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 National Gas and Electric L.P. (NG&E). 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-7, and Item 8, page, 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, 1996, the Company supplied electric service to 121,959 customers, of whom 109,009 were located in the cities of Fitchburg, Madison, Middleton, and Monona, and 12,950 in adjacent areas. Of the total number of customers, 105,848 were residential and 15,972 were commercial. For 1996, residential and commercial electric service revenues comprised 35 and 49 percent, respectively, of total electric revenues. The remaining electric revenues during 1996 were from industrial sales (7 percent), sales to public authorities including the University of Wisconsin (9 percent), and sales to other utilities (less than 1 percent). The electric operations accounted for 60 percent of the total revenues of the Company.
See Item 2
Item 2. Properties
The following table presents the generating capability in service at December 31, 1996:
Commercial Net Capability No. of Plants Operation 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, 1996, are as follows:
Miles Lines Overhead Lines Underground Lines
Transmission 345 kV 124 - 138 kV 96 3 69 kV 66 18 Distribution 13.8 kV and under 1,025 734
Substation Installed Capacity (kVA)
Transmission (22) 4,132,350 Distribution (33) 361,700
Gas facilities include 1,861 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.
Item 3. Legal Proceedings
The Company filed a suit January 3, 1996, in Dane County Circuit Court charging WPL with violations of Wisconsin laws and rules in attempting to provide electric service to the new Ho Chunk bingo parlor on the southeast side of Madison. The Company also filed a complaint against WPL at the PSCW for illegally duplicating electric facilities in the same area.
The Company claims that WPL intentionally misrepresented the Company's cost for electric service to the Ho Chunk Nation, falsely advertised its services to induce the Ho Chunk Nation to enter into a contract with WPL, and improperly interfered with the Company's legal rights to serve that facility.
A decision from Dane County Circuit Judge Mark Frankel on March 10, 1997, upheld a previous ruling by the PSCW, stating that the Company, not WPL, had the right to provide electric service to the bingo parlor. This decision came in response to WPL's appeal of last summer's PSCW ruling. In July 1996, the PSCW ruled that WPL's extension of an electric distribution line to the bingo parlor violated state law and that the Company was the only utility that could legally serve the site. It also ordered WPL to remove the service extension.
Item 4.
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.
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, 1997, was 18,245. 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 1996 Dividends per 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
Common stock price range 1995 Dividends per share High Low 1995
First quarter $21 7/8 $20 5/8 $0.313
Second quarter $21 7/8 $20 1/2 $0.313
Third quarter $22 5/8 $20 3/8 $0.317
Fourth quarter $23 3/8 $21 7/8 $0.317
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
GENERAL
Certain matters that are discussed in the Management's Discussion and Analysis of Financial Condition and Results of Operations are forward-looking statements and can generally be identified as such because the content includes statements like the Company "believes," "anticipates," or "expects." Such forward-looking statements are subject to certain risks and uncertainties which could cause actual results to differ materially from those currently anticipated.
RESULTS OF OPERATIONS
Earnings overview
Earnings from Madison Gas and Electric Company's (the Company) core utility operations increased to $1.48 per share in 1996, compared to $1.42 in 1995. Earnings from utility operations were higher despite $0.9 million (after tax) of additional costs for 1996 related to the extended outage of the Kewaunee Nuclear Power Plant (Kewaunee). The Company's consolidated earnings per share 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 the Company's gas marketing subsidiaries of $5.4 million (after tax).
Consolidated earnings per share of the Company's common stock decreased to $0.40 in 1996, compared to $1.49 in 1995. The Company earned $1.0 million or $0.07 per share on its gas marketing subsidiaries in 1995.
The consolidated earnings in 1995 of $1.49 per share were lower than the $1.53 earned in 1994 due to the costs associated with industry restructuring, various regulatory filings in relation to the proposed utility mergers within the state, and a lower authorized return on common stock equity, which became effective in January 1995.
Electric sales and revenues
Electric retail sales for 1996 increased slightly from 1995, despite the cold summer experienced in 1996 compared to 1995. The increase can be attributable to an increase of 1.2 percent in the number of electric customers. The electric sales breakdown by customer class is shown in the table below:
Electric Sales % (Megawatt hours) 1996 1995 Change
Residential 725,471 735,442 (1.4)
Commercial 1,381,043 1,347,947 2.5
Industrial 289,903 292,649 (0.9)
Other 305,962 320,869 (4.6)
Total Retail 2,702,379 2,696,907 0.2
Resale - Utilities 26,815 26,344 1.8
Total Sales 2,729,194 2,723,251 0.2
Electric revenues decreased slightly in 1996 compared to 1995. The Company's electric margin decreased $3.1 million or 2.6 percent during 1996 compared to 1995. The primary factor for the decrease in the electric margin is the increase in replacement purchased power costs due to the extended outage at Kewaunee.
Electric retail sales for 1995 increased 7.1 percent from 1994. This increase is attributable to the hot and humid weather experienced in the summer of 1995. As a result of the increase in electric sales, electric revenues increased $3.9 million or 2.6 percent in 1995 compared to 1994. The increase in electric revenues occurred despite a 3.3 percent reduction to electric rates effective January 1, 1995.
Gas sales and revenues
Total gas therms delivered by the Company increased 3.3 percent in 1996 compared to 1995, largely reflecting the colder weather experienced during the first quarter of 1996. Gas therms delivered during the first quarter of 1996 increased 12.7 percent over the same 1995 period. The table below shows total gas deliveries for 1996 by customer class:
Therms Delivered % (Thousands) 1996 1995 Change
Residential 96,062 89,099 7.8
Commercial and Industrial 93,723 94,729 (1.1)
Total Retail System 189,785 183,828 3.2
Transport 37,707 36,502 3.3
Total Gas Deliveries 227,492 220,330 3.3
Gas revenues increased $5.5 million or 5.8 percent in 1996 when compared to the same period a year ago. This was mainly attributable to the increase in gas deliveries due to the cold weather experienced in the first quarter as well as the increase in the number of gas customers of 2.2 percent. The Company's gas margin (revenues less natural gas purchased) decreased $3.0 million or 8.1 percent in 1996 compared to 1995. The main reason for the decreased margin is the Company's return of $2.5 million of revenue to gas customers under a prior sharing mechanism between GLENCO and the Company (see Note 5).
Gas delivered to customers in 1995 increased 6.3 percent from 1994. Despite the increase in gas delivered in 1995, gas revenues remained constant when compared to 1994. A shift in customers from retail system rates to transportation rates is the main reason gas revenues did not increase in proportion to gas deliveries. Gas transport customer revenue is recorded on a margin basis, whereas retail system customer revenue is recorded on a total revenue basis.
Electric fuel and natural gas costs
Electric fuel costs and purchased power costs increased $2.3 million or 6.4 percent in 1996 compared to 1995. As previously mentioned, the increase is mainly attributable to the increased purchased power costs associated with replacing power caused by the extended outage at Kewaunee. Purchased power costs increased $3.6 million or 45.2 percent for 1996 over 1995. This was offset somewhat by a $1.3 million or 4.8 percent decrease in fuel used for electric generation for the same comparable periods. Kewaunee normally provides over 25 percent of the generation requirements of the Company. Electric fuel costs and purchased power costs remained constant in 1995 compared to 1994.
Natural gas costs increased $8.5 million or 14.8 percent during 1996 compared to 1995. Due to the cold first quarter experienced in 1996, the demand for natural gas increased significantly causing the cost per therm to rise accordingly. The cost per therm in 1996 increased $0.04 or 13.4 percent over 1995.
Natural gas costs decreased $2.2 million or approximately 3.7 percent during 1995 compared to 1994. This was due to a decrease in the cost per therm of approximately 3.0 percent from the previous year.
Other operating expenses
Operations and maintenance (O&M ) expenses decreased $2.8 million or 3.8 percent during 1996 compared to 1995. Management's continued effort to control O&M expenses is the primary reason for the decrease. Depreciation expense increased $0.7 million or 2.8 percent in 1996 compared to 1995. Depreciation expense related to decommissioning costs contributed $0.4 million of the increase in total depreciation expense.
Other operations increased $4.7 million or 8.3 percent during 1995 compared to 1994. This is due in part to an increase in industry restructuring costs and costs associated with participation in proposed utility merger filings.
Other nonoperating expenses
The Company's gas marketing subsidiaries had an after-tax operating loss of $5.4 million in 1996, compared to $1.0 million in after-tax operating income in 1995. The main reason for the operating losses this year is due to the increase in the cost of gas, specifically in the first quarter when the demand was the highest. In the first quarter of 1996, extremely cold weather caused natural gas supply prices to rise substantially. Gas marketing companies are severely impacted by the volatility in natural gas supply prices because they work on a margin basis (revenues less cost of gas). Therefore, when gas costs increase, profit margins are reduced.
The Company recorded a one-time write down 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 Note 4).
Total interest expense decreased $0.6 million or 5.4 percent in 1996 compared to 1995. This is mainly due to lower interest rates in 1996 than in 1995. Also, in November 1995, the Company replaced its 7 %, 2001 Series, First Mortgage Bonds, with lower cost short-term debt.
Electric and gas operations outlook
The Company anticipates electric and gas sales to each grow at a compound annual rate of 1.5 percent over the next five-year period ending December 31, 2001. The service territory remains well-insulated against economic downturns. The Company's service area is one of America's most economically vibrant. The Company expects to remain at a competitive advantage in a disaggregated electric utility market because of its low generation costs, competitive rates, and low percentage of industrial customers. The Company continues to respond with rates and services to meet the needs of its customers as the gas industry proceeds toward deregulation.
Joint venture
To strengthen its position in the gas marketing business, the Company's gas marketing subsidiaries entered into a joint venture with another gas marketing firm in January 1997. GLENCO and American Energy Management Inc. (AEM), the Company's two gas marketing subsidiaries, formed a joint venture with National Gas & Electric L.P. (NG&E) to market 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. NG&E, a unit of PanCanadian Energy, Inc., is a Houston-based gas marketing company. NG&E has a proven track record of profitability providing gas to a growing commercial and industrial customer base.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities
Cash provided by operating activities decreased $2.5 million or 4.9 percent in 1996 compared to a year ago. A portion of the decrease is attributable to an increase in the Company's net working capital. Accounts receivable increased $2.3 million or 6.3 percent in 1996 compared to a year ago. Also, stored natural gas and prepaid taxes combined increased $2.4 million or 19.9 percent over last year.
Capital requirements and investing activities
The Company's liquidity is primarily affected by the requirement of its ongoing construction program. In 1996, capital expenditures increased $2.7 million or 14.3 percent, as compared to 1995, mainly due to an increase in nuclear fuel expenditures. It is anticipated that capital expenditures will be in the range of $25 to $35 million for the years 1997 through 2001. For the five-year period ending December 31, 2001, the Company estimates that internally generated cash will provide, on average, more than 100 percent of the utility plant and nuclear fuel expenditures.
Financing activities and capitalization matters
On June 1, 1996, the Company's 5.45%, 1996 Series, First Mortgage Bonds matured. The Company was able to satisfy this $7.8 million maturity with short-term debt.
At December 31, 1996, bank lines of credit available to the Company were $55 million which included $10 million for GLENCO, a wholly owned subsidiary of the Company, and AEM, a subsidiary of GLENCO. Credit requirements for GLENCO and AEM are being transferred to NG&E and the joint venture as part of the joint venture agreement. The bank lines are generally used to support 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.
The Company anticipates it will be able to meet its construction requirements and sinking fund debt requirements with internally generated funds over the next three years.
Kewaunee Nuclear Power Plant
Kewaunee is operated by Wisconsin Public Service Corporation. 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 was removed from service on September 21, 1996, for scheduled refueling and maintenance. Inspection of previously repaired steam generator tubes disclosed more extensive tube damage than had been anticipated. Repair of the tubes using laser welding was undertaken. As of December 31, 1996, it was anticipated that repairs would be completed sometime during the first quarter of 1997. Welding was completed late in January 1997. Subsequent testing indicated that the repair of a number of the tubes was not effective. The return of Kewaunee to service will be delayed indefinitely while additional repair requirements are being investigated. Nuclear Regulatory Commission (NRC) approval is needed for these repairs and to restart the plant.
If for any reason the steam generators cannot be repaired, the Kewaunee owners would need to decide on alternatives ranging from replacing the existing steam generators to early plant closure with replacement power options. Replacement of steam generators must also be approved by the Public Service Commission of Wisconsin (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.
Even if the repairs are successful and the plant restarts, the tube repairs are expected to last only a few years. Therefore, Kewaunee would be retired prior to the expiration of the operating license in 2013 unless the steam generators are replaced.
The PSCW approved the accelerated recovery of the current undepreciated Kewaunee plant balance and the unfunded estimated costs to decommission the plant through 2002.
If Kewaunee returns to service, it will be shut down at midcycle (within one year after being returned to service) for tube inspection. If significant further tube damage is discovered during the midcycle shutdown, the NRC may not permit Kewaunee to continue to operate without replacement of the steam generators. Since the earliest date by which the steam generators could be replaced is sometime in 1999, a midcycle shutdown and subsequent requirement that the steam generators be replaced before startup could result in an extended outage.
An extended Kewaunee outage subjects the Company to increased purchased power costs and increased fuel costs and operating and maintenance costs at other generating units. Since most Kewaunee costs are incurred whether or not the plant generates electricity, an extended outage of the plant results in significant incremental costs for replacement electricity. The cost to use other generating units and to purchase replacement power is expected to cost on average $38,000 a day or approximately $3.4 million if the plant remains down through the end of the first quarter of 1997. The Company received an interim rate order from the PSCW in March 1997. The order provides for a $0.507 per kilowatt-hour surcharge on customers' bills to cover the continuing costs that will be incurred by the Company while Kewaunee remains out of service. The interim electric rate order is scheduled to remain in effect until either Kewaunee returns to service or the Company receives its final rate order. The Company anticipates it will have sufficient sources to meet its customers' energy requirements during the outage.
If Kewaunee is retired early, the Company believes it would be granted regulatory approval to recover from its customers the net plant carrying amount and the estimated costs to decommission Kewaunee in excess of the decommissioning trust assets. At December 31, 1996, the net plant carrying amount was approximately $21.7 million. The Company's share of the current estimated costs to decommission Kewaunee, assuming early retirement, exceeds the fair market value of decommissioning trust assets at December 31, 1996, by $26.2 million. If Kewaunee is retired early, the Company believes it will be able to meet its commitments to supply energy to its customers through either (1) possible investments in new generating units, and/or (2) contracting for additional purchased power. The Company is considering various options with respect to Kewaunee including divestiture or early closure of the nuclear plant.
Electric industry trend
During the past several years, the trend in the electric utility industry has been toward increased competition caused by a changing regulatory environment. In December 1995, the PSCW outlined its plan for the restructuring of the electric utility industry in Wisconsin. The PSCW's plan generally followed a plan proposed by the Company and a broad coalition of customers, public interest groups, cooperative associations, municipal power entities, organized labor, and others. Under the proposed PSCW plan, the Company is developing plans illustrating how it intends to separate generation, transmission, distribution, and energy services into separate business units. The PSCW would continue distribution and transmission regulation. To limit the market power of current transmission owners, the PSCW proposes moving either to appointment of an independent system operator or to organization of a single statewide transmission system. Additional proceedings and presentation to the state legislature on the PSCW's electric utility restructuring proposal are planned prior to the target implementation date. The targeted date under the PSCW proposal is the year 2001, at which time consumers will be able to choose their electricity provider. 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 operates under electric and natural gas utility rates that are approved by the PSCW. These rates are designed to recover the cost of service and provide a reasonable return to investors. The increasing trend toward deregulation and increased competition is causing the electric utility industry to restructure. The restructuring 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 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.
The PSCW completed its generic investigation of the natural gas industry and made a determination as to whether or not traditional regulation should be replaced with a different approach. Currently, the Company has the ability through the Purchased Gas Adjustment Clause (PGAC) to recover from its customers the cost of gas purchased by the Company on behalf of its customers. The PGAC is often referred to as a one-for-one recovery mechanism. On Novewmber 8, 1996, the PSCW issued an order stating that the Company must file a modified one-for-one recovery mechanism or an incentive mechanism. On February 7, 1997, the Company filed a modified one-for-one recovery mechanism and supporting testimony. Approval of a mechanism from the PSCW is expected by July 1, 1997. The proposed implementation date is November 1, 1997. The proposed modified one-for-one recovery mechanism provides appropriate price signals to the Company's customers while minimizing the risk to shareholders.
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," is effective for fiscal years beginning on or after December 15, 1995. SFAS 121 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. SFAS 121 also amends SFAS 71 to require the write-off of a regulatory asset if it is no longer probable that future revenues will recover the asset. The adoption of SFAS 121 did not have an impact on the Company's financial position, cash flows, or results of operations. However, the Company cannot predict what effect a competitive marketplace or future regulatory actions will have on the outcome of the application of SFAS 121.
Mergers
On May 1, 1995, Northern States Power Company and Wisconsin Energy Corporation announced a proposed merger. If approved, the two companies would form a holding company called Primergy Corporation (Primergy), creating the tenth largest utility company in the United States. The merger has been approved by the shareholders of both companies. Various regulatory agency approval is required including the Securities and Exchange Commission, NRC, Federal Energy Regulatory Commission (FERC), and state regulatory agencies.
The Company and a broad coalition of customer groups are opposing approval of the merger on the grounds that the merger would violate antitrust laws and principles by increasing the exercise of anticompetitive market power by Primergy. Studies show Primergy could significantly raise prices for electric customers in Wisconsin by exercising anticompetitive market power. Hearings on the proposed merger have been concluded before the FERC and PSCW. The Company believes that the proposed merger would have a detrimental impact on the Wisconsin economy and that approval of the merger should be denied or strongly conditioned to prevent the significant anticompetitive effects.
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 capital and operating and maintenance 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.
From 1980 to 1984, the Company disposed of fly-ash sludge at the Refuse Hideaway Landfill in Middleton, Wisconsin. In October 1992, the Environmental Protection Agency (EPA) placed the Refuse Hideaway Landfill 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.
The Company is listed as a potentially responsible party on the roster of generators for the Refuse Hideaway Landfill. A group of approximately 45 companies is currently negotiating with EPA on the cleanup of the site. 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.
Accounting principles
The Company is required to adopt Statement of Financial Accounting Standard (SFAS) No. 128, "Earnings Per Share," in 1997. SFAS 128 specifies the computation, presentation, and disclosure requirements for earnings per share. The adoption of this statement will result in the presentation by the Company of earnings per share, as defined by the statement, and is not expected to have a material impact on the earnings per share reported in the financial statements. Upon adoption of this statement, all prior-period earnings per share amounts will be restated to conform to the provisions of SFAS 128.
Item 8.
Item 8. Financial Statements and Supplementary Data
Index of Consolidated Financial Statements, Footnotes, and Supplementary Data
Responsibility for Financial Statements
Report of Independent Accountants
Consolidated Statements of Income and Retained Income
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statements of Capitalization
Notes to Consolidated Financial Statements -
Item 9.
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. 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 David C. Mebane Chairman, President and Chief Executive Officer
/s/ Joseph T. Krzos Joseph T. Krzos 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, 1996 and 1995, and the related consolidated statements of income and retained income and cash flows for the years ended December 31, 1996, 1995, and 1994. 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 audit.
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, 1996 and 1995, and the consolidated results of their operations and their cash flows for the years ended December 31, 1996, 1995, and 1994, in conformity with generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P. Milwaukee, Wisconsin February 7, 1997
Notes to Consolidated Financial Statements
December 31, 1996, 1995, and 1994.
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 122,000 customers in a 250-square-mile area of Dane County. The Company also transports and distributes natural gas to over 105,000 customers in 1,325 square miles of service territories in seven counties. The Company has served the Madison area since 1896.
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. 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 10.62 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 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 $2.4 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 dollars) 1996 1995 1996 1995
Utility plant $85,377 $85,075 $57,929 $57,853
Accumulated depreciation (46,704) (44,366) (36,271) (34,263)
Net Plant $38,673 $40,709 $21,658 $23,590
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, 3.3 percent in 1996 through 1994; gas, 3.4 percent in 1996 and 3.5 percent in 1995 and 1994. 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 accrued over the estimated service life of Kewaunee, which is through the year 2013. These costs are currently recovered from customers in rates and are deposited in external trusts. For 1996, the decommissioning costs recovered in rates were $3.1 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 6.2 percent. As of December 31, 1996, the decommissioning trusts, totaling $45 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 $70.8 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 6.1 percent. Physical decommissioning is expected to occur during the period 2014 through 2021, with additional expenditures being incurred during the period 2022 through 2050 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) 1996 1995 1994
Income taxes charged to operations $12,553 $14,285 $14,822
Income taxes charged to other income (7,942) 786 612
Total income taxes $ 4,611 $15,071 $15,434
Total income taxes consist of the following provision (benefit) components for the years ended December 31:
(Thousands of dollars) 1996 1995 1994
Currently payable Federal $ 9,317 $14,602 $10,985 State 3,267 3,679 2,804
Net deferred Federal (7,079) (2,217) 1,756 State (102) (225) 672
Amortized investment tax credits (792) (768) (783)
Total income taxes $ 4,611 $15,071 $15,434
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:
1996 1995 1994
Statutory federal income tax rate 35.0% 35.0% $35.0%
Amortized investment tax credits (7.2) (2.0) (1.9)
State income taxes, net of federal benefit 7.3 5.8 5.6
Valuation allowance 10.9 - -
Other, individually insignificant (4.2) (0.2) (0.5)
Effective income tax rate 41.8% 38.6% 38.2%
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) 1996 1995
Property-related $59,522 $59,767
Other 6,788 8,062 Gross deferred income tax liabilities 66,310 67,829
Accrued expenses (7,629) (3,571)
Other (3,311) -
Deferred tax regulatory account (9,598) (10,105) Gross deferred income tax assets (20,538) (13,676) Less valuation allowance 1,200 - Net deferred income tax assets (19,338) (13,676) Deferred income taxes $46,972 $ 54,153
Excess deferred income taxes, resulting chiefly from taxes provided at rates higher than current rates, have been recorded as a net regulatory liability ($23.9 million and $25.2 million at December 31, 1996 and 1995, respectively), refundable through future rates.
As discussed in Note 4, 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, 1996, for these deferred tax assets.
For tax purposes, these subsidiaries, as of December 31, 1996, had approximately $8.8 million of state tax net operating loss carryforwards which expire, if unused, in the year 2011.
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. Of these funded pension costs, $0.8 million was charged to operating expenses in 1994. 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) 1996 1995
Fair value of plan assets $58,010 $50,152
Actuarial present value of benefits rendered to date - Accumulated benefits based on compensation to date, including vested benefits of $40,840 and $44,554, respectively 46,019 45,574
Additional benefits based on estimated future salary levels 9,093 9,943
Projected benefit obligation $55,112 $55,517
Plan assets greater/(less) than projected benefit obligation 2,898 (5,365)
Unrecognized net (gain)/loss (4,621) 1,586
Unrecognized prior service cost 1,004 1,130
Net liability $ (719) $(2,649)
Components of net pension costs for the years ended December 31 are:
(Thousands of dollars) 1996 1995 1994
Service costs (benefits earned during the period) $1,715 $1,416 $1,462
Interest costs on projected benefit obligation 4,090 3,724 3,462
Actual (return)/loss on plan assets (6,542) (10,033) 412
Net amortization and deferral 1,793 6,466 (4,056)
Regulatory effect based on funding - - (186)
Net pension costs $1,056 $1,573 $1,094
The assumed rates for calculations used in the above tables were:
1996 1995 1994
Expected long-term rate of return on plan assets 9.50% 9.50% 9.00%
Average rate of increase in salaries 5.00% 5.00% 5.00%
Weighted average discount rate 7.75% 7.25% 8.25%
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 for the years 1996 through 1994 were $0.2 million for each year.
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 7.75 percent in 1996, 7.25 percent in 1995, and 8.25 percent in 1994. The assumed rate of increase in health care costs (health-care-cost trend rate) is 11 percent in 1996, 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 $2.5 million and would increase annual aggregate service and interest costs by $0.3 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) 1996 1995
Accumulated postretirement benefit obligation (APBO):
Retirees $(4,192) $(4,054)
Fully eligible active plan participants (1,662) (1,701)
Other active plan participants (8,526) (7,986)
Total (14,380) (13,741)
Plan assets at fair value 3,581 2,666
APBO in excess of plan assets (10,799) (11,075)
Unrecognized transition obligation 6,945 7,379
Unrecognized prior service costs 2,000 2,166
Unrecognized gain (1,804) (1,129)
Accrued postretirement benefit liability $(3,658) $(2,659)
Components of net periodic benefit costs for the years ended December 31 are as follows:
(Thousands of dollars) 1996 1995 1994
Service cost $ 546 $ 429 $ 402
Interest cost on APBO 1,062 989 772
Actual return on plan assets (266) (177) (91)
Net amortization and deferral 601 606 427
Regulatory effect based on phase in 402 95 (115)
Net periodic benefit cost $2,345 $1,942 $1,395
i. Fair Value of Financial Instruments
At December 31, 1996, 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) 1996 1995
Carrying amount (includes sinking funds) $130,175 $138,215
Fair market value $136,332 $149,469
2. Capitalization Matters
a. First Mortgage Bonds and Other Long-Term Debt
The annual sinking fund requirements of the outstanding first mortgage bonds is $0.2 million in 1997 through 2001. In June 1996, the $7.8 million, 5.45%, 1996 Series, First Mortgage Bonds were retired.
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, 1996.
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 $55 million in bank lines of credit, which included $10 million for Great Lakes Energy Corp. (GLENCO) and American Energy Management Inc. (AEM).
Information concerning short-term borrowings for the years is set forth below:
(Thousands of dollars) December 31: 1996 1995 1994
Available lines of credit (MGE) $45,000 $35,000 $32,000
Available lines of credit (GLENCO) $10,000 $5,000 -
Commercial paper outstanding $29,750 $20,500 $28,600
Weighted average interest rate 5.63% 5.86% 6.06%
During the year:
Maximum short-term borrowings $29,750 $28,600 $29,500
Average short-term borrowings $13,805 $16,091 $16,549
Weighted average interest rate 5.53% 6.03% 4.57%
3. Rate Matters
In September 1996, the Company announced its intention to increase electric rates for the test period beginning July 1, 1997, by $7.7 million or 5.1 percent annually and increase natural gas rates by $3.7 million or 3.8 percent annually for the same time period. The proposed changes are based on a requested return on common equity of 12.0 percent and would remain in effect through 1998. The proposed early recovery of the Kewaunee investment and accelerated decommissioning collections are the primary reasons for the increase in electric rates. Hearings will be held during April 1997 with a decision expected by the end of the second quarter of 1997.
The Company filed an application with the PSCW in December 1996 for interim electric rate relief for the first half of 1997. The reason for the interim request is a prolonged outage at Kewaunee, increasing maintenance costs and replacement power normally supplied by Kewaunee. The Company received an interim rate order from the PSCW in March 1997. The order provides for a $0.507 per kilowatt-hour surcharge on customers' bills to cover the continuing costs that will be incurred by the Company while Kewaunee remains out of service. The interim electric rate order is scheduled to remain in effect until either Kewaunee returns to service or the Company receives its final rate order.
4. Gas Marketing Subsidiaries
The Company continually evaluates its asset base, including certain intangible assets such as goodwill, for events or changes in circumstances that indicate the carrying amount of the assets may not be recoverable. Throughout 1996, the Company experienced a decline in operating margins and continuing operating losses at the Company's gas marketing subsidiaries. This prompted the Company to evaluate the assets of the two companies for potential impairment. In the Company's evaluation, it found that some of the assets would not be recoverable. Thus, in December 1996, the Company wrote down its assets in both GLENCO and AEM to properly reflect the current value. The write down resulted in an after-tax charge to income of $10.4 million.
GLENCO and AEM, two unregulated gas marketing subsidiaries, formed a joint venture, effective January 1, 1997, with National Gas & Electric L.P. (NG&E) 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. NG&E, a unit of PanCanadian Energy, Inc., is a Houston-based gas marketing company. The partnership gives GLENCO and AEM customers additional services to strengthen their competitive edge while at the same time joining forces with a gas marketing firm with a proven record. NG&E will actively manage the joint venture.
5. GLENCO Economic Benefit
In the fourth quarter of 1996, the Company had a one-time charge resulting from a refund to its natural gas customers. Under a sharing mechanism with GLENCO, an economic benefit based on GLENCO's net income was to be passed back to the Company's natural gas utility customers.
GLENCO's economic benefit was $2.5 million plus an additional $0.2 million in interest, which was added to compensate the natural gas utility customers for the time funds were retained, for a total refund of $2.7 million. This has an after-tax impact of $1.6 million on net income. The refund was properly credited to customers through the Purchased Gas Adjustment Clause.
6. Commitments
Utility plant construction expenditures for 1997, including the Company's proportional share of jointly owned electric power production facilities and purchases of fuel for Kewaunee, are estimated to be $31 million, and substantial commitments have been incurred in connection with such expenditures. Significant commitments have also been made for fuel for Columbia.
7. 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) 1996 1995 1994
Electric Operations
Total revenues $152,747 $153,554 $149,665 Operation and maintenance expenses 90,862 89,994 87,748 Depreciation and amortization 20,094 19,503 17,337 Other general taxes 7,000 6,908 6,907 Pre-tax Operating Income 34,791 37,149 37,673 Income taxes 10,221 11,193 11,717 Net Operating Income $ 24,570 $ 25,956 $ 25,956 Construction and Nuclear Fuel Expenditures (electric) $ 16,855 $ 14,006 $ 16,804
Gas Operations
Operating revenues $100,544 $ 95,036 $ 95,307 Revenues from sales to electric utility 2,304 3,100 1,671 Total Revenues 102,848 98,136 96,978 Operation and maintenance expenses 86,418 80,017 79,009 Depreciation and amortization 5,416 5,312 5,046 Other general taxes 1,736 1,801 1,712 Pre-tax Operating Income 9,278 11,006 11,211 Income taxes 2,332 3,091 3,105 Net Operating Income $ 6,946 $ 7,915 $ 8,106 Construction expenditures (gas) $ 5,051 $ 5,156 $ 9,625
8. 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) 1996 1995 1994
Interest paid, net of amounts capitalized $10,932 $11,894 $11,235
Income taxes paid $16,041 $18,016 $13,602
9. Regulatory Assets and Liabilities
Pursuant to SFAS 71, 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 consisted of the following as of December 31:
1996 1995
(Thousands of dollars) Assets Liabilities Assets Liabilities
Demand-side management $12,284 $ 728 $14,169 $ 213
Decommissioning and decontamination 2,403 2,403 2,569 2,569
Unamortized debt expense 5,260 - 5,448 -
Other postretirement benefits - 3,481 - 2,516
Other 10,199 9,236 11,461 8,602
Other regulatory assets/liabilities $30,146 $15,848 $33,647 $13,900
Regulatory liability - SFAS 109 - 23,914 - 25,177
Total $30,146 $39,762 $33,647 $39,077
PART III.
Item 10.
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 24, 1997, with the Securities and Exchange Commission, which is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation
See Item 12
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 24, 1997, which is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions
None.
PART IV.
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
1a. Financial statements (consolidated, as of December 31, 1996 and 1995, and for each of the three years in the period ended December 31, 1996). 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.
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.
Tenth1 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)
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 - The Company filed a Current Report on Form 8-K dated December 31, 1996, under Item 5, "Other Events," which contains, under Exhibit 99, a press release announcing that its fourth-quarter and year-end earnings were negatively impacted by several factors.
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 24, 1997 /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 24, 1997.
/s/ David C. Mebane Chairman, President and Chief Executive David C. Mebane Officer and Director (Principal Executive Officer)
/s/ Joseph T. Krzos Vice President - Finance (Principal Joseph T. Krzos Financial Officer and Principal Accounting Officer)
/s/ Frank C. Vondrasek Vice Chairman and Director Frank C. Vondrasek
Jean Manchester Biddick Director
/s/ Richard E. Blaney Director Richard E. Blaney
/s/ Regina M. Millner Director Regina M. Millner
/s/ Frederic E. Mohs Director Frederic E. Mohs
/s/ Phillip C. Stark Director Phillip C. Stark
H. Lee Swanson Director