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, 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
Item 3. Legal Proceedings
None.
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, 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.
Item 7.
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, 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, 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, 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:
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, 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, 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.
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 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
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:
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, 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.
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:
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 23, 1998, 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 23, 1998, 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, 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