6,427 $23,970 Items not affecting cash: Depreciation and amortization 28,317 25,510 24,815 Deferred income taxes (1,400) (7,181) (2,442) Amortization of nuclear fuel 1,517 2,098 2,740 Amortization of investment tax credits (753) (792) (768) AFUDC - equity funds (28) (40) (57) Writedown of nonregulated gas - 15,741 - subsidiaries Other 431 1,146 1,729 Net Funds Provided from Operations 50,607 42,909 49,987 Changes in working capital, excluding cash equivalents, sinking funds, maturities, and interim loans: Decrease/(increase) in current assets 6,162 (3,445) (12,168) (Decrease)/increase in current (21,174) 2,458 11,287 liabilities Other noncurrent items, net 5,244 6,386 1,716 Cash Provided by Operating Activities 40,839 48,308 50,822 Financing Activities: Cash dividends on common and preferred (20,689) (20,475) (20,322) stock Maturities/redemptions of First Mortgage (3,800) (7,840) (13,263) Bonds Increase in long-term debt 5,000 - 11,000 Other decreases in First Mortgage Bonds (163) (162) (199) Decrease in preferred stock - - (5,300) Decrease in bond construction funds, net - - 8,090 Increase/(decrease) in interim loans 3,750 9,250 (8,100) Cash Used for Financing Activities (15,902) (19,227) (28,094) Investing Activities: Acquisition of nonregulated subsidiary - - (8,036) Additions to utility plant and nuclear fuel (21,635) (21,906) (19,162) AFUDC - borrowed funds (15) (21) (29) Increase in nuclear decommissioning fund (6,467) (4,710) (4,191) Cash Used for Investing Activities (28,117) (26,637) (31,418) Change in Cash and Cash Equivalents (3,180) 2,444 (8,690) Cash and cash equivalents at beginning of period 5,288 2,844 11,534 Cash and cash equivalents at end of period $2,108 $ 5,288 $ 2,844 The accompanying notes are an integral part of the above statements.
Consolidated Balance Sheets (Thousands of dollars)
At December 31, 1997 1996 ASSETS Utility Plant, at original cost, in service: Electric $510,405 $500,690 Gas 181,861 178,312 Gross Plant in Service 692,266 679,002 Less accumulated provision for depreciation (407,602) (374,315) Net Plant in Service 284,664 304,687 Construction work in progress 10,995 7,517 Nuclear decommissioning fund 59,179 44,617 Nuclear fuel, net 8,255 8,378 Total Utility Plant 363,093 365,199 Other Property and Investments 8,252 7,115 Current Assets: Cash and cash equivalents 2,108 5,288 Accounts receivable, less reserves of $1,235 and $1,220, respectively 28,395 39,145 Unbilled revenue 13,580 13,852 Materials and supplies, at lower of average cost or market 5,557 5,740 Fossil fuel, at lower of average cost or market 3,605 1,808 Stored natural gas, at lower of average cost or market 9,851 7,189 Prepaid taxes 7,190 7,258 Other prepayments 2,081 1,429 Total Current Assets 72,367 81,709 Deferred Charges 28,078 30,146 Total Assets $471,790 $484,169 CAPITALIZATION AND LIABILITIES Capitalization (see statement) $310,846 $307,975 Current Liabilities: Long-term debt sinking fund requirements 200 200 Interim loans - commercial paper outstanding 33,500 29,750 Accounts payable 14,528 30,094 Accrued interest 2,206 2,322 Accrued nonregulated items 4,837 7,923 Other 5,326 7,732 Total Current Liabilities 60,597 78,021 Other Credits: Deferred income taxes 45,572 46,972 Regulatory liability - SFAS 109 24,875 23,914 Investment tax credit - deferred 10,685 11,439 Other regulatory liabilities 19,215 15,848 Total Other Credits 100,347 98,173 Commitments - - Total Capitalization and Liabilities $471,790 $484,169 The accompanying notes are an integral part of the above balance sheets.
Consolidated Statements of Capitalization (Thousands of dollars)
At December 31, 1997 1996 Common Shareholders' Equity: Common stock - par value $1 per share: Authorized 50,000,000 shares Outstanding 16,079,718 shares $ 16,080 $ 16,080 Amount received in excess of par value 112,558 112,558 Retained income 52,285 50,451 Total Common Shareholders' Equity 180,923 179,089 First Mortgage Bonds: 6 1/2%, 2006 Series: Pollution Control Revenue Bonds 6,675 6,875 8.50%, 2022 Series 40,000 40,000 6.75%, 2027A Series: Industrial Development Revenue Bonds 28,000 28,000 6.70%, 2027B Series: Industrial Development Revenue Bonds 19,300 19,300 7.70%, 2028 Series 21,200 25,000 First Mortgage Bonds Outstanding 115,175 119,175 Unamortized discount and premium on (1,052) (1,089) bonds, net Long-term debt sinking fund requirements (200) (200) Total First Mortgage Bonds 113,923 117,886 Other Long-Term Debt: 6.01%, due 2000 11,000 11,000 6.91%, due 2004 5,000 - Total Capitalization $310,846 $307,975 The accompanying notes are an integral part of the above statements.
Notes to Consolidated Financial Statements December 31, 1997, 1996, and 1995 1. Summary of Significant Accounting Policies a. General Madison Gas and Electric Company (the Company) is an investor-owned public utility headquartered in Madison, Wisconsin. The Company generates, transmits, and distributes electricity to about 123,000 customers in a 250-square-mile area of Dane County. The Company also transports and distributes natural gas to over 107,000 customers in 1,325 square miles of service territories in seven counties. The consolidated financial statements reflect the application of certain accounting policies described in this note. The financial statements include the accounts of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company records unbilled revenue on the basis of service rendered. Gas revenues are subject to an adjustment clause related to periodic changes in the cost of gas. Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. They also affect the disclosure of contingencies. Actual results could differ from those estimates. b. Utility Plant Utility plant is stated at the original cost of construction, which includes indirect costs consisting of payroll taxes, pensions, postretirement benefits, other fringe benefits, administrative and general costs, and an allowance for funds used during construction (AFUDC). AFUDC represents the approximate cost of debt and equity capital devoted to plant under construction. The Company presently capitalizes AFUDC at a rate of 10.76 percent on 50 percent of construction work in progress. The AFUDC rate approximates the Company's cost of capital. The portion of the allowance applicable to borrowed funds is presented in the Consolidated Statements of Income as a reduction of interest expense, while the portion of the allowance applicable to equity funds is presented as other income. Although the allowance does not represent current cash income, it is recovered under the ratemaking process over the service lives of the related properties. Substantially all of the Company's utility plant is subject to a first mortgage lien. c. Nuclear Fuel The cost of nuclear fuel used for electric generation is being amortized to fuel expense and recovered in rates based on the quantity of heat produced for the generation of electric energy by the Kewaunee Nuclear Power Plant (Kewaunee). Such cost includes a provision for estimated future disposal costs of spent nuclear fuel. The Company currently pays disposal fees to the Department of Energy based on net nuclear generation. The Company has recovered through rates and satisfied its known fuel disposal liability for past nuclear generation. The National Energy Policy Act enacted in 1992 contains a provision for all utilities that have used federal enrichment facilities to pay a special assessment for decontamination and decommissioning for these facilities. This special assessment will be based on past enrichment, and the Company has accrued and deferred an estimate of $2.2 million for the Company's portion of the special assessment. The Company believes all costs will be recovered in future rates. d. Joint Plant Ownership The Company and two other Wisconsin investor-owned utilities jointly own two electric generating facilities, which account for 54 percent (325 mw) of the Company's net generating capability. Power from the facilities is shared in proportion to the companies' ownership interests. The Company's interests are 22 percent (232 mw) of the coal-fired Columbia Energy Center (Columbia) and 17.8 percent (93 mw) of Kewaunee. Each owner provides its own financing and reflects its respective portion of facilities and operating costs in its financial statements. The Company's portions of these facilities, included in its gross utility plant in service, and the related accumulated depreciation reserves at December 31, were as follows: Columbia Kewaunee (Thousands of 1997 1996 1997 1996 dollars) Utility plant $85,183 $85,377 $57,883 $57,929 Accumulated depreciation (48,762) (46,704) (38,799) (36,271) Net Plant $36,421 $38,673 $19,084 $21,658 e. Depreciation Provisions at composite straight-line depreciation rates, excluding decommissioning costs discussed as follows, approximate the following percentages of the cost of depreciable property: electric, 3.4 percent in 1997 and 3.3 percent in 1996 and 1995; gas, 3.4 percent in 1997 and 1996 and 3.5 percent in 1995. Depreciation rates are approved by the Public Service Commission of Wisconsin (PSCW) and are generally based on the estimated economic lives of property. Nuclear decommissioning costs are being accrued to an end-of-service life of 2002 for Kewaunee. These costs are currently recovered from customers in rates and are deposited in external trusts. For 1997, the decommissioning costs recovered in rates were $4.9 million. Decommissioning costs are recovered through depreciation expense, excluding earnings on the trusts. Net earnings on the trusts are included in other income. The long- term, after-tax earnings assumption on these trusts is 5.6 percent. As of December 31, 1997, the decommissioning trusts, totaling $59.2 million, are shown on the balance sheet in the utility plant section and offset by an equal amount under accumulated provision for depreciation. The Company's share of Kewaunee decommissioning costs is estimated to be $78.8 million in current dollars based on a site-specific study performed in 1992 using immediate dismantlement as the method of decommissioning. Decommissioning costs as studied are assumed to inflate at an average rate of 6.0 percent. Physical decommissioning is expected to occur during the period 2014 through 2021, with additional expenditures being incurred during the period 2022 through 2039 related to the storage of spent nuclear fuel at the plant site. f. Income Taxes Total income taxes in the Consolidated Statements of Income are as follows: (Thousands of dollars) 1997 1996 1995 Income taxes charged to operations $11,940 $12,553 $14,285 Income taxes charged to other income 1,571 (7,942) 786 Total income taxes $13,511 $ 4,611 $15,071 Total income taxes consist of the following provision (benefit) components for the years ended December 31: (Thousands of 1997 1996 1995 dollars) Currently payable Federal $12,229 $9,317 $14,602 State 3,435 3,267 3,679 Net deferred Federal (1,308) (7,079) (2,217) State (92) (102) (225) Amortized investment tax credits (753) (792) (768) Total income taxes $13,511 $ 4,611 $15,071 Deferred income taxes are provided to reflect the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Investment tax credits from regulated operations are amortized over the service lives of the property to which they relate. The differences between the federal statutory income tax rate and the Company's effective rate are as follows:
1997 1996 1995 Statutory federal income tax rate 35.0% 35.0% 35.0% Amortized investment tax credits (2.1) (7.2) (2.0) State income taxes, net of federal benefit 5.9 7.3 5.8 Valuation allowance (0.2) 10.9 - Other, individually insignificant (1.1) (4.2) (0.2) Effective income tax rate 37.5% 41.8% 38.6%
The significant components of deferred tax liabilities (assets) that appear on the Consolidated Balance Sheets as of December 31 are as follows: (Thousands of dollars) 1997 1996 Property-related $57,951 $59,522 Other 6,026 6,788 Gross deferred income tax liabilities 63,977 66,310 Accrued expenses (6,344) (7,629) Other (3,166) (3,311) Deferred tax regulatory (9,983) (9,598) account Gross deferred income tax assets (19,493) (20,538) Less valuation allowance 1,088 1,200 Net deferred income tax assets (18,405) (19,338) Deferred income taxes $ 45,572 $ 46,972 Excess deferred income taxes, resulting chiefly from taxes provided at rates higher than current rates, have been recorded as a net regulatory liability ($24.9 million and $23.9 million at December 31, 1997 and 1996, respectively), refundable through future rates. As discussed in Note 4, on page F-17, the Company's nonregulated gas marketing subsidiaries have entered into a joint venture with an unrelated third party. Realization of state deferred tax assets including net operating loss carryforwards of these subsidiaries is dependent on future income of the joint venture in states where the subsidiaries file separate tax returns. Due to the circumstances associated with these temporary differences, a valuation allowance was established at December 31, 1997 and 1996, for these deferred tax assets. For tax purposes, these subsidiaries, as of December 31, 1997, had approximately $10.4 million of state tax net operating loss carryforwards which expire, if unused, in the year 2012. g. Pension Plans The Company maintains two defined benefit plans for its employees. The pension benefit formula used in the determination of pension costs is based on the average compensation earned during the last five years of employment for the salaried plan and career earnings for the nonsalaried plan subject to a monthly maximum. Effective January 1, 1995, the Company began recovering pension costs in customer rates under Statement of Financial Accounting Standard (SFAS) No. 87, "Employers' Accounting for Pensions." Prior to this date, pension costs were recovered in rates as funded. The plans' assets are in a master trust with a bank. The funded status of the plans at December 31 is as follows: (Thousands of dollars) 1997 1996 Fair value of plan assets $70,298 $58,770 Actuarial present value of benefits rendered to date - Accumulated benefits based on compensation to date, including vested benefits of $47,958 and $40,840 respectively 54,025 46,019 Additional benefits based on estimated future salary levels 11,085 9,093 Projected benefit obligation $65,110 $55,112 Plan assets greater than projected benefit obligation 5,188 3,658 Unrecognized net (gain) (6,390) (5,381) Unrecognized prior service cost 1,140 1,004 Net liability $ (62) $ (719) Components of net pension costs for the years ended December 31 are: (Thousands of dollars) 1997 1996 1995 Service costs (benefits earned during the period) $1,616 $1,715 $1,416 Interest costs on projected benefit obligation 4,421 4,090 3,724 Actual return on plan (12,244 (7,302) (10,033) Net amortization and Net pension costs $649 $1,056 $1,573 The assumed rates for calculations used in the above tables were: 1997 1996 1995 Expected long-term rate of return on plan assets 9.50% 9.50% 9.50% Average rate of increase in salaries 5.00% 5.00% 5.00% Weighted average discount rate 7.25% 7.75% 7.25% In addition to the noted plans, the Company also maintains two defined-contribution 401(k) benefit plans for its employees. The Company's costs of the 401(k) plan was $0.3 million in 1997 and $0.2 million in years 1996 and 1995. h. Postretirement Benefits Other Than Pensions The Company provides health care and life insurance benefits for its retired employees, and substantially all of the Company's employees may become eligible for these benefits upon retirement. These benefits are accrued over the period in which employees provide services to the Company. The Company has elected to recognize the cost of its transition obligation (the accumulated postretirement benefit obligation as of January 1, 1993) by amortizing it on a straight-line basis over 20 years. The Company's obligation and costs are based on a discount rate of 7.25 percent in 1997, 7.75 percent in 1996, and 7.25 percent in 1995. The net periodic benefit costs for the years 1997 through 1995 were based on an assumed long-term rate of return on plan assets of 9.5 percent. The assumed rate of increase in health care costs (health-care-cost trend rate) is 10 percent in 1997, decreasing gradually to 5 percent in 2003 and remaining constant thereafter. Increasing the health-care-cost trend rates of future years by one percentage point would increase the accumulated postretirement benefit obligation by $2.8 million and would increase annual aggregate service and interest costs by $0.4 million. The Company's policy is to fund the obligation to the yearly maximum through tax-advantaged vehicles. The plan's assets are in trust or on reserve with an insurance company. The funded status of the plan at December 31 is as follows: (Thousands of dollars) 1997 1996 Accumulated postretirement benefit obligation (APBO): Retirees $(4,122) $(4,192) Fully eligible active plan participants (2,091) (1,662) Other active plan participants (9,570) (8,526) Total $(15,783) $(14,380) Plan assets at fair value 4,467 3,602 APBO in excess of plan assets (11,316) (10,778) Unrecognized transition obligation 6,511 6,945 Unrecognized prior service costs 2,111 2,000 Unrecognized gain (1,832) (1,825) Accrued postretirement benefit liability $(4,526) $(3,658) Components of net periodic benefit costs for the years ended December 31 are as follows: (Thousands of dollars) 1997 1996 1995 Service cost $490 $546 $429 Interest cost on APBO 1,062 1,062 989 Actual return on plan assets (388) (287) (177) Net amortization and deferral 583 622 606 Regulatory effect based on phase in - 402 95 Net periodic benefit cost $1,747 $2,345 $1,942 i. Fair Value of Financial Instruments At December 31, 1997, the carrying amount of cash and cash equivalents approximates fair value. The estimated fair market value of the Company's First Mortgage Bonds and other long-term debt, based on quoted market prices at December 31, is as follows: (Thousands of dollars) 1997 1996 Carrying amount (includes sinking funds) $131,175 $130,175 Fair market value $137,611 $136,332 2. Capitalization Matters a. First Mortgage Bonds and Other Long-Term Debt On April 18, 1997, the Company purchased on the open market $3.8 million of its 7.70%, 2028 series, First Mortgage Bonds. The Company purchased these bonds at a discount and later retired them. On June 10, 1997, the Company entered into a fixed interest rate agreement in a principal amount of $5.0 million at 6.91%, maturing on June 10, 2004. The annual sinking fund requirements of the outstanding First Mortgage Bonds is $0.2 million in 1998 through 2002. b. Preferred Stock The Company has 1,175,000 shares of $25 par value redeemable preferred stock, cumulative, that is authorized but unissued at December 31, 1997. c. Notes Payable to Banks, Commercial Paper, and Lines of Credit For short-term borrowings, the Company generally issues commercial paper (issued at the prevailing discount rate at the time of issuance) which is supported by unused bank lines of credit. Through negotiations with several banks, the Company had $52 million in bank lines of credit. Information concerning short-term borrowings for the years is set forth below: (Thousands of dollars) December 31: 1997 1996 1995 Available lines of credit (MGE) $52,000 $45,000 $35,000 Available lines of credit (GLENCO) $ - $10,000 $ 5,000 Commercial paper outstanding $33,500 $29,750 $20,500 Weighted average interest rate 6.06% 5.63% 5.86% During the year: Maximum short-term borrowings $33,500 $29,750 $28,600 Average short-term borrowings $16,816 $13,805 $16,091 Weighted average interest rate 5.68% 5.53% 6.03% 3. Rate Matters The Company received an interim rate order from the PSCW in March 1997. Effective with the order, the Company collected a 0.507 cents per kilowatt-hour surcharge on customers' bills to cover costs incurred by the Company while Kewaunee remained out of service. Additional replacement power costs in the amount of about $1.0 million per month were recovered through the customer surcharge during the period March 6, 1997, through July 1, 1997. In August 1997, the PSCW's rate order became effective increasing electric rates $4.9 million, or 3.1 percent, and natural gas rates $3.5 million, or 3.5 percent. These rates will remain in place until the next test year, which is scheduled to begin January 1, 1999. These current rates are based on an authorized return on common stock equity of 12.0 percent. The proposed early recovery of the Kewaunee investment and accelerated decommissioning collections are the primary reasons for the increase in electric rates. Gas rates increased due to substantial technology upgrades and infrastructure improvements as well as higher operating costs due to inflation. Prior to the recently approved increases, electric rates had not been increased since 1990 and were reduced in 1993 and 1994. Gas rates had not been increased since 1989 and were reduced in 1990, 1992 and 1993. The co-owners of Kewaunee filed an application with the PSCW in November 1997 for a customer surcharge to recover costs associated with the 1997 steam generator repairs. The Company's portion of these costs is approximately $1.8 million (excluding carrying costs). The Company requested recovery of these costs through a customer surcharge which would be collected over a four-month period in 1998. The PSCW approved, at its open meeting on March 19, 1998, the Company's request for a customer surcharge relating to recovery of 1997 steam generator repair costs. 4. Gas Marketing Subsidiaries In December 1996, the Company wrote down its investment in both Great Lakes Energy Corp. (GLENCO) and American Energy Management Inc. (AEM), the Company's gas marketing subsidiaries, to properly reflect current value. The write down resulted in an after-tax charge to income of $10.4 million. As of December 31, 1997, a $4.8 million liability remains to account for the remaining commitment and contingencies related to this writedown. GLENCO and AEM formed a joint venture with another gas marketing company effective January 1, 1997. The joint venture is called National Energy Management L.L.C. and is based in Chicago. Also in December 1996, the Company had a one-time after-tax charge of $1.6 million on net income. The charge resulted from a refund to the Company's natural gas customers. Under a sharing mechanism with GLENCO, an economic benefit based on GLENCO's net income was passed back to the Company's natural gas utility customers. 5. Commitments Utility plant construction expenditures for 1998, including the Company's proportional share of jointly owned electric power production facilities and purchases of fuel for Kewaunee, are estimated to be $46 million and substantial commitments have been incurred in connection with such expenditures. Significant commitments have also been made for fuel for Columbia. 6. Segments of Business The table below presents information pertaining to the Company's segments of business. Information regarding the distribution of net assets between electric and gas for the years ended December 31 is set forth on page II-2.
(Thousands of dollars) 1997 1996 1995 Electric Operations Total revenues $163,123 $152,747 $153,554 Operation and maintenance expenses 100,854 90,862 89,994 Depreciation and amortization 22,799 20,094 19,503 Other general taxes 6,937 7,000 6,908 Pre-tax Operating Income $ 32,533 $ 34,791 $ 37,149 Income taxes 9,106 10,221 11,193 Net Operating Income $ 23,427 $ 24,570 $ 25,956 Construction and Nuclear Fuel Expenditures (Electric) $ 16,849 $ 16,855 $ 14,006 Gas Operations Operating revenues $101,525 $100,544 $ 95,036 Revenues from sales to electric utility 6,038 2,304 3,100 Total Revenues 107,563 102,848 98,136 Operation and maintenance expenses 89,788 86,418 80,017 Depreciation and amortization 5,518 5,416 5,312 Other general taxes 1,860 1,736 1,801 Pre-tax Operating Income 10,397 9,278 11,006 Income taxes 2,834 2,332 3,091 Net Operating Income $ 7,563 $ 6,946 $ 7,915 Construction Expenditures (Gas) $ 4,786 $ 5,051 $ 5,156
7. Supplemental Cash Flow Information For purposes of the Consolidated Statements of Cash Flows, the Company considers cash equivalents to be those investments that are highly liquid with maturity dates of less than three months. Cash payments for interest and income taxes for the years ended December 31 were as follows: (Thousands of Dollars) 1997 1996 1995 Interest paid, net of amounts capitalized $10,841 $10,932 $11,894 Income taxes paid, net $15,365 $16,041 $18,016 8. Regulatory Assets and Liabilities Pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company capitalizes, as deferred charges, incurred costs that are expected to be recovered in future electric and natural gas rates. The Company also records as other credits, obligations to customers to refund previously collected revenue or to spend revenue collected from customers on future costs. The Company's regulatory assets and liabilities, included in deferred charges and credits on the balance sheet, consisted of the following as of December 31:
1997 1996 (Thousands of Dollars) Assets Liabilities Assets Liabilities Demand-side management $10,052 $ 759 $12,284 $ 728 Decommissioning and decontamination 2,300 2,211 2,403 2,403 Unamortized debt expense 5,072 - 5,260 - Other postretirement benefits 58 4,567 - 3,481 Kewaunee outage/repairs 2,052 933 - - Summer power shortages 1,704 - - - Subtotal regulatory assets/liabilities 21,238 8,470 19,947 6,612 Other deferred items 6,840 10,745 10,199 9,236 Subtotal deferred items 28,078 19,215 30,146 15,848 Regulatory liability - SFAS 109 - 24,875 - 23,914 TOTAL $28,078 $44,090 $30,146 $39,762
PART III. Item 10. Directors and Executive Officers of the Registrant Information concerning the Directors of the Company is contained in the definitive proxy statement under the section "Election of Directors" filed on March 23, 1998, with the Securities and Exchange Commission, which is incorporated herein by reference. Executive Officers of the Registrant (elected annually by Directors)
Effective Service Years Executive Title Date as an Officer David C. Mebane Chairman, President and CEO 05/09/94 17 Age: 64 President, CEO and COO 01/01/94 President and COO 10/01/91 Mark C. Williamson Senior Vice President - Energy Services 05/01/95 6 Age: 44 Vice President - Energy Services 05/03/93 Assistant Vice President - Energy Services 11/01/92 Gary J. Wolter Senior Vice President - Administration and 7 Age: 43 Secretary 05/01/95 Vice President - Administration and Secretary 12/01/91 Ronald L. Semmann Group Vice President 01/01/98 1 Age: 62 Vice President - Human Resources 07/18/97 Special Assistant to the Chairman 05/12/97 James C. Boll Vice President - Law and Corporate 5 Age: 62 Communications 10/20/95 Assistant Vice President - Law and Corporate Comms. 05/03/93 Executive Director - Law and Corporate Comms. 01/13/92 Terry A. Hanson Vice President - Finance 11/01/97 7 Age: 46 Vice President and Treasurer 10/01/96 Treasurer 12/01/91 Lynn K. Hobbie Vice President - Marketing 05/01/96 4 Age: 39 Assistant Vice President - Marketing 11/01/94 Senior Director - Marketing 07/01/93 Director - Market Planning and Programs 11/01/92 Thomas R. Krull Vice President - Gas and Electric Operations 5 Age: 48 Vice President - Electric Transmission and 11/01/97 Distribution Assistant Vice President - Electric Trans. and 05/01/96 Dist. Executive Director -Electric Transmission and 05/03/93 Dist. Peter J. Waldron Vice President - Power Supply Ops. and Eng. 04/23/97 2 Age: 40 Assistant Vice President - Power Supply Ops. and Eng. 05/01/96 Executive Director - Power Supply Ops. and Eng. 10/01/95 Senior Director - Power Supply Ops. and Eng. 12/01/94 Director - Power Supply Ops. and Eng. 04/01/93 Manager - Power Supply Ops. and Eng. 02/01/92 Jeffrey C. Newman Treasurer 11/01/97 1 Age: 35 Executive Director - Budgets and Financial Management 05/01/96 Director - Budgets and Financial Management 08/01/92 Scott A. Neitzel Assistant Vice President - Gas Rates and Fuels 08/04/97 1 Age: 37 Joe R. Trueblood Assistant Vice President - Gas Operations 11/01/97 1 Age: 63 Director - Gas System Planning and Construction 05/01/92 Carol A. Wiskowski Assistant Vice President - Admin. and Assistant 19 Age: 58 Secretary 05/01/92
Item 11. Executive Compensation See Item 12 below. Item 12. Security Ownership of Certain Beneficial Owners and Management The required information for Items 11 and 12 is included in the Company's definitive proxy statement under the section "Executive Compensation," not including "Report on Executive Compensation" and "Company Performance," and under the section "Beneficial Ownership of Common Stock by Directors and Executive Officers" filed with the Securities and Exchange Commission on March 23, 1998, which is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions None. PART IV. Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 1a. Financial statements (consolidated, as of December 31, 1997 and 1996, and for each of the three years in the period ended December 31, 1997). Included in Part II, Item 8, of this report: - Responsibility for Financial Statements - Report of Independent Accountants - Statements of Income and Retained Income - Statements of Cash Flows - Balance Sheets - Statements of Capitalization - Notes to Consolidated Financial Statements b. Financial statement schedules. None. 2. All exhibits including those incorporated by reference. Exhibits (an asterisk (*) indicates a management contract or compensatory plan or arrangement): No. Description of document 3.(i)Articles of Incorporation as in effect at May 6, 1996. (Incorporated by reference to Exhibit 3.(i) with 1996 10-K in File No. 0-1125.) 3.(ii)By-Laws as in effect at January 1, 1991. (Incorporated by reference to Exhibit 3B with 1991 10-K in File No. 0- 1125.) 4A Indenture of Mortgage and Deed of Trust between the Company and Firstar Trust Company, as Trustee, dated as of January 1, 1946, and filed as Exhibit 7-D to SEC File No. 0- 1125 and the following indentures supplemental thereto are incorporated herein by reference: Supplemental Dated Exhibit Indenture as of No. SEC File No. Tenth(1) 11/01/76 2.03 2-60227 Fourteenth 04/01/92 4C 0-1125 (1992 10-K) Fifteenth 04/01/92 4D 0-1125 (1992 10-K) Sixteenth 10/01/92 4E 0-1125 (1992 10-K) Seventeenth 02/01/93 4F 0-1125 (1992 10-K) No. Description of document 10A Copy of Joint Power Supply Agreement with Wisconsin Power and Light Company and Wisconsin Public Service Corporation dated February 2, 1967. (Incorporated by reference to Exhibit 4.09 in File No. 2-27308.) 10B Copy of Joint Power Supply Agreement (Exclusive of Exhibits) with Wisconsin Power and Light Company and Wisconsin Public Service Corporation dated July 26, 1973, amending Exhibit 5.04. (Incorporated by reference to Exhibit 5.04A in File No. 2-48781.) 10D Copy of revised Agreement for Construction and Operation of Columbia Generating Plant with Wisconsin Power and Light Company and Wisconsin Public Service Corporation dated July 26, 1973. (Incorporated by reference to Exhibit 5.07 in File No. 2-48781.) 10F* Form of Severance Agreement. (Incorporated by reference to Exhibit 10F with 1994 10-K in File No. 0-1125.) 12 Statement regarding computation of ratios (page II-2). 21 Subsidiaries of the Registrant. 23 Consent of Independent Accountants. 27 Appendix E to Item 601(c) of Regulation S-K: Public Utilities Companies Financial Data Schedule UT. 3. Reports on Form 8-K - No Current Report on Form 8-K was filed for the quarter ended December 31, 1997. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MADISON GAS AND ELECTRIC COMPANY (Registrant) Date: March 23, 1998 /s/ David C. Mebane David C. Mebane Chairman, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 23, 1998. /s/ David C. Mebane Chairman, President and Chief Executive Officer and Director (Principal Executive Officer) /s/ Terry A. Hanson Vice President - Finance (Principal Financial Officer and Principal Accounting Officer) /s/ Frank C. Vondrasek Vice Chairman and Director Jean Manchester Biddick Director /s/ Richard E. Blaney Director /s/ Regina M. Millner Director /s/ Frederic E. Mohs Director /s/ Phillip C. Stark Director /s/ H. Lee Swanson Director EX-21 2 Exhibit No. 21 Madison Gas and Electric Company and Consolidated Subsidiaries SUBSIDIARIES OF THE REGISTRANT As of December 31, 1997, the Company owned 100 percent of the voting securities of the following subsidiaries (all Wisconsin corporations): - - MAGAEL INC. - holds title to property acquired by the Company for future utility plant expansion and nonutility property. - - Central Wisconsin Development Corporation - assists new and expanding businesses throughout Central Wisconsin by participating in planning, financing, property acquisition, joint ventures, and associated activities. - - Great Lakes Energy Corp. - formed a joint venture on January 1, 1997, with American Energy Management, Inc., and another gas marketing company that markets fuels and energy services to commercial and industrial customers. (See Item 7, page II- 6, and Item 8, page F-17, for further discussion.) - - Wisconsin Resources Corporation - Inactive. - - North Central Technologies, Inc. - Inactive. - - Mid America Technologies, Inc. - Inactive. As of December 31, 1997, Great Lakes Energy Corp. owned 100 percent of the voting securities of the following subsidiary (a Wisconsin corporation): - - American Energy Management, Inc. - formed a joint venture on January 1, 1997, with Great Lakes Energy Corp. and another gas marketing company that markets nonregulated energy services, including the purchase and transportation of natural gas and other fuels for commercial and industrial customers. (See Item 7, page II-6, and Item 8, page F-17, for further discussion.) EX-23 3 Exhibit No. 23 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Madison Gas and Electric Company on Form S-3 (Registration No. 33-52491 and Registration No. 33-24115) of our report dated February 6, 1998, on our audits of the consolidated financial statements of Madison Gas and Electric Company as of December 31, 1997 and 1996, and for the years ended December 31, 1997, 1996, and 1995, which report is included in this annual report on Form 10-K. /s/ Coopers & Lybrand L.L.P. Milwaukee, Wisconsin EX-27 4
UT This schedule contains summary financial information extracted from SEC Form 10-K. Items 1 through 22 are as of December 31, 1997. Items 23 through 38 are for the twelve months ended December 31, 1997. 1,000 YEAR DEC-31-1997 DEC-31-1997 PER-BOOK 363,093 8,252 72,367 28,078 0 471,790 16,080 112,558 52,285 180,923 0 0 129,923 0 0 33,500 200 0 0 0 127,244 471,790 264,648 11,940 221,718 233,658 30,990 2,257 33,247 10,724 22,523 0 22,523 (20,689) 8,758 40,839 1.40 1.40
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