[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
[ ] TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the transition period from: ________________ to ________________
Indicate by check mark whether the Registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and has been subject to such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes X No
State the aggregate market value of the voting stock held by nonaffiliates of the Registrant: $481,420,828 based on a closing bid price of $28.00 as of March 15, 2002.
The number of shares outstanding of each of the issuer's classes of common stock, as of the close of the periods covered by this report, was 17,071,554 for 2001, 16,618,729 for 2000 and 16,161,305 for 1999 of Common Stock, Par Value $1 Per Share.
List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: Any annual report to security holders, any proxy or information statement and any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933.
- Definitive Proxy Statement filed prior to April 30, 2002 (Parts I and III)
Table of Contents
Item 4 - Results of Votes of Security Holders
Item 5 - Market for the Registrant's Common Stock and Related Stockholder Matters
Item 6 - Selected Financial Data
Item 7 - Management's Discussion and Analysis
of Financial Condition and
Results of Operations
Item 7A - Qualitative and Quantitative Disclosures about Market Risk
Item 8 - Financial Statements and Supplementary Data
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 10 - Directors and Executive Officers of the Registrant
Item 11 - Executive Compensation (see Item 12)
Item 12 - Security Ownership of Certain Beneficial Owners And Management
Item 13 - Certain Relationships and Related Transactions - None
Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form 8-K
GENERAL DESCRIPTION OF BUSINESS
Madison Gas and Electric Company (MGE) generates and distributes electricity to more than 128,000 customers in Dane County, Wisconsin (250 square miles), and purchases, transports, and distributes natural gas to nearly 123,000 customers in seven Wisconsin counties: Columbia, Crawford, Dane, Iowa, Juneau, Monroe, and Vernon (1,375 square miles).
As a public utility, MGE is subject to regulation by the Public Service Commission of Wisconsin (PSCW) and the Federal Energy Regulatory Commission (FERC). The PSCW has authority to regulate most aspects of MGE's business including rates, accounts, issuance of securities, and plant and transmission line siting. FERC has jurisdiction, under the Federal Power Act, over certain accounting practices and certain other aspects of MGE's business.
MGE is also subject to regulation under state and federal laws regarding air and water quality and solid waste disposal. See ENVIRONMENTAL below.
MGE was organized as a Wisconsin corporation in 1896. Its principal offices are located at 133 South Blair Street, Madison, Wisconsin 53701-1231.
ELECTRIC OPERATIONS
At December 31, 2001, MGE supplied electric service to more than 128,000 customers, of whom 113,000 were located in the cities of Fitchburg, Madison, Middleton, and Monona and 15,000 in adjacent areas. Of the total number of customers, approximately 111,000 were residential and 17,000 were commercial and industrial. Electric revenues for 2001 were comprised of residential (35%), commercial (49%), industrial (7%), sales to public authorities including the University of Wisconsin (UW) (7%), sales to other utilities, and other (2%). Electric operations accounted for 61% of MGE's total 2001 revenues.
See Item 2, Properties, for a description of MGE's electric utility plant.
MGE is a member of Mid-America Interconnected Network, Inc. (MAIN), a regional reliability group. MAIN members work together to utilize better reserve generating capacity and coordinate long-range system planning and day-to-day operations. MAIN seeks to maintain adequate planning reserve margins, ranging from 15% to 22%, for generation in the region.
MGE is also a member of the Mid-Continent Area Power Pool (MAPP) Regional Transmission Committee (RTC). RTC members pool their transmission systems, allowing each member to easily access economical energy across the upper Midwest. Each member is then compensated for energy that flows on its individual transmission system.
On October 29, 1999, Reliability 2000 legislation took effect (Part of 1999 Wisconsin Act 9). Part of Reliability 2000 required creating a statewide for-profit transmission company, American Transmission Company LLC (ATC), to own the investor-owned utilities' transmission assets. The stated purpose behind ATC is to provide reliable, economic transmission service to all customers in a fair and equitable manner. ATC is to plan, construct, operate, maintain, and expand transmission facilities it owns to provide adequate and reliable transmission of power.
MGE, along with other Wisconsin investor-owned utilities, several municipal utilities, and retail cooperatives have joined ATC by either contributing cash and/or transferring their transmission assets. ATC began operating on January 1, 2001, and is regulated by FERC.
In 2001, MGE started paying a network service fee for using the ATC transmission system. MGE's transmission assets revenue requirement will be recovered in rates for 2001 and 2002 since the impact of joining ATC was unknown at the time MGE's rates were set. However, the difference between the revenue requirement associated with the contributed transmission assets and the network service fees payable to ATC will be deferred, subject to regulatory treatment.
Fuel Supply and Generation
MGE estimates its net kilowatt-hour requirements for 2002 will be provided from the following sources: 65% from fossil-fueled steam plants, 28% from power purchases, and 7% from a combination of wind turbines, diesel generators, and oil-fired combustion turbines. Actual sources used will depend upon generating unit availability, weather, and customer demand.
MGE has a 22% ownership interest in two, 527-megawatt (MW) coal-burning units at the Columbia Energy Center (Columbia). The coal inventory supply for the units increased from 40 days on December 31, 2000, to 49 days on December 31, 2001. The co-owners' goal is to maintain approximately a 40-day inventory. The units burn low-sulfur coal obtained from the Powder River Basin coal fields located in Wyoming and Montana.
For information about a request from the U.S. Environmental Protection Agency (EPA) that affects Columbia, refer to the section on "Air Quality" under ENVIRONMENTAL below.
GAS OPERATIONS
On December 31, 2001, MGE supplied natural gas service to nearly 123,000 customers in the cities of Elroy, Madison, Middleton, Monona, Fitchburg, Lodi, Prairie du Chien, Verona, and Viroqua; 24 villages; and all or parts of 45 townships. Gas revenues for 2001 were comprised of residential (58%), commercial (38%), industrial (1%), and other (1%). Transportation service accounted for slightly more than 2% of the total 2001 gas revenues. Gas operations accounted for 39% of MGE's total revenues.
MGE can curtail gas deliveries to its interruptible customers. Approximately 4% of gas sold in 2001 was to interruptible customers.
Gas Supply
MGE has physical interconnections with ANR Pipeline Company (ANR) and Northern Natural Gas Company (NNG). MGE's primary service territory, which includes Madison and the surrounding area, receives deliveries at one NNG and four ANR gate stations. MGE also receives deliveries at NNG gate stations located in Elroy, Prairie du Chien, Viroqua, and Crawford County. Interconnections with two major pipelines provide competition in interstate pipeline service and a more reliable and economical supply mix, which includes gas from Canada and the United States mid-continent and Gulf/offshore regions.
By contract, a total of 4,943,332 dekatherms can be injected into ANR's storage fields from April 1 through October 31. These gas supplies are then available for withdrawal during the subsequent heating season November 1 through March 31. ANR's storage fields are located in Michigan. Using storage allows MGE to buy gas supplies during the summer season, when prices are normally lower, and withdraw these supplies during the winter season, when prices are typically higher. Storage also gives MGE more flexibility in meeting daily load fluctuations.
During the winter months, when customer demand is high, MGE is primarily concerned with meeting its obligation to firm customers. MGE meets customer demand by using firm supplies under contracts finalized before the heating season, supplies in storage (injected during the summer), and other firm supplies purchased during the winter period.
The prior heating season (November 2000 through March 2001) was colder than normal (8% more heating degree days). The current heating season (November 2001 through March 2002) has been 24% warmer than normal (based on actual heating degree days through January) and has caused the quantity of stored gas to be higher than normal. A heating degree day is the number of degrees that the mean daily temperature is below 65 degrees Fahrenheit.
MGE's contracts for firm transportation service include maximum daily quantities of:
- 46,572 dekatherms (excluding storage) on ANR.
- 54,719 dekatherms on NNG.
- 2,457 dekatherms into Viroqua's NNG gate station.
- 1,432 dekatherms into Crawford County's NNG gate station.
ENVIRONMENTAL
MGE is subject to state and federal regulations concerning air quality, water quality, and solid waste disposal. Those regulations affect the manner in which MGE conducts its operations, the costs of those operations, as well as some capital expenditures. It can also affect the siting, timing, and cost of new projects or other significant actions affecting the environment. MGE believes that it has met the requirements of current environmental regulations. MGE is not able to predict if compliance with future pollution control regulations will involve additional expenditures for pollution control equipment or plant modifications, operations curtailments, reductions in capacity or efficiency at existing plants, or delays in the construction and operation of future generating facilities.
The Wisconsin Department of Natural Resources (DNR) regulates pollution and environmental control matters at MGE's electric generating plants. The DNR has jurisdiction over air and water quality as well as solid and hazardous waste standards.
The ongoing issue of global warming could result in significant costs to reduce carbon dioxide emissions. MGE does not yet know the amounts of these expenditures or the period of time over which they may be required.
The National Environmental Policy Act and Wisconsin Environmental Policy Act require MGE to conduct a complete environmental review and issue a detailed environmental impact statement before obtaining necessary authorizations or permits from regulatory agencies. This applies to any new projects or other major actions that could significantly affect the environment.
Air Quality
On January 1, 2000, Phase II of the 1990 Federal Clean Air Act amendments took effect, setting new emission limits for sulfur dioxide (SO2) and nitrogen oxide (NOx). MGE's generating units meet those limits. The units were modified well in advance to meet year 2000 NOx requirements. Early modifications at Blount Generating Station (Blount) allow MGE to postpone meeting more stringent NOx requirements at this plant until 2007.
On October 27, 1998, the EPA issued final rules requiring more NOx emission reductions from sources in 22 states, including Wisconsin, to reduce the transport of ozone across state boundaries. However, a successful legal challenge resulted in excluding Wisconsin from this rule. After further modeling and research, the EPA is expected to revise or amend these rules to control NOx emissions in Wisconsin in order to help other states meet the one- and eight-hour ozone standards.
MGE is evaluating NOx compliance strategies, including fuel switching, emissions trading, purchased power agreements, new emission control devices, or installation of new fuel-burning and clean-coal technologies. Implementing any of these new measures would likely increase capital and operating and maintenance expenditures.
Wisconsin's acid rain law imposes limitations on SO2 emissions. Blount and MGE's share of Columbia are required to meet a combined SO2 emission rate of 1.20 pounds of SO2 per million Btu. MGE does not anticipate any capital expenditure in order to comply with this standard.
In December 2000, the EPA announced it would create rules to limit the amount of mercury emitted by coal- and oil-fired electric-steam generating facilities. The EPA plans to have the proposed rules published no later than December 15, 2003, and final regulations published no later than December 15, 2004. The DNR is also developing rules to limit mercury emissions from coal-fired boilers. The proposed rules require sources emitting more than 10 pounds of mercury per year to reduce emissions in phases of 30%, 50%, and 90% over 15 years. It also sets a ceiling of 10 pounds of mercury per year for smaller sources. If either of these regulations is issued, they may require MGE to evaluate emission control options for its Blount and Columbia facilities in order to comply. These controls would likely increase capital expenditures and operating and maintenance expenses.
In December 2000 and February 2001, Columbia received Requests for Information from the EPA to evaluate compliance with the Clean Air Act. Alliant Energy Corp. (Alliant), the plant operator, has responded to both of the requests and has not yet received a response from the EPA. On a broader basis, the EPA is assessing the impact of investments in utility generation capacity, energy efficiency, and environmental protection as well as assessing proposed multi-pollutant legislation. Results of this review are expected in mid-2002.
Water Quality
MGE is subject to water quality regulations issued by the DNR. These regulations include categorical-effluent discharge standards and general water quality standards. The regulations limit discharges from MGE's plants into Lake Michigan and other Wisconsin waters.
The categorical-effluent discharge standards require each discharger to use effluent-treatment processes equivalent to categorical "best practicable" or "best available" technologies under compliance schedules established under the Federal Water Pollution Control Act. The DNR has published categorical regulations for chemical discharges from electric-steam generating plants. MGE is in compliance with these standards.
Solid Waste
MGE is listed as a potentially responsible party for a site the EPA has placed on the national priorities Superfund list. The Lenz Oil site in Lemont, Illinois, was used for storing and processing waste oil for several years. This site requires clean up under the Comprehensive Environmental Response, Compensation and Liability Act. A group of companies, including MGE, is currently working on cleaning up the site.
MGE, a potentially responsible party, is also negotiating with the City of Madison for cleanup costs at the Demetral Landfill. MGE used this site for coal ash disposal from 1954 to 1959.
Management believes that its share of the final cleanup costs for all sites will not result in any materially adverse effects on MGE's operations, cash flows, or financial position. Insurance may cover a portion of the cleanup costs. Management believes that the cleanup costs not covered by insurance will be recovered in current and future rates. MGE estimates its future expense to clean up these sites could range from $250,000 to $550,000. At December 31, 2001, MGE accrued a $250,000 liability for theses matters.
GENERAL
MGE's business is seasonal based on fluctuations in weather conditions. MGE had 676 full-time employees at December 31, 2001. Information regarding MGE executive officers is included under Item 10, Directors and Executive Officers of the Registrant.
MGE's net generating capability in service at December 31, 2001, was as follows:
| Plants | Commercial Operation Date | Fuel | Net Capability (MW) | No. of Units | ||||
| Steam plants: | ||||||||
| Columbia | 1975 & 1978 | Low-sulfur coal | 232 (1,2,3) | 2 | ||||
| Blount (Madison) | 1957 & 1961 | Coal/gas | 99 | 2 | ||||
| 1938 & 1943 | Gas | 39 | 2 | |||||
| 1949 | Coal/gas | 22 | 1 | |||||
| 1964-1968 | Gas/oil | 35 | 4 | |||||
| Combustion turbines | 1964-2000 | Gas/oil | 170 | 6 | ||||
| Portable generators | 1998-2001 | Diesel | 51 | 55 | ||||
| Wind turbines | 1999 | Wind | 2 | 17 | ||||
| Total | 650 | |||||||
| 1 Base load generation
2 MGE's 22% share of two 527-MW units located near Portage, Wisconsin. The other owners are Alliant, which operates Columbia, and Wisconsin Public Service Corp. (WPSC). 3 See Item 3, Legal Proceedings. |
||||||||
MGE sold its 17.8% ownership interest in Kewaunee Nuclear Power Plant (Kewaunee)
to WPSC in 2001. Footnote 10 of the Notes to Consolidated Financial Statements
in this report includes information regarding that sale along with a description
of MGE's continuing obligations for Kewaunee beyond the closing date and MGE's
decision to exercise an option to buy electric capacity and energy from WPSC
for two years starting in 2001.
Major electric distribution lines and substations in service at December 31, 2001, are as follows:
| Miles | ||||
| Distribution Lines | Overhead | Underground | ||
| 69 kV | 7 | 1 | ||
| 13.8 kV and under | 994 | 819 | ||
| Distribution | Substations | Installed Capacity (kVA) | ||
| 69-13.8 kV | 22 | 723,000 | ||
| 13.8-4 kV | 32 | 325,000 | ||
On January 1, 2001, MGE transferred its electric transmission assets to
ATC. In exchange for its transmission plant and related deferred taxes and deferred
investment tax credits, MGE received approximately a 6% ownership interest in
ATC. MGE expects to receive a return on its investment in ATC that is approximately
equal to the return it would have earned by retaining its transmission facilities.
A small portion of the 69-kilovolt (kV) lines and substations has been classified
as distribution assets.
Gas facilities include 2,117 miles of distribution mains.
In May 1999, MGE brought an arbitration proceeding against Alliant Energy Corp., the parent company of Wisconsin Power and Light Company (WPL). The arbitration was based on a claim regarding WPL's merger into Alliant and the manner in which it was running Columbia that triggered MGE's right to acquire WPL's interest in the plant at book value.
In March 2001, MGE received an arbitration decision in the dispute. While the arbitrators did not grant the specific relief MGE sought in the arbitration (the right to purchase WPL's interest in the plant), the arbitrators recognized one of MGE's primary arguments. MGE argued that WPL had transferred its interest in the Columbia plant to its parent company, Alliant, after the merger in 1998. The arbitrators required Alliant to accept responsibility as the operator and manager of the plant. The Dane County Circuit Court confirmed the arbitration award in late November 2001.
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.
Item 5 - Market for the Registrant's Common Stock and Related Stockholder Matters
MGE common stock is traded on The Nasdaq Stock Market (Nasdaq) under the symbol MDSN. On March 15, 2002, there were approximately 18,000 stockholders of record. Effective January 1, 2001, MGE appointed Continental Stock Transfer & Trust Company to take over the transfer agent and registrar duties from Computershare Investor Services.
The table below shows high and low sales prices for the common stock on Nasdaq and dividends paid per common share for each quarter over the past two years.
| Common stock price range | |||||
| High | Low | Dividends per share | |||
| 2001 | |||||
| First quarter | $24.13 | $20.88 | $0.331 | ||
| Second quarter | $27.80 | $21.50 | $0.331 | ||
| Third quarter | $26.50 | $23.09 | $0.333 | ||
| Fourth quarter | $27.63 | $24.00 | $0.333 | ||
| 2000 | |||||
| First quarter | $20.63 | $16.75 | $0.328 | ||
| Second quarter | $21.50 | $17.25 | $0.328 | ||
| Third quarter | $23.00 | $17.50 | $0.331 | ||
| Fourth quarter | $23.69 | $20.00 | $0.331 | ||
Item 6 - Selected Financial Data
(In thousands, except per-share amounts)
| For the years ended December 31, | |||||||||
| Summary of Operations | 2001 | 2000 | 1999 | 1998 | 1997 | ||||
| Operating revenues: | |||||||||
| Electric | $203,178 | $203,176 | $185,955 | $169,563 | $163,123 | ||||
| Gas | 130,533 | 120,932 | 88,079 | 80,189 | 101,525 | ||||
| Total | 333,711 | 324,108 | 274,034 | 249,752 | 264,648 | ||||
| Operating expenses | 274,340 | 258,411 | 219,910 | 199,954 | 212,921 | ||||
| Other general taxes | 10,864 | 10,180 | 9,306 | 9,263 | 8,797 | ||||
| Income tax provision | 13,836 | 15,416 | 12,268 | 10,723 | 11,940 | ||||
| Net operating income | 34,671 | 40,101 | 32,550 | 29,812 | 30,990 | ||||
| Other income (including AFUDC-equity), net of tax | 6,263 | 1,383 | 3,235 | 3,273 | 2,257 | ||||
| Income before interest expense and cumulative effect of a change in accounting principle | 40,934 | 41,484 | 35,785 | 33,085 | 33,247 | ||||
| Interest expense (including AFUDC-debt) | 13,572 | 14,129 | 12,039 | 10,855 | 10,724 | ||||
| Net income before cumulative effect of a change in accounting principle | 27,362 | 27,355 | 23,746 | 22,230 | 22,523 | ||||
| Cumulative effect of a change in accounting principle, net of tax benefit of $78* | (117) | - | - | - | - | ||||
| Net income | $ 27,245 | $ 27,355 | $ 23,746 | $ 22,230 | $ 22,523 | ||||
| Average shares outstanding | 16,819 | 16,382 | 16,084 | 16,080 | 16,080 | ||||
| Earnings per share before cumulative effect of a change in accounting principle | $1.63 | $1.67 | $1.48 | $1.38 | $1.40 | ||||
| Cumulative effect of a change in accounting principle | (.01) | - | - | - | - | ||||
| Basic and diluted earnings per share | $1.62 | $1.67 | $1.48 | $1.38 | $1.40 | ||||
| Dividends paid per share | $1.328 | $1.318 | $1.308 | $1.298 | $1.287 | ||||
| Assets | |||||||||
| Electric | $371,423 | $395,622 | $342,130 | $311,563 | $313,855 | ||||
| Gas | 130,125 | 123,486 | 114,881 | 111,762 | 118,339 | ||||
| Assets not allocated | 39,903 | 52,496 | 38,499 | 42,940 | 39,596 | ||||
| Total | $541,451 | $571,604 | $495,510 | $466,265 | $471,790 | ||||
| Capitalization including Short-Term Debt | |||||||||
| Common shareholders' equity | $216,292 | $200,312 | $185,686 | $182,275 | $180,923 | ||||
| Long-term debt** | 177,600 | 183,637 | 159,799 | 159,761 | 129,923 | ||||
| Short-term debt | 9,500 | 44,000 | 15,750 | - | 33,500 | ||||
| Total Capitalization | $403,392 | $427,949 | $361,235 | $342,036 | $344,346 | ||||
*The change in accounting principle to 2001 net income
is due to MGE's adoption of SFAS No. 133.
**Includes current maturities.
Item 7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations
GENERAL
The following discussion provides information that management believes is relevant to an assessment and understanding of Madison Gas and Electric Company's (MGE) consolidated results of operations and financial condition. This discussion should be read in conjunction with the consolidated financial statements and notes.
Forward-Looking Statements
This report, and certain other MGE public documents, contain forward-looking statements that reflect management's current assumptions and estimates regarding future performance and economic conditions, especially as they relate to future revenues, expenses, financial resources, and regulatory matters. These forward-looking statements are made pursuant to the provisions of the Private Securities Litigation Reform Act of 1995. MGE cautions investors that forward-looking statements are subject to known and unknown risks and uncertainties that may cause MGE's actual results to differ materially from those projected, expressed, or implied. Some of those risks and uncertainties include:
- Economic and market conditions in MGE's service territory.
- Magnitude and timing of capital expenditures.
- Regulatory environment (including restructuring the
electric utility industry in Wisconsin).
- Availability and cost of power supplies.
MGE undertakes no obligation to publicly release any revision to these forward-looking statements to reflect events or circumstances after the date of this report.
RESULTS OF OPERATIONS
Earnings Overview
In 2001, MGE produced earnings of $27.2 million, or $1.62 per share, compared to the record earnings of $27.4 million, or $1.67 per share, in 2000. While electric revenues stayed the same despite a third-quarter adjustment of approximately $4.5 million reducing electric unbilled revenues (see Footnote 1.b.), electric operating income was down due to increased fuel costs, transmission wheeling expenses paid to American Transmission Company (ATC) (see Footnote 9), and higher distribution expenses. Gas operating income decreased mainly because warm weather in the fourth quarter resulted in lower gas deliveries. Other income increased substantially due to MGE's equity earnings in the ATC, gains on weather hedge instruments, and lower charitable contributions. Charitable donations were higher in 2000 due to a one-time substantial contribution to the University of Wisconsin (UW) Research Park to help expand the MGE Innovation Center. Lower interest rates, combined with less short-term debt, reduced interest expense by $0.5 million.
In 2000, MGE produced record earnings of $27.4 million, or $1.67 per share. Electric operating income was up $5.9 million due to increased sales and new generating facilities that earn a return for investors. An 8.8% increase in total gas deliveries added $1.7 million to gas operating income. Two other factors that contributed significantly to higher net income were performance-based natural gas incentives, which added $0.7 million (after tax), and pension costs, which were down $1.1 million (after tax) due to a strong performance in MGE's plan assets.
In 1999, MGE produced earnings of $23.7 million, or $1.48 per share. Revenues and net operating income were up nearly 10% in 1999 versus 1998 due to a 5.1% electric rate increase effective in January and an increase in gas margin due to higher deliveries in 1999.
Electric Sales and Revenues
During 2001, electric retail sales decreased 1.6% for the twelve months ended December 31 despite warmer-than-normal summer temperatures.
Total electric revenues remained the same for 2001, even though electric sales dropped slightly. Retail revenues were up $6.7 million, or 3.5%, despite an approximate $4.5 million reduction in the third quarter due to a change in estimated unbilled revenues, which is described below. Significant items affecting retail revenues include:
- A 3.9% electric rate increase effective January 1, 2001, combined with customer growth and greater use per customer ($5.8 million, net of the unbilled adjustment).
- A $0.001 kilowatt-hour (kWh) electric fuel surcharge effective May 9 through September 2, 2001 ($0.8 million; see Footnote 7).
The increase in retail revenues were offset by:
- A decrease in other electric revenues of $1.4 million.
- A decrease in sales for resale of $5.3 million due to a contract that expired with Wisconsin Public Power Inc. MGE sold 30 megawatts (MW) of firm energy and capacity to Wisconsin Public Power from March 1999 through September 30, 2000.
As noted above, during the third quarter MGE made an adjustment to unbilled revenues that reduced revenues by approximately $4.5 million. The adjustment was prompted by a review of MGE's assumptions regarding electricity lost in the process of transmission and distribution, or line loss. Prior to the adjustment, MGE estimated line loss based upon a computer-modeled study performed in 1985 that had been reviewed for reasonableness and, as necessary, adjusted during subsequent periods. An analysis of various operating and financial statistics in the third quarter of 2001, including the unbilled-to-billed sales ratio, indicated that the estimate for unbilled revenues needed to be adjusted. MGE made an adjustment in order to bring the unbilled-to-billed ratio into alignment with a 40% to 50% range that it would normally expect. MGE is in the process of reviewing its line loss experience and may further adjust its line loss estimate as a result of that review or any subsequent review determined by MGE to be necessary to achieve a normalized estimate of line loss. MGE also revised aspects of the calculation methodology and validation process as part of the adjustment. MGE does not expect any future revisions as a result of this analysis to be material.
Based on information available from its customer billing system, MGE has changed the method by which it incorporates unbilled consumption from prior periods into the calculation of amounts available for sale to customers during the current period. MGE revised the calculation to base the determination of unbilled quantities available for sale in the current month on the current month and the trailing two months as opposed to bringing forward the unbilled quantity from the prior months, which had the effect of cumulating any underestimated line loss amounts. The three months is based on an assumption, which MGE believes to be reasonable, that all electricity consumed by all classes of customers is billed within three months. MGE also determined that the ratio of unbilled-to-billed sales had a sufficient relationship to make that ratio, in addition to the ratio between unbilled sales and accounts receivable that was being used previously, a statistic for validating the results of its estimation methodology. See Footnote 1.b. for more information regarding the unbilled revenue estimation methodology.
| Electric sales (megawatt-hours) | 2001 | 2000 | % Change | |||
| Residential | 771,094 | 780,446 | (1.2) | |||
| Commercial | 1,543,866 | 1,577,165 | (2.1) | |||
| Industrial | 314,448 | 319,394 | (1.5) | |||
| Other | 307,132 | 307,263 | 0.0 | |||
| Total retail | 2,936,540 | 2,984,268 | (1.6) | |||
| Resale - utilities | 69,544 | 283,809 | (75.5) | |||
| Total sales | 3,006,084 | 3,268,077 | (8.0) |
In 2000, electric retail sales increased 2.5% despite cooler-than-normal summer
temperatures.
Electric revenues increased $17.2 million, or 9.3%, primarily due to:
- A 5.5% electric rate increase effective January 1, 2000, combined with customer growth and greater use per customer ($14.5 million; see Footnote 7).
- Increased revenues associated with MGE's new electric generating assets: an 83-MW natural gas-fired combustion turbine ($2.5 million) and wind energy and customer backup generation ($0.7 million).
Gas Sales and Revenues
Retail gas deliveries decreased 8.8% in 2001. Warmer weather in November and December resulted in lower gas use per customer. The average temperature for November and December 2001 was 38.5 degrees Fahrenheit, 65% warmer than the same period in 2000. Transport deliveries were up 5.2% primarily because customers who have the ability to switch to or from alternate fuels bought more gas to generate electricity or produce steam.
In 2001, gas revenues increased $9.6 million, or 7.9%. Significantly higher gas costs during the first half of the year and a 2.7% rate increase effective January 1, 2001, contributed to this increase (see Footnote 7).
The table below shows total gas deliveries by customer class.
| Therms delivered (In thousands) | 2001 | 2000 | % Change | |||
| Residential | 82,637 | 90,446 | (8.6) | |||
| Commercial and industrial | 71,169 | 78,190 | (9.0) | |||
| Total retail system | 153,806 | 168,636 | (8.8) | |||
| Transport | 47,524 | 45,193 | 5.2 | |||
| Total gas deliveries | 201,330 | 213,829 | (5.8) |
In 2000, total retail gas therms delivered by MGE rose 12.1%. Extremely cold
December weather drove up total heating degree days 6.8% (the number of degrees
that the mean daily temperature is below 65 degrees Fahrenheit) compared to
1999. The Madison area experienced its second-coldest December in recent history,
with an average temperature of 11.4 degrees Fahrenheit for the month.
Gas revenues were up $32.9 million, or 37.3%, in 2000 due to increased deliveries, higher gas costs that were passed on to customers through a purchased gas adjustment (PGA) clause authorized by the Public Service Commission of Wisconsin (PSCW), and an increase in gas incentive revenues.
Electric Fuel and Purchased Power
In 2001, fuel for electric generation increased $4.0 million, or 10.9%. Fuel costs for MGE's electric generating units were up primarily due to the increased use of base-load power plants at a marginally higher fuel cost, especially in the second quarter, and the higher cost of natural gas used to generate electricity during the first half of the year. MGE customers set a record for peak demand (714 MW) on August 7, 2001.
During 2001, purchased power decreased $0.7 million, or 3.4%. This decrease is attributed to the following:
- During the first three quarters of 2001, MGE did not need to buy additional capacity from outside sources because its base-load units operated at full capacity. In the second quarter of 2000, MGE purchased more expensive open-market replacement power during a six-week scheduled refueling and maintenance outage at the Kewaunee Nuclear Power Plant (Kewaunee).
- MGE purchased only 15 MW from Commonwealth Edison in 2001 compared to 30 MW in 2000.
The purchased power decreases described above were partially offset by the following:
- MGE executed its option to purchase 90 MW of electric capacity and energy at a fixed price from Wisconsin Public Service Corp. (WPSC) from September 24, 2001, through September 23, 2003. This option was part of the Kewaunee sale agreement between WPSC and MGE (see Footnote 10).
Electric margin (revenues less fuel and purchased power) decreased $3.3 million, or 2.2%, in 2001 primarily due to the constant revenues and increased fuel costs as previously described.
During 2000, fuel costs for electric generation rose $4.0 million, or 12.2%. Kewaunee was out of service for scheduled maintenance and refueling for approximately six weeks in 2000. To meet customer demand during this time, MGE relied on other generating units with higher fuel costs. MGE also had new generating assets come on-line in 2000, which in turn contributed to higher fuel costs.
Purchased power costs decreased $3.2 million, or 14.6%, in 2000. This decrease was primarily because MGE added new generation in 2000 and relied more on purchased power in 1999 during unexpected outages at the Columbia Energy Center's (Columbia) coal-fired plant.
Electric margins were up $16.5 million, or 12.6%, due to a 5.5% electric rate increase, growth in retail sales stemming from an increase in customers and usage per customer ($14.5 million), and revenue from a new generating asset, which went into service in June ($3.5 million). Some of the increase in the electric margin was partially offset by increased operations and maintenance expenses related to the Kewaunee outage.
Natural Gas Purchased
In 2001, natural gas purchased increased $8.6 million, or 11.0%, despite retail deliveries declining 8.8%. Even though customer use was down due to the warmer-than-normal winter weather, the average cost per therm of natural gas was up 21.8% over last year. The PGA allows MGE to pass along to customers the cost of gas, subject to certain limited incentive participation. Gas margins (revenues less gas purchased) increased $1.0 million, or 2.4%, primarily due to a 2.7% rate increase effective January 1, 2001 (see Footnote 7).
In 2000, natural gas costs rose $28.1 million, or 56.9%, due to a 12.1% increase in retail sales and significantly higher wellhead prices. Natural gas prices (cost per therm) increased more than 60% in 2000 compared to 1999. Gas margins increased $4.8 million, or 12.3%, in 2000 primarily as a result of higher retail deliveries, a $1.0 million gain for recovering certain regulatory gas assets, and a $1.2 million increase in other gas revenues related to MGE's gas cost incentives.
Other Operating Expenses
Electric. In 2001, electric operating expense increased $6.1 million, or 11.7%. The changes in electric operating expense are a result of:
- Increased transmission costs ($6.6 million), primarily attributable to the wheeling charge MGE started paying to the ATC on January 1, 2001. This wheeling charge is offset by the equity earnings in ATC for MGE's ownership interest. These equity earnings are recorded in other income.
- Nitrogen oxide (NOx) accrual ($0.9 million), which resulted from the PSCW authorizing utilities to defer all project costs for complying with the federal US Environmental Protection Agency's (EPA) new requirements on NOx emissions. In its last rate case, Docket 3270-UR-110, the PSCW allowed MGE to establish an escrow mechanism for these costs due to uncertainties regarding the amount and timing of NOx emissions remediation expenditures. The annual recovery allowed in rates is $1.6 million, of which $0.7 million is recorded in depreciation expense and $0.9 million in operating expense.
- Increased miscellaneous distribution expenses ($1.0 million).
Increases in electric operating expenses were offset somewhat by:
- Lower Kewaunee operating expenses ($2.2 million) due to three fewer months of expense after MGE sold its ownership interest in the plant (see Footnote 10) and lower administrative and general overheads.
- Decreased authorized PSCW energy conservation escrow amount ($0.8 million).
In 2000, electric operating expense rose $2.9 million, or 6.1%, primarily due to higher operating cost at Kewaunee ($0.9 million), expense for outside services ($0.8 million) and transmission wheeling cost for purchased power ($0.7 million). Several transmission contracts covered a full year in 2000 compared to a partial year in 1999.
Gas. In 2001, gas operating expense increased $1.7 million, or 8.2%. Uncollectible customer account balances were up due to significantly higher natural gas costs during the first half of the year ($1.0 million) and increased administrative and billing expenses ($0.7 million).
In 2000, gas operating expense rose $1.3 million, or 7.0%, due to higher distribution costs and other general expenses.
Maintenance expense. In 2001, electric maintenance expense was down $4.5 million, or 26.5%, primarily due to:
- Three fewer months of expense at Kewaunee after MGE sold its ownership interest in the plant (see Footnote 10) combined with lower maintenance expense, when compared to the previous year ($1.8. million).
- Lower maintenance expense at Columbia ($1.2 million).
In 2000, electric maintenance expense rose $5.2 million, or 44.1%, due to costs related to the Kewaunee outage ($3.0 million) and additional maintenance at Blount Generating Station (Blount) ($0.9 million), at one of MGE's combustion turbines ($0.5 million), and at Columbia ($0.2 million).
Depreciation. In 2001, depreciation expense increased $0.6 million, or 1.6%.
Depreciation expense for electric assets, when compared to the prior year, increased $0.7 million due to:
- Increased earnings on the decommissioning trust fund ($0.6 million, after tax), a NOx accrual ($0.7 million, see NOx accrual description under Other Operating Expenses) and the addition of electric assets designed to increase customer reliability ($1.4 million) (an 83-MW natural gas-fired combustion turbine was added during the second quarter of 2000).
And somewhat offset by:
- Reduced transmission depreciation as a result of MGE transferring substantially all of its electric transmission facilities to ATC on January 1, 2001 ($1.8 million; see Footnote 9) and the transfer of assets related to the Kewaunee sale ($0.5 million; see Footnote 10).
There were no significant impacts to gas depreciation for 2001.
In 2000, depreciation expense decreased slightly. Certain utility plant assets became fully depreciated in 2000, offsetting the impact on depreciation of utility plant additions.
Other general taxes. The increase ($0.7 million, or 6.9%) in other general taxes reflects a higher Wisconsin utility license fee tax, which is based on adjusted operating revenues of the prior year.
Income taxes. Effective income tax rates, before cumulative effect of a change in accounting principle, were consistent over the three-year period. The tax rates are 36.8%, 36.5%, and 36.9%, respectively, for 2001, 2000, and 1999. Reversing temporary differences associated with the sale of Kewaunee, including decommissioning transactions, resulted in deferred tax expense of $9.1 million for 2001 compared to a deferred tax benefit of $1.1 million for 2000. These reversing temporary differences reduced MGE's current tax expense by an equivalent amount.
Other Nonoperating Items
In 2001, other income increased $4.9 million (after tax) primarily due to:
- Equity earnings in ATC, $2.0 million (after tax) (see Footnote 9).
- A $0.6 million (after tax) gain from weather hedge instruments covering the 2001-2002 heating season.
- Gains and earnings of the decommissioning funds increased $0.6 million (after tax) when compared to the same period in 2000.
- A reduction in charitable contributions, $1.0 million (after tax).
In 2000, other income decreased $1.9 million, or 64.5%. MGE donated $1.0 million (after tax) to the MGE Innovation Center and the MGE Foundation. These donations provide substantial benefits to the community and MGE's service territory. In 1999, there was a gain in other income related to MGE's gas marketing subsidiaries that was not experienced in 2000. This also contributed to the decrease in other income. Earnings on the decommissioning fund were up $0.4 million in 2000.
In 1999, MGE wrote off $0.5 million in a related acquisition adjustment for a gas division. These two items helped offset some of the decrease in 2000.
In 1999, MGE earned $3.1 million on its decommissioning trust. These earnings are included in other income and depreciation expense. MGE also resolved certain contingencies in the amount of $1.0 million (after tax) related to its gas marketing subsidiaries. In 1996, MGE wrote down its investment in both its gas marketing subsidiaries, Great Lakes Energy Corp. (GLENCO) and American Energy Management, Inc. (AEM), to reflect its current value. These outstanding contingencies included expired lighting warranties and outstanding accounts payable for AEM and one-time benefits on some outstanding legal and tax issues for GLENCO and AEM.
Interest Expense
In 2001, total interest decreased $0.5 million, or 3.6%. Lower short-term debt, due to proceeds received from ATC (see Footnote 9) and the sale of Kewaunee (see Footnote 10), caused the decline in other interest expense of $0.6 million. In addition, MGE redeemed $6.1 million of its 6 1/2%, 2006 Series, at par on November 1, 2001.
In 2000, total interest increased $2.1 million, or 17.3%. Compared to 1999, MGE had higher levels of short-term debt and interest on $35.0 million in new long-term debt ($20.0 million issued on May 4, 2000, and $15.0 million issued on September 20, 2000).
Electric and Gas Operations Outlook
MGE anticipates electric and gas sales will grow at a compounded rate of 1.0% to 2.0% through December 2006. MGE also anticipates peak-demand growth to be approximately 3% through 2006. MGE expects to maintain a competitive advantage because of its:
- Vibrant service territory, distinguished by consistent growth, high employment and wages, and a diversified base of business, industry, government, and education.
- Competitive distribution costs, low percentage of industrial customers, and lower risk of stranded investments.
- Size and agility, which allow employees to respond quickly and offer more flexibility as customers' needs change.
MGE sold its ownership interest in Kewaunee in the fall of 2001. This will help eliminate the risk of future stranded investment. The capacity lost from Kewaunee will be replaced with purchased power contracts.
The PSCW has focused on improving the infrastructure needed in Wisconsin to provide reliable service to consumers. MGE invests in new facilities to meet its customers' needs and advocates statewide solutions that will keep pace with the growing demand for energy.
MGE and the UW continue to work on a proposal to build a natural gas-fired cogeneration plant, which is expected to cost between $175 million to $195 million. This plant will help to meet the future needs of the UW and MGE customers. This facility will produce steam heat and chilled-water air-conditioning for the UW and up to 150 MW of electricity to help meet growing customer demand in the Madison area. MGE will own the electric-generating portion of the plant. It is proposed that MGE will operate and maintain the entire plant. The unit is expected to start operating in 2004.
On February 23, 2001, MGE announced that it had secured an option agreement to own a portion of the advanced technology, coal-fired base-load generation included in Wisconsin Energy Corp.'s (WEC) "Power the Future" proposal. The proposal includes three, 600-MW coal-fired units of new generation. MGE's option rights provide for up to 1/12th ownership allotment (approximately 50 MWs) in each unit for an estimated investment over a ten-year period of $150 million to $175 million. WEC filed its construction proposal (CPCN) with the PSCW in early 2002. A decision from the PSCW is expected in 2002.
In February 2002, MGE exercised its option for the first proposed coal unit to obtain the maximum equity interest available under the agreement but not less than 50 MW. MGE's option rights may be terminated if necessary regulatory approvals are not received or WEC discontinues the project. Furthermore, MGE retains the right under the agreement with WEC to revoke the option exercise at certain points in the process including, but not limited to, any time up to 60 days prior to commencement of construction of the coal unit.
LIQUIDITY AND CAPITAL RESOURCES
Cash Provided by Operating Activities
In 2001, cash provided by operating activities increased $26.9 million, or 56.3%, compared to 2000. Decreases in customer receivables ($13.1 million) and unbilled revenues ($11.4 million) were offset by higher stored gas inventories of $6.8 million and a $4.4 million reduction in accounts payable. Deferred income taxes increased in 2001, due to the sale of Kewaunee, which resulted in the reversal of temporary differences for the plant and certain associated nuclear decommissioning liabilities and funds held in trust (see Footnote 3).
In 2000, cash provided by operating activities decreased $12.6 million, or 20.8%, compared to 1999. This was primarily due to a $27.0 million increase in current assets (excluding cash and cash equivalents) compared to 1999. Record-high gas costs forced average utility bills up about 40% during the last quarter of 2000. Higher accounts receivable ($10.2 million) and unbilled revenues ($14.7 million) contributed to the increase in MGE's current assets. Current liabilities increased in 2000 compared to 1999, somewhat offsetting the increase in current assets.
Capital Requirements and Investing Activities
In 2001, MGE's cash used for investing activities was down $60.3 million, or 71.1%, mainly because of a significant decrease in plant additions. In 2000, MGE paid $31.6 million for an 83-MW gas-fired combustion turbine. Also, in 2001 MGE received a capital distribution of $15.0 million from ATC for debt repayment (see Footnote 9) and a cash payment of $15.4 million from the sale of Kewaunee (see Footnote 10).
In 2000, MGE's cash used for investing activities increased $23.0 million, or 37.2%, due to increased plant additions of $22.6 million, mostly related to purchasing the gas-fired combustion turbine previously described.
MGE's liquidity is primarily affected by its construction requirements. Capital expenditures in 2001 totaled $42 million, which includes a coal-handling system at Blount ($4.8 million) and normal system upgrades to the distribution system. It is anticipated that 2002 capital expenditures will be $64.5 million, including the installation of an automated meter reading system ($24 million).
Capital expenditures for 2002 through 2006 will average an estimated $46.0 million per year (excluding the UW cogeneration project and MGE's option to purchase a portion of "Power the Future"). The following table shows estimated expenditures for 2002, actual for 2001 and three-year averages for 1998 to 2000.
| Capital Expenditures (including nuclear fuel) | |||||||||||
| (In thousands) For the years ended December 31 |
2002 (Estimated) |
2001 (Actual) |
Three-Year Average (1998 to 2000) |
||||||||
| Electric: | |||||||||||
| Production | $14,610 | 22.6% | $12,747 | 30.4% | $27,909 | 53.9% | |||||
| Transmission | - | - | - | - | 2,651 | 5.1% | |||||
| Distribution and general | 30,054 | 46.6% | 17,705 | 42.2% | 11,502 | 22.2% | |||||
| Nuclear fuel | - | - | 2,544 | 6.0% | 1,959 | 3.8% | |||||
| Total electric | 44,664 | 69.2% | 32,996 | 78.6% | 44,021 | 85.0% | |||||
| Gas | 15,281 | 23.7% | 7,766 | 18.5% | 5,860 | 11.3% | |||||
| Common | 4,555 | 7.1% | 1,204 | 2.9% | 1,927 | 3.7% | |||||
| Total | $64,500 | 100.0% | $41,966 | 100.0% | $51,808 | 100.0% | |||||
MGE used internally generated funds and short-term debt to satisfy most of its capital requirements for 2001. For larger capital investments, MGE issues additional long-term debt and common stock.
Financing Activities and Capitalization Matters
In 2001, cash used for financing activities was $52.0 million as MGE reduced its short-term debt by $34.5 million. MGE reduced short-term debt and redeemed $6.1 million in long-term debt by using the cash distribution from ATC and cash received from the sale of Kewaunee. MGE raised $10.9 million by issuing common stock for its Dividend Reinvestment and Direct Stock Purchase Plan (Plan). MGE issues new shares of common stock for the Plan to improve cash flow and capitalization ratios.
| Capital Structure Ratios | 2001 | 2000 |
| Common shareholders' equity | 53.6% | 46.8% |
| Long-term debt | 44.0% | 42.9% |
| Short-term debt | 2.4% | 10.3% |
In 2000, cash provided by financing activities was $39.4 million. MGE had
several large capital investments in 2000 that required issuing long-term debt
($35.0 million) and short-term debt ($28.3 million). MGE raised $9.0 million
by issuing common stock for the Plan.
MGE's First Mortgage Bonds are currently rated Aa2 by Moody's Investors Service, Inc. (Moody's) and AA by Standard & Poor's Corp. (S&P). MGE's Medium Term Notes are rated Aa3 by Moody's and AA- by S&P. MGE's dealer-issued commercial paper carries the highest ratings assigned by Moody's and S&P.
MGE's access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities' ratings. None of MGE's borrowings is subject to default or prepayment as a result of a downgrading of securities' ratings.
Contractual Obligations and Commercial Commitments
MGE's contractual obligations as of December 31, 2001, representing cash obligations that are considered to be firm commitments, are as follows:
| In thousands | Payment due within: | Due after | |||||||
| Total | 1 Year | 2-3 Years | 4-5 Years | 5 Years | |||||
| Long-term debt | $178,500 | $20,000 | $ 5,000 | $ - | $153,500 | ||||
| Short-term debt | 9,500 | 9,500 | - | - | - | ||||
| Operating leases | 9,560 | 1,010 | 1,600 | 1,050 | 5,900 | ||||
| Purchase obligations | 232,000 | 31,700 | 55,800 | 46,200 | 98,300 | ||||
| Other long-term obligations | 9,455 | 8,371 | 542 | 542 | - | ||||
| Total contractual obligations | $439,015 | $70,581 | $62,942 | $47,792 | $257,700 | ||||
For additional information about:
- Long-term debt consisting of secured First Mortgage Bonds and unsecured Medium Term Notes, see Footnote 6.c. of the Notes to Consolidated Financial Statements.
- Short-term debt consisting of commercial paper, which is supported by unused lines of credit from banks, see Footnote 6.d. of the Notes to Consolidated Financial Statements.
- Operating leases, see Footnote 8 of the Notes to Consolidated Financial Statements.
- Purchase obligations consisting of obligations to purchase electricity and to purchase and transport natural gas, see Footnote 8 of the Notes to Consolidated Financial Statements.
- Other long-term obligations, see Footnotes 1.c. and 10 of the Notes to Consolidated Financial Statements.
MGE's commercial commitments as of December 31, 2001, representing commitments triggered by future events, including financing arrangements to secure obligations of MGE, are as follows:
| In thousands | Expiration within: | Due after | |||||||
| Total | 1 Year | 2-3 Years | 4-5 Years | 5 Years | |||||
| Available lines of credit (a) | $40,000 | $40,000 | $ - | $ - | $ - | ||||
| (a) Lines of credit consisting of a 364-day credit facility to support commercial paper issuances. At December 31, 2001, there were no borrowings against the credit facility. Additionally, at December 31, 2001, there was $9.5 million of commercial paper outstanding. | |||||||||
Other Factors
Due to the performance of the US debt and equity markets, the value of assets held in trusts to satisfy the obligations of pension and postretirement benefit plans has decreased. These factors may also result in additional future funding requirements of the pension and postretirement benefit plans.
BUSINESS AND REGULATORY ENVIRONMENT
Transfer Transmission Assets to ATC
On January 1, 2001, MGE transferred substantially all of its electric transmission facilities to ATC in exchange for approximately a 6% interest in this joint venture. ATC is comprised of Wisconsin investor-owned utilities and some Wisconsin municipal utilities, cooperatives, and power supply agencies.
MGE accounts for this investment on the equity method of accounting. MGE's records as equity in earnings of the investee its share of ATC's earnings, amortization of the Statement of Financial Accounting Standards (SFAS) No. 109 regulatory liability, and deferred investment tax credits related to the transmission assets transferred to ATC. MGE recorded $3.3 million (pretax) of equity earnings in ATC as of December 31, 2001.
In the second quarter of 2001, MGE received $15.0 million in a cash distribution as a result of ATC's issuance of debt. Also during 2001, MGE received a total of $1.6 million in dividends from ATC. The dividend is a return of capital that reduces its investment in ATC.
MGE contracts with ATC for transmission services. MGE's 2001 cost of $8.1 million is included in operating expenses. Under a three-year contract beginning January 1, 2001, MGE provides various services to ATC, including fixed capital construction, operations and maintenance, and transitional services. MGE bills for these services based on its actual costs for labor, materials, and overhead. MGE billed ATC $3.7 million for these services in 2001.
MGE tracks the difference between the revenue requirement for transmission services included in its current rate tariffs and the network transmission service fee paid to ATC. The difference is deferred and subject to adjustment in MGE's next rate case. In 2001, MGE recorded a deferred asset of $0.5 million for this difference.
Kewaunee Nuclear Power Plant
Effective September 23, 2001, MGE sold to WPSC its 17.8% ownership interest in Kewaunee. In exchange for a cash payment of $15.4 million, MGE transferred its net book value of utility plant ($8.2 million), net nuclear fuel ($7.9 million), inventories ($1.5 million), and other assets ($0.1 million). These assets were offset by $2.3 million owed to WPSC. On the closing date, MGE also transferred its Qualified Decommissioning Fund ($65.0 million fair market value) and Nonqualified Decommissioning Fund ($28.1 million fair market value), which resulted in a decrease of accumulated depreciation by an equal amount. This transaction occurred in accordance with an agreement between MGE and WPSC dated September 29, 1998. That agreement requires certain continuing obligations of MGE and WPSC after the closing date, as described below.
MGE will make monthly contributions to the MGE Nonqualified Decommissioning Fund from September 23, 2001, through December 31, 2002. MGE will make monthly contributions in the amount of approximately $675,000, the level currently authorized by the PSCW. These costs are currently recovered from customers in rates. MGE's decommissioning liability is limited to the fund balances at the closing date plus all decommissioning collections through 2002. MGE's Nonqualified Decommissioning Fund is shown on the balance sheet in the Utility Plant section. As of December 31, 2001, this fund totaled $1.9 million (pretax fair market value) and is offset by an equal amount recorded in accumulated provision for depreciation. The securities and uninvested cash balances in the fund, net of trust investment expenses and taxes on investment income, will be transferred to the WPSC Nonqualified Decommissioning Fund on January 2, 2003.
The federal government is responsible for the disposition and storage of spent nuclear fuel. Federal legislation is being considered to establish an interim storage facility. Spent nuclear fuel is currently stored at Kewaunee. Minor plant modifications to the spent fuel pools in 2001 should ensure Kewaunee has sufficient fuel storage capacity until the end of its licensed life in 2013. MGE retains its spent fuel obligations for all fuel burned at Kewaunee for MGE's generation from the opening of the plant to the closing date. WPSC took title to such fuel at the closing date.
A surcharge imposed by the National Energy Policy Act of 1992 requires nuclear power companies to fund the decontamination and decommissioning of US Department of Energy facilities that process nuclear fuel. As a result, the Kewaunee co-owners are required to pay a surcharge on uranium enrichment services purchased from the federal government prior to October 23, 1992. On an inflation-adjusted basis, MGE's portion of the obligation related to Kewaunee is approximately $1.4 million at December 31, 2001. MGE is required to continue paying its portion of this annual assessment.
In accordance with the agreement, MGE exercised its option in June 2001 to buy electric capacity and energy at a fixed price from WPSC. MGE will purchase 90 MW of electric capacity and energy from September 24, 2001, through September 23, 2003, to help meet customers' electric needs.
Proposal to Form a Holding Company
In November 2001, MGE filed a registration statement on Form S-4 with the Securities and Exchange Commission regarding its proposal to create a holding company named MGE Energy, Inc. The holding company structure allows MGE to expand its options for financing new power plants to meet customers' growing demand. Electric prices will continue to be regulated by the PSCW.
Under the holding company proposal, shares of MGE common stock would be exchanged on a one-for-one basis for shares of MGE Energy, Inc. MGE shareholders will vote on the holding company proposal this spring. MGE has received FERC approval and expects PSCW approval in the summer 2002.
Form S-4 contains a preliminary joint proxy statement and prospectus of MGE and MGE Energy, Inc., and other relevant documents concerning the holding company proposal.
Industry Restructuring in Wisconsin
Wisconsin has focused on building the infrastructure needed to provide reliable electric service to customers. State regulators realize a competitive market cannot exist when supply is short. The PSCW will decide when it is appropriate for retail competition to proceed in the electric industry. MGE cannot predict what impact future PSCW actions may have on its future financial condition, cash flows, and results of operations. However, MGE believes it is well-positioned to compete.
Restructuring the electric industry could affect MGE's ability to continue establishing certain regulatory asset and liability amounts allowed under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." MGE is unable to predict whether any adjustments to regulatory assets and liabilities will occur in the future. However, the PSCW recognizes the need to allow recovery for commitments made under prior regulation.
Gas Cost Incentives
Under MGE's gas cost incentives, if actual gas commodity costs are above or below a benchmark set by the PSCW, then MGE's gas sales service customers and shareholders share equally in any increased costs or savings up to $1.5 million. Any costs or savings that exceed $1.5 million will be passed on to gas sales service customers. The PSCW allows MGE to resell gas pipeline capacity reserved to meet peak demands but not needed every day to serve customers. Revenues from capacity release that exceed or fall short of PSCW-targeted levels are shared equally. In 2001, MGE shareholders benefited $0.5 million (after tax) from capacity release revenues and commodity savings under the gas cost incentives.
Critical Accounting Policies
The preparation of financial statements in conformity with generally accepted accounting principles requires management to apply policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. Because of the inherent uncertainty in the nature of the matters where estimates are used, actual amounts could differ from estimated amounts. The following accounting policies represent those that management believes are particularly important to the financial statements and require the use of judgment in estimating matters that are inherently uncertain.
Revenues. Revenues from the sale of electricity and gas to customers are generally recorded when electricity/gas is delivered to those customers. The quantity of those sales is measured by customers' meters. Due to the large volume of those meters, it is impractical to read all of them at month end and, thus, those meters are read on a systematic basis throughout the month based on established meter-reading schedules. Consequently, at the end of any month, there exists a quantity of electricity and gas that has been delivered to customers but has not been captured by the meter readings. As a result, management must estimate revenue related to electricity and gas delivered to customers between their meter read date and the end of the period. These estimates include:
- The amount of electricity expected to be lost in the process of its transmission and distribution to customers (line loss) and, therefore, the amount of electricity actually delivered to customers.
- The mix of sales between customer rate classes, which is based upon historical utilization assumptions.
MGE believes that the ratio of unbilled-to-billed sales should typically fall in a 40% to 50% range. A ratio outside that range would indicate a need for further review and analysis. It should be noted that a small change in line loss could have a significant impact on estimated electric unbilled revenues.
Accounting for Derivative Instruments. MGE accounts for derivative financial instruments under SFAS No. 133, "Accounting for Derivatives and Hedging Activities." Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is recorded in current period earnings. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80%-120% of the changes in fair value or cash flows of the hedged item.
Regulatory Assets/Liabilities. Regulatory assets represent costs that have been deferred to future periods when it is probable or certain that the regulator will allow future recovery of those costs through rates. MGE bases its assessment of recovery by precedents established by the regulatory body. Regulatory liabilities represent previous collections from customers to fund future expected costs or amounts received in rates, which are expected to be refunded to customers in future periods. These costs typically include the recovery of stranded costs due to deregulation, deferral of energy costs, the normalization of income taxes, and the deferral of losses incurred on debt retirements. The accounting for these regulatory assets and liabilities is in accordance with the provisions of SFAS No. 71.
MGE continually assesses whether the regulatory assets continue to meet the criteria for probability of future recovery. This assessment includes consideration of factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction, and the status of any pending or potential deregulation legislation. If future recovery of costs becomes no longer probable, the assets and liabilities would be recognized as current period revenue or expense.
Amortization of regulatory assets is provided over the recovery period as provided in the related regulatory agreement and is included in depreciation and amortization expense. The most significant regulatory assets recorded by MGE include demand-side management programs, decommissioning and decontamination of Kewaunee, environmental costs, deferred charges related to the set up of the ATC, and deferred charges on the interest expense of its 2027A Series First Mortgage Bonds (see Footnote 1.f.).
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," that supersede Accounting Principles Board (APB) Opinion No. 16, "Business Combinations," and APB Opinion No. 17, "Intangible Assets." The two statements modify the method of accounting for business combinations and address the accounting and reporting for goodwill and intangible assets. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001 and, with acquisitions completed after June 30, 2001, for all business combinations accounted for by the purchase method for which the date of acquisition is completed after June 30, 2001. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. MGE does not believe this statement will have a material impact on its financial statements.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," and is effective for all companies. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible, long-lived assets. MGE expects to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. MGE is currently reviewing this statement to determine its effect on its financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which supersedes SFAS No. 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to be Disposed of," and the accounting and reporting provisions of APB No. 30, "Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets and is effective for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. MGE does not believe this statement will have a material impact on its financial statements.
INFLATION
The current financial statements report operating results in terms of historical cost, but they do not evaluate the impact of inflation. Because utilities can depreciate only the historical cost of utility plant, there may not be adequate cash flows from existing plant to replace this investment. Under PSCW rate treatment, projected operating costs, including the impacts of inflation, are recovered in revenues.
Item 7A - Qualitative and Quantitative Disclosures about Market Risk
Market risks. MGE is potentially exposed to market risk associated with interest rates, commodity prices, gas margins, and equity returns. MGE currently has no exposure to foreign currency risk. MGE manages some risk exposure through risk management policies and uses derivative instruments.
Interest rate risk. MGE issues commercial paper at varying interest rates for its short-term borrowings (see Footnote 6.b.). MGE has a swap agreement with a commercial bank at a notional amount of $5.0 million, backed by MGE's commercial paper. MGE pays a fixed rate of 6.91% on the swap, which was used to replace a portion of MGE's 7.70%, 2028 Series, First Mortgage Bonds. MGE manages its interest rate risk by limiting its variable rate exposure and continually monitoring the effects of market changes on interest rates. MGE is not exposed to changes in interest rates on its long-term debt until that debt matures and is refinanced at market rates. MGE records the changes in the fair market value currently in the income statement as required by SFAS No. 133 each period.
Commodity price risk. MGE has commodity price risk exposure with respect to the price of natural gas, electricity, coal, and oil. MGE employs established policies and procedures to reduce the market risks associated with changing commodity prices, including the use of commodity and financial instruments (see Footnote 5). MGE's commodity risks are somewhat mitigated by the current ratemaking process in place for recovering electric fuel, purchased energy, and the cost of natural gas purchased for resale. MGE's electric fuel costs are subject to fuel rules, established by the PSCW, which further mitigate commodity risk. Under fuel rules, if electric fuel costs exceed a 3% bandwidth set by the PSCW, MGE can apply for a fuel surcharge from its customers. If costs fall below the 3% bandwidth, MGE would refund money to customers. Under the PGA authorized by the PSCW, MGE passes through to customers the cost of gas, subject to certain limited incentive participation.
MGE has a limited number of financial gas commodity contracts. These contracts are primarily comprised of exchange-traded option contracts to manage the cost of gas and over-the-counter financial floating-to-fixed price swaps and calls for the Winter Set-Price Firm Gas Sales Service pilot program. The derivative amounts recorded as a result of these gas contracts are offset with a corresponding regulatory asset or liability because these transactions are part of the PGA and not subject to incentive participation.
Gas margin risk. A significant portion of MGE's gas system demand is driven by heating. MGE's gas margins (revenues less gas purchased) are collected under a combination of fixed and volumetric rates set by the PSCW based on "normal weather." As a result of weather-sensitive demand and volumetric rates, a portion of MGE's gas margin is at risk for warmer-than-normal weather. MGE uses weather derivatives, pursuant to its risk management program, to reduce the impact of weather volatility on its gas margins.
In October 2001, MGE entered into a nonexchange-traded heating degree day (HDD) collar contract covering the period November 1, 2001, through March 31, 2002, and received a premium of $20,000. A HDD is the number of degrees that the mean daily temperature is below 65 degrees Fahrenheit. The contract has cap and floor strikes of 6,000 and 5,500 HDD, respectively, a notional amount of $2,500 per HDD, a maximum HDD-related receipt or payment amount of $1.0 million, and financial settlement against Madison weather. If the total actual HDD for the contract period exceeds 6,000 HDD, MGE will pay. If the total actual HDD is less than 5,500 HDD, MGE receives payment. For the contract period, MGE's average gas margin per HDD at risk is estimated to exceed $2,500. As a result of the contract, MGE expects to gain, or lose, less gas margin than it otherwise would under all scenarios above and below 6,008 HDD, respectively. Through December 31, 2001, actual and contract midpoint allocated HDD were 1,642 and 2,171, respectively, resulting in a $1.0 million gain for MGE. Weather during February and March 2002 would need to be more than 9% colder than normal, on average, before MGE would expect to record any loss under the contract (based on actual weather through January 31, 2002).
Equity price risks. MGE currently funds its liabilities related to employee benefits and nuclear decommissioning through trust funds. These funds, which include investments in debt and equity securities, are managed by various investment managers. Changes in market value of these investments can have an impact on the future expenses related to these liabilities. MGE's risk of expense and annuity payments, as a result of changes in the market value of the trust funds, is mitigated in part through future rate actions by the PSCW.
Credit risks. MGE is obligated to provide service to all electric and gas customers within its respective franchised territories. As a result, MGE has a broad customer base. For the year ended December 31, 2001, MGE's ten largest electric customers represented approximately 17% of its retail electric revenues, and the ten largest gas customers represented approximately 4% of its gas revenues. Credit risk for electric and gas is managed by MGE's credit and collection policies, which are consistent with state regulatory requirements.
Item 8 - Financial Statements and Supplementary Data
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of Madison Gas and Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 14 (a) (1) present fairly, in all material respects, the financial position of Madison Gas and Electric Company and its subsidiaries at December 31, 2001 and December 31, 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 14 (a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 6, 2002
CONSOLIDATED STATEMENTS OF INCOME
| (In thousands, except per-share amounts) | For the years ended December 31, | ||||
| 2001 | 2000 | 1999 | |||
| Operating Revenues | |||||
| Electric | $203,178 | $203,176 | $185,955 | ||
| Gas | 130,533 | 120,932 | 88,079 | ||
| Total Operating Revenues | 333,711 | 324,108 | 274,034 | ||
| Operating Expenses | |||||
| Fuel for electric generation | 40,299 | 36,338 | 32,388 | ||
| Purchased power | 18,310 | 18,963 | 22,198 | ||
| Natural gas purchased | 86,035 | 77,482 | 49,395 | ||
| Other operations | 79,758 | 72,015 | 67,471 | ||
| Maintenance | 14,279 | 18,532 | 13,304 | ||
| Depreciation and amortization | 35,659 | 35,081 | 35,154 | ||
| Other general taxes | 10,864 | 10,180 | 9,306 | ||
| Income tax provision | 13,836 | 15,416 | 12,268 | ||
| Total Operating Expenses | 299,040 | 284,007 | 241,484 | ||
| Net Operating Income | 34,671 | 40,101 | 32,550 | ||
| Other Income and Deductions | |||||
| AFUDC - equity funds | 385 | 343 | 302 | ||
| Equity in earnings in ATC | 3,345 | - | - | ||
| Income tax provision | (2,105) | (336) | (1,608) | ||
| Other, net | 4,638 | 1,376 | 4,541 | ||
| Total Other Income and Deductions | 6,263 | 1,383 | 3,235 | ||
| Income before interest expense and cumulative effect of a change in accounting principle |
40,934 |
41,484 |
35,785 |
||
| Interest Expense | |||||
| Interest on long-term debt | 12,781 | 12,622 | 11,500 | ||
| Other interest | 1,008 | 1,683 | 694 | ||
| AFUDC - borrowed funds | (217) | (176) | (155) | ||
| Net Interest Expense | 13,572 | 14,129 | 12,039 | ||
| Net income before cumulative effect of a change in accounting principle | $ 27,362 | $ 27,355 | $ 23,746 | ||
| Cumulative effect of a change in accounting principle, net of tax benefit of $78 | (117) | - | - | ||
| Net Income | $ 27,245 | $ 27,355 | $ 23,746 | ||
| Earnings Per Share of Common Stock (basic and diluted): | |||||
| Income before cumulative effect of a change in accounting principle | $1.63 | $1.67 | $1.48 | ||
| Cumulative effect of a change in accounting principle | (.01) | - | - | ||
| Net Income | $1.62 | $1.67 | $1.48 | ||
| Average Shares Outstanding | 16,819 | 16,382 | 16,084 | ||
The accompanying notes are an integral part of the above consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| (In thousands) | For the years ended December 31, | ||||
| Operating Activities | 2001 | 2000 | 1999 | ||
| Net income | $27,245 | $27,355 | $23,746 | ||
| Items not affecting cash: | |||||
| Depreciation and amortization | 35,659 | 35,081 | 35,154 | ||
| Deferred income taxes | 8,978 | (1,074) | (708) | ||
| Amortization of nuclear fuel | 1,649 | 2,194 | 2,638 | ||
| Amortization of investment tax credits | (849) | (727) | (739) | ||
| AFUDC - equity funds | (385) | (343) | (302) | ||
| Equity earnings in ATC | (3,345) | - | - | ||
| Cumulative effect of change in accounting principle, net of tax benefit of $78 | 117 | - | - | ||
| Other items | - | (825) | (1,430) | ||
| Dividend income from ATC | 1,630 | - | - | ||
| Changes in working capital items: | |||||
| Receivables, net | 13,100 | (10,248) | (1,101) | ||
| Inventories | (8,809) | (1,143) | (1,095) | ||
| Unbilled revenues | 11,414 | (14,733) | (54) | ||
| Prepayments | (1,813) | (895) | (262) | ||
| Accounts payable | (4,364) | 9,239 | 4,189 | ||
| Accrued taxes and interest | (2,602) | 2,051 | 378 | ||
| Other | (1,520) | 1,621 | (1,213) | ||
| Other noncurrent items, net | (1,421) | 221 | 1,142 | ||
| Cash Provided by Operating Activities | 74,684 | 47,774 | 60,343 | ||
| Investing Activities | |||||
| Additions to utility plant and nuclear fuel | (41,966) | (73,606) | (50,988) | ||
| AFUDC - borrowed funds | (217) | (176) | (155) | ||
| Increase in nuclear decommissioning fund | (8,931) | (11,059) | (10,692) | ||
| Capital distribution from ATC | 15,000 | - | - | ||
| Purchase of gas service territory | (3,800) | - | - | ||
| Sale of nuclear plant | 15,381 | - | - | ||
| Cash Used for Investing Activities | (24,533) | (84,841) | (61,835) | ||
| Financing Activities | |||||
| Issuance of common stock | 10,879 | 8,964 | 1,678 | ||
| Cash dividends on common stock | (22,341) | (21,588) | (21,038) | ||
| Maturity/redemption of long-term debt | (6,075) | (11,200) | (200) | ||
| Increase in long-term debt | - | 35,000 | - | ||
| Increase/(decrease) in short-term debt | (34,500) | 28,250 | 15,750 | ||
| Cash Provided by/(Used) for Financing Activities | (52,037) | 39,426 | (3,810) | ||
| Change in Cash and Cash Equivalents | (1,886) | 2,359 | (5,302) | ||
| Cash and cash equivalents at beginning of period | 4,307 | 1,948 | 7,250 | ||
| Cash and cash equivalents at end of period | $ 2,421 | $ 4,307 | $ 1,948 | ||
The accompanying notes are an integral part of the above consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
| (In thousands) | At December 31, | ||
| 2001 | 2000 | ||
| ASSETS | |||
| Utility Plant (at original cost, in service) | |||
| Electric | $506,810 | $622,209 | |
| Gas | 207,868 | 197,093 | |
| Gross Plant in Service | 714,678 | 819,302 | |
| Less accumulated provision for depreciation | (340,660) | (510,381) | |
| Net Plant in Service | 374,018 | 308,921 | |
| Construction work in progress | 25,376 | 22,863 | |
| Nuclear decommissioning fund | 1,855 | 102,891 | |
| Nuclear fuel, net | - | 6,979 | |
| Total Utility Plant | 401,249 | 441,654 | |
| Other Property and Investments | 3,610 | 3,988 | |
| Investment in ATC | 26,237 | - | |
| Total Other Property and Investments | 29,847 | 3,988 | |
| Current Assets | |||
| Cash and cash equivalents | 2,421 | 4,307 | |
| Accounts receivable, less reserves of $3,764 and $2,071, respectively | 25,061 | 38,161 | |
| Unbilled revenue | 16,486 | 27,900 | |
| Materials and supplies, at lower of average cost or market | 7,810 | 7,735 | |
| Fossil fuel, at lower of average cost or market | 4,266 | 3,872 | |
| Stored natural gas, at lower of average cost or market | 16,607 | 9,785 | |
| Prepaid taxes | 8,846 | 7,539 | |
| Other prepayments | 1,727 | 1,221 | |
| Total Current Assets | 83,224 | 100,520 | |
| Deferred Charges | 27,131 | 25,442 | |
| Total Assets | $541,451 | $571,604 | |
| CAPITALIZATION AND LIABILITIES | |||
| Capitalization (see statement) | $373,892 | $383,749 | |
| Current Liabilities | |||
| Long-term debt due within one year | 20,000 | 200 | |
| Short-term debt - commercial paper | 9,500 | 44,000 | |
| Accounts payable | 22,156 | 28,792 | |
| Accrued taxes | - | 2,550 | |
| Accrued interest | 3,110 | 3,162 | |
| Accrued payroll-related items | 5,186 | 4,968 | |
| Other | 1,827 | 3,565 | |
| Total Current Liabilities | 61,779 | 87,237 | |
| Other Credits | |||
| Deferred income taxes | 56,198 | 43,321 | |
| Investment tax credit - deferred | 5,927 | 8,472 | |
| Regulatory liability - SFAS No. 109 | 16,235 | 21,532 | |
| Other regulatory liabilities | 6,201 | 4,985 | |
| Other deferred liabilities | 21,219 | 22,308 | |
| Total Other Credits | 105,780 | 100,618 | |
| Commitments and Contingencies (see Footnote 8) | |||
| Total Capitalization and Liabilities | $541,451 | $571,604 | |
The accompanying notes are an integral part of the above consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(In thousands)
| At December 31, | |||
| 2001 | 2000 | ||
| Common Shareholders' Equity | |||
| Common stock - par value $1 per share: | |||
| Authorized 50,000,000 shares | |||
| Outstanding 17,071,554 and 16,618,729 shares, respectively | $ 17,072 | $ 16,619 | |
| Additional paid-in capital | 133,087 | 122,661 | |
| Retained earnings | 67,016 | 62,112 | |
| Accumulated other comprehensive loss | (883) | (1,080) | |
| Total Common Shareholders' Equity | 216,292 | 200,312 | |
| Redeemable Preferred Stock, cumulative, $25 par value, 1,175,000 authorized, but unissued | - | - | |
| First Mortgage Bonds | |||
| 6 1/2%, 2006 Series: | |||
| Pollution Control Revenue Bonds | - | 6,075 | |
| 8.50%, 2022 Series | 40,000 | 40,000 | |
| 6.75%, 2027A Series: | |||
| Industrial Development Revenue Bonds | 28,000 | 28,000 | |
| 6.70%, 2027B Series: | |||
| Industrial Development Revenue Bonds | 19,300 | 19,300 | |
| 7.70%, 2028 Series | 21,200 | 21,200 | |
| First Mortgage Bonds Outstanding | 108,500 | 114,575 | |
| Unamortized discount and premium on bonds, net | (900) | (938) | |
| Long-term debt sinking fund requirements | - | (200) | |
| Total First Mortgage Bonds | 107,600 | 113,437 | |
| Other Long-Term Debt | |||
| Variable rate, due 2002 | - | 20,000 | |
| 6.91%, due 2004 | 5,000 | 5,000 | |
| 7.49%, due 2007 | 15,000 | 15,000 | |
| 6.02%, due 2008 | 30,000 | 30,000 | |
| Total Long-Term Debt | 157,600 | 183,437 | |
| Total Capitalization | $373,892 | $383,749 | |
The accompanying notes are an integral part of the above consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMMON EQUITY AND COMPREHENSIVE INCOME
(In thousands, except per-share amounts)
|
|
Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive (Loss)/Income | Comprehensive Income | |||||||
| 1999 | |||||||||||
| Beginning balance - December 31, 1998 | 16,080 | $16,080 | $112,558 | $ 53,637 | |||||||
| Net income | 23,746 | $23,746 | |||||||||
| Other comprehensive income/(loss): | |||||||||||
| Minimum pension liability adjustment, net of $654 tax benefit | |
|
|
$(975) |
(975) |
||||||
| Total comprehensive income | $22,771 | ||||||||||
| Common stock dividends ($1.31 per share) | (21,038) | ||||||||||
| Common stock issued | 81 | 81 | 1,597 | ||||||||
| Ending balance - December 31, 1999 | 16,161 | $16,161 | $114,155 | $ 56,345 | $(975) | ||||||
| 2000 | |||||||||||
| Net income | $ 27,355 | $27,355 | |||||||||
| Other comprehensive income/(loss): | |||||||||||
| Minimum pension liability adjustment, net of $70 tax benefit | |
|
|
$ (105) |
(105) |
||||||
| Total comprehensive income | $27,250 | ||||||||||
| Common stock dividends ($1.32 per share) | (21,588) | ||||||||||
| Common stock issued | 458 | $ 458 | $ 8,506 | ||||||||
| Ending balance - December 31, 2000 | 16,619 | $16,619 | $122,661 | $ 62,112 | $(1,080) | ||||||
| 2001 | |||||||||||
| Net income | $ 27,245 | $27,245 | |||||||||
| Other comprehensive income/(loss): | |||||||||||
| Minimum pension liability adjustment, net of $132 tax provision | |
|
|
$197 |
197 |
||||||
| Total comprehensive income | $27,442 | ||||||||||
| Common stock dividends ($1.33 per share) | (22,341) | ||||||||||
| Common stock issued | 453 | $ 453 | $ 10,426 | ||||||||
| Ending balance - December 31, 2001 | 17,072 | $17,072 | $133,087 | $ 67,016 | $(883) | ||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000, and 1999
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
a. General
Madison Gas and Electric Company (MGE) is an investor-owned public utility headquartered in Madison, Wisconsin. MGE generates and distributes electricity to more than 128,000 customers in a 250-square-mile area of Dane County. MGE also transports and distributes natural gas to nearly 123,000 customers in 1,375 square miles of service territory in seven south-central Wisconsin counties.
The consolidated financial statements reflect the application of certain accounting policies described in this note. Certain 2000 balances have been reclassified to conform to the 2001 presentation. The financial statements include the accounts of MGE and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
In order to prepare consolidated financial statements in conformity with generally accepted accounting principles, management must make estimates and assumptions that affect reported amounts of assets and liabilities at the dates of the financial statements, reported amounts of revenues and expenses during the reported periods, and disclosure of contingencies. Actual results could differ from management's estimates.
Accounting policies for regulated operations are in accordance with those prescribed by the regulatory authorities having jurisdiction, principally the Public Service Commission of Wisconsin (PSCW), the Federal Energy Regulatory Commission (FERC), and the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935.
b. Revenues
Revenues from the sale of electricity and gas to customers are generally recorded when electricity/gas is delivered to those customers. The quantity of those sales is measured by customers' meters. Due to the large volume of those meters, it is impractical to read all of them at month end and, thus, those meters are read on a systematic basis throughout the month based on established meter-reading schedules. Consequently, at the end of any month, there exists a quantity of electricity and gas that has been delivered to customers but has not been captured by the meter readings. As a result, management must estimate revenue related to electricity and gas delivered to customers between their meter read date and the end of the period.
In order to estimate unbilled revenues as of the end of a particular period, MGE performs a series of calculations based upon actual and estimated numbers and assumptions. MGE begins by calculating the amount of electricity and gas available for sale within its system during that period based upon known inputs, i.e., electricity and gas purchases from third parties, gas from storage, and MGE-generated electricity. These amounts are then adjusted to deduct the amounts actually included within customers' bills for that period. In the case of electricity, the amount is further reduced by an estimate of the quantity of electricity lost in the process of transmitting and distributing it to customers. The resulting available-for-sale quantities are then allocated to various customer classes based upon historical utilization patterns for those customers, and MGE applies published tariffs to determine the associated revenues. Utilization patterns are based upon assumptions regarding weather, economic conditions, and consistency of use over the period in question and can be affected by variations in those items. The resulting estimate is then compared to other available statistics, including accounts receivable and billed sales for the particular period, in order to confirm its reasonableness. MGE believes that the ratio of unbilled-to-billed sales should typically fall in a 40% to 50% range. A ratio outside that range would indicate a need for further review and analysis.
During the third quarter of 2001, MGE made an adjustment to unbilled revenues that reduced revenues by approximately $4.5 million. The adjustment was prompted by a review of MGE's assumptions regarding electricity lost in the process of transmission and distribution, or line loss. Prior to the adjustment, MGE estimated line loss based upon a computer-modeled study performed in 1985 that had been reviewed for reasonableness and, as necessary, adjusted during subsequent periods. An analysis of various operating and financial statistics in the third quarter of 2001, including the unbilled-to-billed sales ratio, indicated that the estimate for unbilled revenues needed to be adjusted. MGE made an adjustment in order to bring the unbilled-to-billed ratio into alignment with the expected 40% to 50% range. MGE is in the process of reviewing its line loss experience and may further adjust its line loss estimate as a result of that review or any subsequent review determined by MGE to be necessary to achieve a normalized estimate of line loss. MGE also revised aspects of the calculation methodology and validation process as part of the adjustment. MGE does not expect any future revisions as a result of this analysis to be material.
Based on information available from its customer billing system, MGE has changed the method by which it incorporates unbilled consumption from prior periods into the calculation of amounts available for sale to customers during the current period. MGE revised the calculation to base the determination of unbilled quantities available for sale in the current month on the current month and the trailing two months as opposed to bringing forward the unbilled quantity from the prior months, which had the effect of cumulating any underestimated line loss amounts. The three months is based on an assumption, which MGE believes to be reasonable, that all electricity consumed by all classes of customers is billed within three months. MGE also determined that the ratio of unbilled-to-billed sales had a sufficient relationship to make that ratio, in addition to the ratio between unbilled sales and accounts receivable that was being used previously, a statistic for validating the results of its estimation methodology.
Gas revenues are subject to an adjustment clause related to periodic changes in the cost of gas. In November 1999, MGE started operating under a new gas cost incentive mechanism. Under this mechanism, if actual gas commodity costs are above or below a benchmark set by state regulators, MGE's gas sales service customers and shareholders share equally in the higher costs or savings up to $1.5 million. Any costs or savings that exceed $1.5 million will be passed on to the gas sales service customers.
c. Nuclear Fuel
The cost of nuclear fuel used for electric generation is amortized to fuel expense and recovered in rates based on the units of production method for generating electricity at the Kewaunee Nuclear Power Plant (Kewaunee).
These costs include a provision for estimated future disposal costs of spent nuclear fuel. MGE paid disposal fees to the US Department of Energy based on net nuclear generation. MGE has recovered through rates its known fuel disposal liability for past nuclear generation.
The 1992 National Energy Policy Act requires all utilities that have used federal enrichment facilities to pay a special assessment for decontaminating and decommissioning these facilities. This special assessment is based on past enrichment. MGE has accrued in other regulatory liabilities and deferred in deferred charges an estimated $1.4 million for its portion of the special assessment. MGE believes any additional costs will be recovered in future rates.
Effective September 23, 2001, MGE sold its 17.8% ownership interest in Kewaunee to Wisconsin Public Service Corp. (WPSC) (see Footnote 10).
d. 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. MGE presently capitalizes AFUDC at a rate of 10.58% on 50.0% of average construction work in progress. The AFUDC rate approximates MGE's cost of capital. The portion of the allowance that applies to borrowed funds is presented in the Consolidated Statements of Income as a reduction of interest expense, and 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.
MGE's accounting policy for planned major maintenance projects is to expense the costs for such projects in the periods for which they are incurred.
e. Depreciation
Provisions at composite straight-line depreciation rates, excluding decommissioning costs, approximate the following percentages for the cost of depreciable property:
| 2001 | 2000 | 1999 | |||
| Electric | 3.4% | 3.2% | 3.6% | ||
| Gas | 3.3% | 3.4% | 3.4% |
Depreciation rates are approved by the PSCW and are generally based on the estimated
economic lives of property.
Effective September 23, 2001, MGE transferred the assets of its external decommissioning trusts to external trusts of WPSC. This transfer was part of the Kewaunee sale agreement between WPSC and MGE (see Footnote 10). The agreement requires MGE to continue funding its external decommissioning trust through the end of 2002 at the PSCW authorized level, which is currently approximately $675,000 per month. These costs are currently recovered from customers in rates. At the beginning of 2003, the remaining assets of the MGE external trust will transfer to the external trust of WPSC. The trusts are shown on the balance sheet in the Utility Plant section.
As required by Statement of Financial Accounting Standard (SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity Securities," MGE's debt and equity security investments in the trusts are classified as available for sale. Gains and losses on the trusts were determined based on specific identification. Net unrealized holding gains on the trusts were recorded as part of accumulated provision for depreciation.
As of December 31, 2001, the decommissioning trust totaled $1.9 million, its pretax fair market value. Realized earnings on the trusts were $4.1 million, $3.5 million, and $3.1 million for the years ended December 31, 2001, 2000, and 1999, respectively. Unrealized earnings of the trusts totaled $0 million, $28.0 million, and $33.3 million at December 31, 2001, 2000, and 1999, respectively.
f. Regulatory Matters
Pursuant to SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation," MGE capitalizes (as deferred charges) incurred costs that are expected to be recovered in future electric and natural gas rates. MGE also records (as other credits) obligations to customers to refund previously collected revenue or to spend revenue collected from customers on future costs.
Electric industry restructuring could affect MGE's ability to continue establishing certain regulatory asset and liability amounts now allowed under SFAS No. 71. MGE is unable to predict whether any adjustments to regulatory assets and liabilities will occur in the future. However, the PSCW recognizes the need to allow recovery for commitments made under prior regulation.
MGE's regulatory and deferred assets and liabilities consisted of the following as of December 31:
| 2001 | 2000 | ||||||
| (In thousands) | Assets | Liabilities | Assets | Liabilities | |||
| Demand-side management | $ 1,955 | $ 653 | $ 3,910 | $ 1,345 | |||
| Decommissioning and decontamination | 1,356 | 1,356 | 1,584 | 1,584 | |||
| Environmental costs | 584 | - | 592 | - | |||
| Regulatory liability - SFAS No. 109 | - | 16,235 | - | 21,532 | |||
| Gas supply derivatives | 634 | - | - | - | |||
| Deferred charges related to ATC | 1,247 | - | 526 | - | |||
| Deferred charges related to interest - 2027A Series | 878 | - | 913 | - | |||
| Nitrogen oxide escrow | - | 1,608 | - | - | |||
| Other | 1,232 | 2,584 | 1,604 | 2,056 | |||
| Subtotal - regulatory assets/liabilities | 7,886 | 22,436 | 9,129 | 26,517 | |||
| Pension and deferred compensation assets/liabilities | 6,101 | 16,860 | 4,938 | 15,426 | |||
| Unamortized debt expense (a) | 4,684 | - | 5,038 | - | |||
| Customer advances for construction | - | 2,672 | - | 4,325 | |||
| Other deferred items | 8,460 | 1,687 | 6,337 | 2,557 | |||
| Subtotal - deferred assets/liabilities | 19,245 | 21,219 | 16,313 | 22,308 | |||
| Total | $27,131 | $43,655 | $25,442 | $48,825 | |||
| (a) Unamortized debt expense includes costs associated with the issuance of long-term debt. These costs are amortized over the respective lives of the associated debt instruments. MGE recovers these costs in rates as a cost of long-term debt. | |||||||
Demand-side management expenditures are for programs to promote energy efficiency. The demand-side management asset balance is for conservation expenditures that were previously capitalized. MGE recovers a carrying cost on this asset. MGE has not incurred any expenditures for capitalized conservation since 1997. The capitalized conservation balance at December 31, 1999, is currently being recovered in rates over a four-year amortization period, which ends December 2002.
The demand-side management liability balance is for MGE's conservation escrow expenditures. Costs for demand-side management programs are estimated in MGE's rates. To the extent the costs are over or under spent compared to the estimate included in rates, MGE will be required in its next rate case to seek recovery on any amounts overspent and return to ratepayers any amounts underspent.
Costs related to decommissioning and decontamination will be recovered in rates through September 2007 (see Footnote 1.c.)
Environmental costs MGE has received regulatory treatment on include clean up of two landfill sites and costs of certain nitrogen oxide (NOx) related expenditures. The regulators have allowed MGE to recover carrying costs associated with NOx expenditures and amortize the costs over varying time periods between four years for cleanup of sites and ten years for NOx related expenditures.
MGE has a limited number of physical and financial gas commodity contracts that are defined as derivatives under SFAS No. 133. The derivative amounts recorded as a result of these gas contracts is offset with a corresponding regulatory asset or liability because these transactions are part of the purchased gas adjustment (PGA) clause authorized by the PSCW and not subject to the gas cost incentive sharing mechanism. This regulatory asset will be fully recovered in the first quarter of 2002.
Deferred charges in connection with the start-up of the American Transmission Company (ATC) are being deferred under SFAS No. 71, as MGE believes it is probable that MGE will obtain recovery of these costs in future rates based on the PSCW's order in Docket O5-EI-121. MGE is earning a current return on the deferred charges related to this regulatory asset, which will be recovered over the next biennial rate case, which is 2003-2004.
Deferred charges on the interest expense of the 2027A Series relates to the incremental difference in the interest that MGE earned on its construction bond fund and the actual interest that MGE paid out. That incremental difference between interest earned and interest expensed is currently being amortized over the remaining life of the bonds (through 2027) as part of the rate recovery allowed by the PSCW.
The PSCW has authorized utilities to defer all project costs associated with the compliance of the federal US Environmental Protection Agency's (EPA) new requirements on NOx emissions. In MGE's last rate case, Docket 3270-UR-110, due to the uncertainty regarding the level and timing of NOx emissions remediation expenditures, the PSCW allowed MGE to establish an escrow mechanism for these costs. The annual recovery allowed in rates is $1.6 million, of which $0.7 million is recorded in depreciation expense and $0.9 million in operating expense. MGE earns a return on the unrecovered portion, which it will be amortizing over a ten-year period.
g. Statement of Cash Flows
MGE considers cash equivalents to be those investments that are highly liquid with original maturity dates of less than three months.
Supplementary noncash investing items and cash paid/(received) for interest and income taxes and other noncash investing items for the years ended December 31 were as follows:
| (In thousands) | 2001 | 2000 | 1999 | ||
| Interest paid, net of amount capitalized | $13,551 | $13,822 | $12,053 | ||
| Income taxes paid | $10,347 | $16,078 | $15,857 | ||
| Income taxes received | $ (570) | $ - | $ - | ||
| Noncash investing items | $ - | $ - | $ 5,301 |
In December 1999, MGE recorded $5.3 million in capital expenditures as
construction work in process for capital equipment that was received in 1999,
with a corresponding increase in accounts payable. These amounts were excluded
from the Consolidated Statements of Cash Flows and separately disclosed as noncash
investing activities and reflected in the Consolidated Statements of Cash Flows
in subsequent periods once paid.
The amortization of debt issuance costs for the year ended 2001 is included in the line item "Other noncurrent items, net" in the cash flow statement from operating activities and is not separated in a separate line as it is immaterial.
h. Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Comprehensive income is reflected in the Consolidated Statements of Common Equity and Comprehensive Income.
i. Hedge Accounting
Hedge accounting is applied only if the derivative reduces the risk of the underlying hedged item and is designated at inception as a hedge, with respect to the hedged item. If a derivative instrument ceased to meet the criteria for deferral, any gains or losses were recognized in income.
j. Accounting for Financial Derivatives
MGE manages its risk exposure related to interest rates, commodity prices, and gas margin through its risk management policies and the use of various derivative instruments. MGE manages its interest rate risk by limiting its variable rate exposure through interest rate swap agreements. MGE uses various derivative contracts to manage the cost of gas for its "Winter Set-Price Firm Gas Sales Service" pilot program. MGE will use weather derivatives to reduce the impact of weather volatility on its gas margins.
MGE has a swap agreement with a commercial bank for a notional amount of $5.0 million, backed by MGE's commercial paper. MGE pays a fixed rate of 6.91% on the swap, which was used to replace a portion of MGE's 7.70%, 2028 Series, First Mortgage Bonds. This swap agreement did not meet the criteria for hedge accounting due to the term of the swap being four years while the item being hedged has a 30-day maturity. Therefore, MGE's commercial paper swap agreement has been classified as a derivative and the changes in fair market value are recorded each quarter in the income statement. The cumulative effect of the change in accounting principle for the adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," led to a one-time charge of $0.1 million (after tax), which was recorded in the first quarter.
MGE has a 22.0% ownership interest in the coal-fired Columbia Energy Center (Columbia), which is operated by Alliant Energy, Corp. (Alliant). Alliant has entered into a long-term coal supply agreement with Dynegy Marketing and Trade. The contract contains certain put options and consequently, in accordance with the terms of SFAS No. 133, the contract is recorded at fair value on the balance sheet. Gains and losses are recorded in other income. The fair value adjustments of the two derivatives (swap agreement and Dynegy contract) were $0.1 million (after tax) for the year ended December 31, 2001.
MGE has a limited number of physical and financial gas commodity contracts that are defined as derivatives under SFAS No. 133. These gas instruments are primarily comprised of exchange-traded option contracts to manage the cost of gas and over-the-counter financial floating-to-fixed price swaps and calls for the Winter Set-Price Firm Gas Sales Service pilot program. The derivative amounts recorded as a result of these gas contracts is offset with a corresponding regulatory asset or liability because these transactions are part of the PGA clause and not subject to the gas cost incentive sharing mechanism. As of December 31, 2001, MGE has recorded a liability from gas supply derivatives and a corresponding regulatory asset of $0.6 million related to these contracts.
k. New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," that supersede Accounting Principles Board (APB) Opinion No. 16, "Business Combinations," and APB Opinion No. 17, "Intangible Assets." The two statements modify the method of accounting for business combinations and address the accounting and reporting for goodwill and intangible assets. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001 and, with acquisitions completed after June 30, 2001, for all business combinations accounted for by the purchase method for which the date of acquisition is completed after June 30, 2001. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. MGE does not believe this statement will have a material impact on its financial statements.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," and is effective for all companies. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible, long-lived assets. MGE expects to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. MGE is currently reviewing this statement to determine its effect on its financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets," which supersedes SFAS No. 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to be Disposed of," and the accounting and reporting provisions of APB No. 30, "Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets and is effective for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. MGE does not believe this statement will have a material impact on its financial statements.
l. Impairment of Long-lived Assets
MGE continually reviews plant and equipment, other intangible assets and property, and goodwill, if any, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. MGE's policy for determining when long-lived assets are impaired is to recognize an impairment loss if the sum of the expected future cash flows (undiscounted and without interest charges) from an asset is less than the carrying amount of that asset. If an impairment loss is recognized, the amount that will be recorded will be measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. MGE believes there is no impairment of long-lived assets in accordance to SFAS No. 121 at December 31, 2001.
m. Income and Excise Taxes
Under the liability method used by MGE, income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax basis of assets and liabilities, using the tax rates scheduled by law to be in effect when the temporary differences reverse. Regulation has created a SFAS No. 109 regulatory liability related to income taxes (see Footnote 3).
Investment tax credits from regulated operations are amortized over related property service lives.
MGE pays a license fee tax to the State of Wisconsin in lieu of property taxes on property used in utility operations. License fee tax is calculated as a percent of operating revenues of the prior year. The electric tax rate is 3.19% and the gas tax rate is 0.97%. Estimated tax is prepaid (prepaid taxes) one year in advance of expense recognition. License fee tax expense included in other general taxes was $7.7 million, $6.9 million, and $6.2 million for the years ended December 31, 2001, 2000, and 1999, respectively.
Operating income taxes, including tax credits, and license fee tax are included in rates.
2. JOINT PLANT OWNERSHIP
MGE and two other utilities jointly own Columbia, a coal-fired generating facility, which accounts for 35.7% (232 megawatts) of MGE's net generating capability. Power from this facility is shared in proportion to each company's ownership interest. MGE has a 22.0% ownership interest in Columbia. The other owners are Alliant, which operates Columbia, and WPSC.
Information regarding MGE's sale in 2001 of its 17.8% ownership interest in Kewaunee to WPSC, MGE's obligations relative to Kewaunee continuing beyond the closing date, and MGE's exercise in 2001 of an option to buy electric capacity and energy for a two-year period from WPSC is included in Footnote 10.
Each owner provides its own financing and reflects its respective portion of facilities and operating costs in its financial statements. MGE's interest in this facility, included in its gross utility plant in service, and the related accumulated depreciation reserves at December 31 were as follows:
| Columbia | Kewaunee | ||||
| (In thousands) | 2001 | 2000 | 2000 | ||
| Utility plant | $ 88,148 | $ 91,993 | $ 59,484 | ||
| Accumulated depreciation | (55,016) | (55,877) | (50,621) | ||
| Net plant | $ 33,132 | $ 36,116 | $ 8,863 | ||
3. INCOME TAXES
Income tax provision before cumulative effect of a change in accounting principle consists of the following provision (benefit) components for the years ended December 31:
| (In thousands) | 2001 | 2000 | 1999 | ||
| Currently payable: | |||||
| Federal | $ 6,634 | $14,280 | $11,772 | ||
| State | 1,100 | 3,273 | 3,551 | ||
| Net-deferred: | |||||
| Federal | 6,487 | (878) | (476) | ||
| State | 2,569 | (196) | (232) | ||
| Amortized investment tax credits | (849) | (727) | (739) | ||
| Total income taxes | $15,941 | $15,752 | $13,876 |
The sale of Kewaunee, described in Footnote 10, resulted in the reversal
of temporary differences for the plant and certain associated nuclear decommissioning
liabilities and funds held in trust. Deferred tax expense recorded for the sale
transaction was $11.7 million.
Amortized investment tax credits above include $0.3 million from the realization of investment tax credit-deferred relating to Kewaunee at the time of its sale (see Footnote 10). The tax benefit of realizing this investment tax credit was recorded in income tax provision in Other Income and Deductions.
MGE's provision for income taxes differed from the amount computed by applying the statutory federal income tax rate to income before tax provision and cumulative effect of a change in accounting principle is as follows:
| 2001 | 2000 | 1999 | |||
| Statutory federal income tax rate | 35.0% | 35.0% | 35.0% | ||
| Amortized investment tax credits | (2.0)% | (1.7)% | (2.0)% | ||
| State income taxes, net of federal benefit | 5.0% | 5.0% | 5.7% | ||
| Valuation allowance | - | (1.1)% | (0.3)% | ||
| Renewable electricity production credit | (0.9)% | (0.9)% | (0.5)% | ||
| Other, individually insignificant | (0.3)% | 0.2% | (1.0)% | ||
| Effective income tax rate | 36.8% | 36.5% | 36.9% |
The significant components of deferred tax liabilities (assets) that appear
on the Consolidated Balance Sheets as of December 31 are as follows:
| (In thousands) | 2001 | 2000 | |
| Property-related | $55,418 | $65,071 | |
| Investment in ATC | 10,134 | - | |
| Nuclear plant decommissioning liability | 3,598 | - | |
| Bond transactions | 1,651 | 1,720 | |
| Energy conservation | 523 | 1,030 | |
| Pension expense | 2,703 | 2,282 | |
| Other | 1,298 | 1,002 | |
| Gross deferred income tax liabilities | 75,325 | 71,105 | |
| Accrued expenses | (6,478) | (4,513) | |
| Retirement benefits, other than pension | (2,429) | (2,107) | |
| Nuclear plant decommissioning | - | (7,507) | |
| Other | (1,696) | (1,986) | |
| Deferred tax regulatory account | (8,895) | (12,042) | |
| Gross deferred income tax assets | (19,498) | (28,155) | |
| Less valuation allowance | 371 | 371 | |
| Net deferred income tax assets | (19,127) | (27,784) | |
| Deferred income taxes | $56,198 | $43,321 |
The valuation allowance reduces MGE's deferred tax assets for state carryforward
losses to estimated realizable value due to the uncertainty of future income
estimates in various state tax jurisdictions.
For tax purposes, as of December 31, 2001, MGE had approximately $7.6 million of state tax net operating loss deductions that expire in 2013, if unused.
Excess deferred income taxes result from past taxes provided at rates higher than current rates. The SFAS No. 109 regulatory liability and the deferred investment tax credit reflect the revenue requirement associated with the return of these tax benefits to customers.
As discussed in Footnote 9, the MGE invested its transmission assets in ATC on January 1, 2001. The carrying value of MGE's investment in ATC was reduced by the SFAS No. 109 regulatory liability and the deferred investment tax credit related to the contributed transmission property. The amount of the reduction to SFAS No. 109 regulatory liability and to deferred investment tax credit was $2.4 million and $1.7 million, respectively. The reduction to the investment carrying value for the transmission component of the SFAS No. 109 regulatory liability and the deferred investment tax credit reflects the transfer of excess deferred taxes and deferred investment tax credit to ATC for regulatory purposes.
MGE is accreting its investment in ATC by amortizing the total adjustment of $4.1 million into income over the related regulatory life of the excess deferred taxes and deferred investment tax credit to coincide with the impact to ATC's regulated revenues. The amortization period runs through 2024 with progressively lower amounts each year. The amount of amortized income for 2001, included in equity in earnings of ATC, was $0.3 million.
Remaining excess deferred income tax ($0.1 million) associated with the Kewaunee plant at the time of sale were taken in income in income tax provision in Other Income and Deductions.
4. PENSION PLANS
MGE maintains qualified and nonqualified pension plans. MGE also provides health care and life insurance benefits for its retired employees. The benefits table below provides a reconciliation of benefit obligations, plan assets, and funded status of the plans.
The funded status information reported in the benefits table includes a nonqualified pension plan and a postretirement benefit plan with accumulated benefit obligations in excess of the fair value of assets. The projected benefit obligation, accumulated benefit obligation, and fair value of assets for a nonqualified pension plan were $7.8 million, $7.2 million, and $0, respectively, at the end of December 31, 2001, and $7.6 million, $7.2 million, and $0, respectively, at December 31, 2000. Similarly, the accumulated benefit obligation and fair value of assets for the postretirement benefit plan were $27.5 million and $7.4 million at December 31, 2001, and $18.3 million and $7.0 million at December 31, 2000.
MGE 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.
MGE maintains two defined contribution 401(k) benefit plans for its employees. MGE's costs of the 401(k) plans were $0.6 million in 2001, $0.6 million in 2000 and $0.5 million in 1999.
Sensitivity of retiree welfare results. The assumed health care cost percentage was 7.0% as of December 31, 2001. Assumed health care trend rates have a significant effect on the amounts reported for health care plans. The following table shows how an assumed 1% increase or 1% decrease in health care cost trends could impact postretirement benefits in 2001 dollars.
| (In thousands) | 1% Increase | 1% Decrease | |
| Effect on total service and interest cost components | $ 438 | $ (352) | |
| Effect on postretirement benefit obligation | $4,630 | $(3,759) |
MGE reports comprehensive income in accordance with SFAS No. 130, "Reporting
Comprehensive Income." Comprehensive income includes the minimum pension liability
adjustment, net of tax, for a nonqualified pension plan and is reflected in
the Consolidated Statements of Common Equity and Comprehensive Income.
| (In thousands) | Pension Benefits | Postretirement Benefits | |||||
| 2001 | 2000 | 2001 | 2000 | ||||
| Change in Benefit Obligation | |||||||
| Net benefit obligation at beginning of year | $ 91,685 | $81,675 | $18,951 | $16,244 | |||
| Service cost | 2,502 | 2,350 | 750 | 612 | |||
| Interest cost | 7,073 | 6,424 | 1,569 | 1,317 | |||
| Plan participants' contributions | - | - | 193 | 157 | |||
| Plan amendments | (125) | 1,696 | - | - | |||
| Actuarial loss | 3,896 | 2,432 | 7,141 | 1,430 | |||
| Gross benefits paid | (3,438) | (2,892) | (1,100) | (809) | |||
| Net benefit obligation at end of year | $101,593 | $91,685 | $27,504 | $18,951 | |||
| Change in Plan Assets | |||||||
| Fair value of plan assets at beginning of year | $98,506 | $99,767 | $7,599 | $7,023 | |||
| Actual return on plan assets | (4,712) | 1,263 | 147 | 227 | |||
| Employer contributions | 1,383 | 368 | 548 | 1,002 | |||
| Plan participants' contributions | - | - | 193 | 156 | |||
| Gross benefits paid | (3,438) | (2,892) | (1,100) | (809) | |||
| Fair value of plan assets at end of year | $91,739 | $98,506 | $7,387 | $7,599 | |||
| Funded status at end of year | $ (9,854) | $ 6,821 | $(20,117) | $(11,352) | |||
| Unrecognized net actuarial (gain)/loss | 5,014 | (12,976) | 5,459 | (2,493) | |||
| Unrecognized prior service cost | 4,551 | 5,142 | 1,351 | 1,541 | |||
| Unrecognized net transition obligation | 1,375 | 1,479 | 4,776 | 5,210 | |||
| Net amount recognized at end of year | $ 1,086 | $ 466 | $ (8,531) | $ (7,094) | |||
| Amounts recognized in the balance sheet consist of: | |||||||
| Prepaid benefit cost | $ 6,100 | $ 4,938 | $ 81 | $ 80 | |||
| Accrued benefit liability | (5,014) | (4,472) | (8,612) | (7,174) | |||
| Additional minimum liability | (2,184) | (2,756) | - | - | |||
| Intangible asset | 708 | 951 | - | - | |||
| Accumulated other comprehensive income | 1,476 | 1,805 | - | - | |||
| Net amount recognized at end of year | $ 1,086 | $ 466 | $(8,531) | $(7,094) | |||
| (In thousands) | Pension Benefits | Postretirement Benefits | |||||||||
| 2001 | 2000 | 1999 | 2001 | 2000 | 1999 | ||||||
| Components of Net Periodic Benefit Cost | |||||||||||
| Service cost | $2,502 | $2,350 | $2,020 | $ 750 | $ 612 | $ 648 | |||||
| Interest cost | 7,073 | 6,424 | 5,868 | 1,569 | 1,317 | 1,177 | |||||
| Expected return on assets | (9,217) | (9,355) | (7,597) | (691) | (655) | (513) | |||||
| Amortization of: | |||||||||||
| Transition obligation | 104 | 104 | 104 | 434 | 434 | 434 | |||||
| Prior service cost | 466 | 442 | 352 | 190 | 190 | 190 | |||||
| Actuarial gain/(loss) | (166) | (883) | 89 | 4 | (114) | (19) | |||||
| Regulatory effect based on phase-in | - | 112 | 113 | - | - | - | |||||
| Net periodic benefit cost | $ 762 | $ (806) | $ 949 | $2,256 | $1,784 | $1,917 | |||||
| Weighted-average Assumptions as of December 31 | |||||||||||
| Discount rate | 7.25% | 7.50% | 7.50% | 7.25% | 7.50% | 7.50% | |||||
| Expected return on plan assets | 9.50% | 9.50% | 9.50% | 9.50% | 9.50% | 9.50% | |||||
| Rate of compensation increase | 4.50% | 5.00% | 5.00% | NA | NA | NA | |||||
The health care cost trend was reset to 10% for 2002. The rate is assumed to decrease to 5% for 2007 and remain at that level thereafter.
5. FAIR VALUE OF FINANCIAL INSTRUMENTS
At December 31, 2001 and 2000, the carrying amount of cash, cash equivalents, and outstanding commercial paper approximates fair market value due to the short maturity of those investments and obligations. MGE's nuclear decommissioning trust is recorded at fair market value. The estimated fair market value of MGE's long-term debt and interest rate swap agreements are based on quoted market prices at December 31. The estimated fair market value of MGE's financial instruments are as follows:
| 2001 | 2000 | ||||||
| (In thousands) | Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
|||
| Assets: | |||||||
| Cash and cash equivalents | $ 2,421 | $ 2,421 | $ 4,307 | $ 4,307 | |||
| Decommissioning fund | $ 1,850 | $ 1,855 | $102,891 | $102,891 | |||
| Liabilities: | |||||||
| Short-term debt | $ 9,500 | $ 9,500 | $ 44,000 | $ 44,000 | |||
| Long-term debt | $173,500 | $179,377 | $184,575 | $187,527 | |||
| Other long-term debt swap agreements | $ - | $ (404) | $ - | $ (194) | |||
Cash, cash equivalents, and customer accounts receivable are the financial instruments that potentially subject MGE to concentrations of credit risk. MGE places its cash and cash equivalents with high credit-quality financial institutions. MGE has limited concentrations of credit risk from customer accounts receivable because of the large number of customers and strong economy in its service territory.
MGE has an interest rate swap agreement with a commercial bank totaling $5.0 million for 2001 and 2000, with effective interest rates of 4.0% and 6.3%, respectively. These agreements have a fixed rate and are backed by MGE's commercial paper. MGE believes the counterparties to the agreements will meet their obligations based on their high credit ratings. This swap agreement does not meet the criteria for hedge accounting due to the term of the swap being four years while the item being hedged has a 30-day maturity. Therefore, MGE records the changes in the fair market value currently in the income statement as required by SFAS No. 133 each quarter.
In October 2001, MGE entered into a nonexchange-traded heating degree day (HDD) collar contract covering the period November 1, 2001, through March 31, 2002. A HDD is the number of degrees that the mean daily temperature is below 65 degrees Fahrenheit. MGE uses weather derivatives to reduce the impact of weather volatility on its gas margin. MGE does not use weather derivatives for trading or speculative purposes. MGE accounts for this weather derivative in accordance with Emerging Issues Task Force (EITF) 99-2, "Accounting for Weather Derivatives," which uses the intrinsic value method. Through December 31, 2001, MGE has recognized a gain of $1.0 million on the contract.
MGE purchased and sold exchange-traded option contracts to manage the cost of gas and purchased over-the-counter financial floating-to-fixed price swaps and calls to fix the price of gas for the Winter Set-Price Firm Gas Sales Service pilot program. These contracts have terms of January, February, and March 2002. Under MGE's natural gas risk management program, approved by the PSCW, the cost of the financial option and swap contracts (as well as the gains or losses realized) will be recovered under the PGA and will not affect net income. The fair value of these financial contracts was a liability of $0.5 million on the balance sheet at December 31, 2001.
Nonperformance of counterparties to the nonexchange-traded derivatives could expose MGE to credit loss. However, MGE enters into transactions only with companies that meet or exceed strict credit guidelines. MGE considers it has minimal risk for counter-party default.
6. CAPITALIZATION MATTERS
a. Common Stock
MGE issues new shares for its Dividend Reinvestment and Direct Stock Purchase Plan (the Plan). Issuing new shares, rather than buying shares on the open market, helps improve cash flow and strengthens MGE's capital structure.
In 2001, a total of 453,000 new shares of common stock were issued under the Plan. The $10.9 million proceeds were allocated to common stock and amounts received in excess of par value (see Consolidated Statements of Common Equity and Comprehensive Income).
In 2000, a total of 458,000 new shares of common stock were issued under the Plan. The $9.0 million proceeds were allocated to common stock and amounts received in excess of par value.
b. Preferred Stock
MGE has 1,175,000 shares of $25 par value redeemable preferred stock, cumulative, that is authorized but unissued at December 31, 2001.
c. First Mortgage Bonds and Other Long-Term Debt
MGE's utility plant is subject to the lien of its First Mortgage Bonds.
MGE has the following call provisions for the First Mortgage Bonds:
| Bond Series | First Call Date | Call Price |
| 8.50%, 2022 Series | April 15, 2002 | 104.25% |
| 6.75%, 2027A Series | April 1, 2002 | 102% |
| 6.70%, 2027B Series | April 1, 2002 | 102% |
| 7.70%, 2028 Series | February 15, 2003 | 104.26% |
MGE's outstanding First Mortgage Bonds contain certain debt covenant restrictions
with respect to dividends. The covenant restricts the payment of dividends or
any other distribution or purchase of shares to the existing earned surplus
(retained earnings) on MGE common stock. As of December 31, 2001, MGE's
earned surplus exceeded all such payments for all years covered under this report.
On November 1, 2001, MGE redeemed $6.1 million of its 6 1/2%, 2006 Series. There was no call premium associated with these bonds. MGE used proceeds from the sale of Kewaunee to retire this debt issue. There is no more sinking fund associated with this debt issue.
MGE's $20 million of unsecured, variable-rate Medium Term Notes mature on May 3, 2002, and is classified under current liabilities. The variable rate, based on the three-month London Interbank Offering Rate (LIBOR) plus 13 basis points, was 2.03% as of December 31, 2001.
Below is MGE's aggregate maturities for all long-term debt for years following the December 31, 2001, balance sheet.
| In thousands | ||
|
Year
|
Amount | |
|
2002
|
$ 20,000 | |
|
2003
|
- | |
|
2004
|
5,000 | |
|
2005
|
- | |
|
2006
|
- | |
|
Future years
|
153,500 | |
|
Total
|
$178,500 | |
d. Notes Payable to Banks, Commercial Paper and Lines of Credit
For short-term borrowings, MGE 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, MGE has $40 million in bank lines of credit
Information concerning short-term borrowings for the past three years is shown below:
| (In thousands) | 2001 | 2000 | 1999 | ||
| As of December 31: | |||||
| Available lines of credit | $40,000 | $55,000 | $40,000 | ||
| Commercial paper outstanding | $9,500 | $44,000 | $15,750 | ||
| Weighted-average interest rate | 2.11% | 6.73% | 6.44% | ||
| During the year: | |||||
| Maximum short-term borrowings | $44,000 | $44,000 | $15,750 | ||
| Average short-term borrowings | $12,803 | $17,117 | $1,899 | ||
| Weighted-average interest rate | 5.27% | 6.58% | 5.78% |
7. RATE MATTERS
Effective January 1, 2002, the PSCW authorized MGE to increase revenue by $12 million (a 5.7% increase in electric rates and a 0.7% increase in gas rates). The increase was associated with a limited reopener of MGE's current rate case to address limited specific issues affecting 2002. MGE's reopener reflected the full-year impact of the disposition of Kewaunee, rising fuel costs, and also addressed implementing an automated meter reading system. MGE's next rate case period is expected to begin January 1, 2003.
The PSCW approved MGE's request for a temporary electric fuel surcharge of 2.7% effective May 9 through September 2, 2001. The temporary rate increase covered the higher cost of natural gas used to generate electricity. Revenues collected from this surcharge were subject to refund, pending the PSCW's review of any excess revenues collected by MGE while the surcharge was in effect. The increase to revenue as a result of the surcharge, net of refunds to customers, was $1.0 million.
In January 2001, the PSCW authorized an electric rate increase of $7.5 million, or 3.9%, to cover rising fuel costs and increased system demands and a natural gas rate increase of $3.4 million, or 2.7%, for improving the gas delivery system and a return on common stock equity of 12.9%.
MGE contracted with WPSC to build and operate an 83-MW natural gas-fired combustion turbine near Marinette, Wisconsin. MGE received rate recovery for this asset and related operating and maintenance expenses. Associated revenues collected in 1999 ($1.7 million) and the first five months of 2000 ($0.8 million) were deferred until the unit went on-line in June 2000. MGE recognized the collection of these deferred revenues ($2.5 million) starting in June 2000.
In January 2000, the PSCW approved an electric rate increase of $9.7 million, or 5.5%, to cover rising fuel costs, repair costs at Kewaunee and additional backup generator costs. These rates were in effect through 2000. In MGE's previous rate case, it was assumed that Kewaunee ownership and related costs would have transferred to WPSC in spring 2000 (when steam generators were scheduled to be replaced). Delays in manufacturing the steam generators postponed this work until fall 2001.
8. COMMITMENTS
Coal Contracts. MGE has no coal contracts that contain demand obligations for its Blount Generating Station (Blount). Fuel procurement for MGE's jointly owned Columbia plant is handled by Alliant, the operating company. If any demand obligations must be paid under these contracts, management believes these would be considered costs of service and recoverable in rates.
Purchased Power Contracts. MGE has several purchased power contracts to help meet future electric supply requirements. As of December 31, 2001, MGE's total commitments for energy and purchased power contracts for capacity are estimated to be $17.2 million in 2002, $18.5 million in 2003, $11.8 million in 2004, $13.4 million in 2005, and $13.5 million in 2006. Management expects to recover these costs in future customer rates.
Purchased Gas Contracts. MGE has natural gas transportation and storage contracts that provide for the availability of firm pipeline transportation and storage capacity under which it must make fixed monthly payments. The pricing component of the fixed monthly payment for these contracts is established but may be subject to change by the FERC. These payments are estimated to be $14.5 million in 2002, $13.2 million in 2003, $12.3 million in 2004, $9.8 million in 2005, and $9.5 million in 2006. Management expects to recover these costs in future customer rates.
Environmental. On January 1, 2000, Phase II of the 1990 Federal Clean Air Act amendments took effect, setting new emission limits for sulfur dioxide (SO2) and NOx. MGE's generating units meet those limits. The units were modified well in advance to meet year 2000 NOx requirements. Early modifications at Blount allow MGE to postpone meeting more stringent NOx requirements at this plant until 2007.
On October 27, 1998, the EPA issued final rules requiring more NOx emission reductions from sources in 22 states, including Wisconsin, to reduce the transport of ozone across state boundaries. However, a successful legal challenge resulted in excluding Wisconsin from this rule. After further modeling and research, the EPA is expected to revise or amend these rules to control NOx emissions in Wisconsin in order to help other states meet the one- and eight-hour ozone standards.
MGE is evaluating NOx compliance strategies, including fuel switching, emissions trading, purchased power agreements, new emission control devices, or installation of new fuel-burning and clean-coal technologies. Implementing any of these new measures would likely increase capital and operating and maintenance expenditures.
Wisconsin's acid rain law imposes limitations on SO2 emissions. Blount and MGE's share of Columbia are required to meet a combined SO2 emission rate of 1.20 pounds of SO2 per million Btu. MGE does not anticipate any capital expenditure in order to comply with this standard.
In December 2000, the EPA announced it would create rules to limit the amount of mercury emitted by coal- and oil-fired electric-steam generating facilities. EPA plans to have the proposed rules published no later than December 15, 2003, and final regulations published no later than December 15, 2004. The DNR is also developing rules to limit mercury emissions from coal-fired boilers. The proposed rules require sources emitting more than 10 pounds of mercury per year to reduce emissions in phases of 30%, 50%, and 90% over 15 years. It also sets a ceiling of 10 pounds of mercury per year for smaller sources. If either of these regulations is issued, they may require MGE to evaluate emission control options for its Blount and Columbia facilities in order to comply. These controls would likely increase capital expenditures and operating and maintenance expenses.
In December 2000 and February 2001, Columbia received Requests for Information from the EPA to evaluate compliance with the Clean Air Act. Alliant Energy Corp. (Alliant), the plant operator, has responded to both of the requests and has not yet received a response from the EPA. On a broader basis, the EPA is assessing the impact of investments in utility generation capacity, energy efficiency, and environmental protection as well as assessing proposed multi-pollutant legislation. Results of this review are expected in mid-2002.
MGE believes all of its plants to be in full compliance with all material aspects of present air-pollution control regulations.
MGE is listed as a potentially responsible party for a site the EPA has placed on the national priorities Superfund list. The Lenz Oil site in Lemont, Illinois, was used for storing and processing waste oil for several years. This site requires clean up under the Comprehensive Environmental Response, Compensation and Liability Act. A group of companies, including MGE, is currently working on cleaning up the site.
MGE, a potentially responsible party, is also negotiating with the City of Madison for cleanup costs at the Demetral Landfill. MGE used this site for coal ash disposal from 1954 to 1959.
Management believes that its share of the final cleanup costs for all sites will not result in any materially adverse effects on MGE's operations, cash flows, or financial position. Insurance may cover a portion of the cleanup costs. Management believes that the cleanup costs not covered by insurance will be recovered in current and future rates. MGE estimates its future expense to clean up these sites could range from $250,000 to $550,000. At December 31, 2001, MGE accrued a $250,000 liability for these matters.
Chattel Paper Agreement. MGE makes available to qualifying customers a financing program for the purchase and installation of energy-related equipment that will provide more efficient use of utility service at the customer's property. MGE is party to a chattel paper purchase agreement with a financial institution under which it can sell or finance an undivided interest, in up to $7.5 million of the financing program receivables until February 28, 2004. At December 31, 2001 and 2000, respectively, MGE had sold a $5.6 million and $5.1 million interest in these receivables, which MGE accounted for as a sale under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - a Replacement of FASB Statement No. 125." MGE retains the servicing responsibility for these receivables.
New Generation. On February 23, 2001, MGE announced that it had secured an option agreement to own a portion of the advanced technology, coal-fired base-load generation included in Wisconsin Energy Corp.'s (WEC) "Power the Future" proposal. The proposal includes three, 600-MW coal-fired units of new generation. MGE's option rights provide for up to 1/12th ownership allotment (approximately 50 MWs) in each unit for an estimated investment over a ten-year period of $150 million to $175 million. WEC filed its construction proposal (CPCN) with the PSCW in early 2002. A decision from the PSCW is expected in 2002.
In February 2002, MGE exercised its option for the first proposed coal unit to obtain the maximum equity interest available under the agreement but not less than 50 MW. MGE's option rights may be terminated if necessary regulatory approvals are not received or WEC discontinues the project. Furthermore, MGE retains the right under the agreement with WEC to revoke the option exercise at certain points in the process including, but not limited to, any time up to 60 days prior to commencement of construction of the coal unit.
Leases. Future minimum rental payments at December 31, 2001, under agreements classified as operating leases with noncancellable terms in excess of one year are as follows:
| In thousands | |
| 2002 | $1,010 |
| 2003 | 940 |
| 2004 | 660 |
| 2005 | 525 |
| 2006 | 525 |
| Thereafter | 5,900 |
| Total minimum future lease payments | $9,560 |
Rental expense under operating leases totaled $1.0 million for each of
the years 2001, 2000, and 1999.
9. AMERICAN TRANSMISSION COMPANY LLC
On January 1, 2001, MGE transferred substantially all of its electric transmission facilities to ATC in exchange for approximately a 6% interest in this joint venture. ATC is comprised of Wisconsin investor-owned utilities and some Wisconsin municipal utilities, cooperatives, and power supply agencies.
MGE accounts for this investment on the equity method of accounting. MGE's records as equity in earnings of the investee its share of ATC's earnings, amortization of the Statement of Financial Accounting Standards (SFAS) No. 109 regulatory liability, and deferred investment tax credits related to the transmission assets transferred to ATC. MGE recorded $3.3 million (pretax) of equity earnings from its investment in ATC.
In the second quarter of 2001, MGE received $15.0 million in a cash distribution as a result of ATC's issuance of debt. Also during 2001, MGE received a total of $1.6 million in dividends from ATC. The dividend is a return of capital that reduces our investment in ATC.
MGE contracts with ATC for transmission services. MGE's 2001 cost of $8.1 million is included in operating expenses. Under a three-year contract beginning January 1, 2001, MGE provides various services to ATC, including fixed capital construction, operations and maintenance, and transitional services. MGE bills for these services based on its actual costs for labor, materials, and overhead. MGE billed ATC $3.7 million for these services in 2001.
MGE tracks the difference between the revenue requirement for transmission services included in its current rate tariffs and the network transmission service fee paid to ATC. The difference is deferred and subject to adjustment in MGE's next rate case. In 2001, MGE recorded a deferred asset of $0.5 million for this difference.
10. KEWAUNEE NUCLEAR POWER PLANT
Effective September 23, 2001, MGE sold to WPSC its 17.8% ownership interest in Kewaunee. In exchange for a cash payment of $15.4 million, MGE transferred its net book value of utility plant ($8.2 million), net nuclear fuel ($7.9 million), inventories ($1.5 million), and other assets ($0.1 million). These assets were offset by $2.3 million owed to WPSC. On the closing date, MGE also transferred its Qualified Decommissioning Fund ($65.0 million fair market value) and Nonqualified Decommissioning Fund ($28.1 million fair market value), which resulted in a decrease of accumulated depreciation by an equal amount. This transaction occurred in accordance with an agreement between MGE and WPSC dated September 29, 1998. That agreement requires certain continuing obligations of MGE and WPSC after the closing date, as described below.
MGE will make monthly contributions to the MGE Nonqualified Decommissioning Fund from September 23, 2001, through December 31, 2002. MGE will make monthly contributions in the amount of approximately $675,000, the level currently authorized by the PSCW. These costs are currently recovered from customers in rates. MGE's decommissioning liability is limited to the fund balances at the closing date plus all decommissioning collections through 2002. MGE's Nonqualified Decommissioning Fund is shown on the balance sheet in the Utility Plant section. As of December 31, 2001, this fund totaled $1.9 million (pretax fair market value) and is offset by an equal amount recorded in accumulated provision for depreciation. The securities and uninvested cash balances in the fund, net of trust investment expenses and taxes on investment income, will be transferred to the WPSC Nonqualified Decommissioning Fund on January 2, 2003.
The federal government is responsible for the disposition and storage of spent nuclear fuel. Federal legislation is being considered to establish an interim storage facility. Spent nuclear fuel is currently stored at Kewaunee. Minor plant modifications to the spent fuel pools in 2001 should ensure Kewaunee has sufficient fuel storage capacity until the end of its licensed life in 2013. MGE retains its spent fuel obligations for all fuel burned at Kewaunee for MGE's generation from the opening of the plant to the closing date. WPSC took title to such fuel at the closing date.
A surcharge imposed by the National Energy Policy Act of 1992 requires nuclear power companies to fund the decontamination and decommissioning of US Department of Energy facilities that process nuclear fuel. As a result, the Kewaunee co-owners are required to pay a surcharge on uranium enrichment services purchased from the federal government prior to October 23, 1992. On an inflation-adjusted basis, MGE's portion of the obligation related to Kewaunee is approximately $1.4 million at December 31, 2001. MGE is required to continue paying its portion of this annual assessment.
In accordance with the agreement, MGE exercised its option in June 2001 to buy electric capacity and energy at a fixed price from WPSC. MGE will purchase 90 MW of electric capacity and energy from September 24, 2001, through September 23, 2003, to help meet customers' electric needs.
11. PURCHASE OF GAS SERVICE TERRITORY
On December 28, 2001, MGE purchased the Prairie du Chien-area natural gas system from Wisconsin Electric-Wisconsin Gas (WE-WG) and the results of operations are included in the consolidated financial statements since the effective date. MGE paid an estimated amount of $3.8 million at closing until final true-up was completed in 2002. On February 25, 2002, MGE paid the final balance due of $0.1 million, for a total purchase price of $3.9 million. MGE accounted for this acquisition in accordance with SFAS No. 141, "Business Combinations," which states that all acquisitions completed after June 30, 2001, will be required to use the purchase method to account for the acquisition. The entire purchase price of $3.8 million as of December 31, 2001, was allocated to the assets based on their fair value.
This transaction includes facilities in the city of Prairie du Chien and surrounding Crawford County villages and townships. MGE gains about 3,500 residential and commercial customers. MGE has served natural gas customers in other parts of Crawford County since 1993.
As part of the purchase agreement executed on October 17, 2001, MGE and WE-WG established a definitive gas service boundary agreement for a portion of Dane County. The new boundary lines do not involve transferring any customers. The boundaries are located primarily through undeveloped land north of Madison's city limits.
12. SEGMENTS OF BUSINESS
MGE has two main business segments, electric and gas, which are both regulated. The electric business generates and distributes electricity. The gas business transports and distributes natural gas. The table below shows key information about MGE's electric and gas operations, including the distribution of net assets, for the years ended December 31.
General corporate expenses include the cost of executive management, corporate accounting and finance, information technology, risk management, human resources and legal functions, and employee benefits that are allocated to electric and gas based on formulas prescribed by the PSCW. Identifiable assets are those used in MGE's operations in each segment. Corporate assets consist primarily of cash and cash equivalents and deferred taxes.
| (In thousands) | 2001 | 2000 | 1999 | ||
| Electric Operations | |||||
| Gross operating revenues | $203,570 | $203,553 | $186,328 | ||
| Interdepartmental revenues eliminated | (392) | (377) | (373) | ||
| Total revenues | 203,178 | 203,176 | 185,955 | ||
| Operation and maintenance expenses | 129,009 | 124,101 | 115,204 | ||
| Depreciation and amortization | 29,791 | 29,137 | 29,319 | ||
| Other general taxes | 8,634 | 8,296 | 7,622 | ||
| Pretax operating income | $ 35,744 | $ 41,642 | $ 33,810 | ||
| Income tax provision | 10,353 | 11,534 | 9,599 | ||
| Net operating income | $ 25,391 | $ 30,108 | $ 24,211 | ||
| Electric Construction and Nuclear Fuel Expenditures | $ 33,722 | $ 65,312 | $ 44,297 | ||
| Gas Operations | |||||
| Gross operating revenues | $136,638 | $127,038 | $ 95,431 | ||
| Interdepartmental revenues eliminated | (6,105) | (6,106) | (7,352) | ||
| Total revenues | 130,533 | 120,932 | 88,079 | ||
| Operation and maintenance expenses | 109,672 | 99,229 | 69,552 | ||
| Depreciation and amortization | 5,868 | 5,944 | 5,835 | ||
| Other general taxes | 2,230 | 1,884 | 1,684 | ||
| Pretax operating income | $ 12,763 | $ 13,875 | $ 11,008 | ||
| Income tax provision | 3,483 | 3,882 | 2,669 | ||
| Net operating income | $ 9,280 | $ 9,993 | $ 8,339 | ||
| Gas Construction Expenditures | $ 8,244 | $ 8,294 | $ 6,691 | ||
| Assets (December 31) | |||||
| Electric | $371,423 | $395,622 | $342,130 | ||
| Gas | 130,125 | 123,486 | 114,881 | ||
| Assets not allocated | 39,903 | 52,496 | 38,499 | ||
| Total | $541,451 | $571,604 | $495,510 |
13. QUARTERLY SUMMARY OF OPERATIONS (Unaudited)
| (In thousands, except per-share amounts) | Quarters Ended | ||||||
| 2001 | March 31 | June 30 | Sept. 30 | Dec. 31 | |||
| Operating revenues: | |||||||
| Electric | $49,438 | $50,686 | $56,432 | $46,622 | |||
| Gas | 72,592 | 19,576 | 9,499 | 28,866 | |||
| Total | 122,030 | 70,262 | 65,931 | 75,488 | |||
| Operating expenses | 109,948 | 62,515 | 59,330 | 67,247 | |||
| Net operating income | 12,082 | 7,747 | 6,601 | 8,241 | |||
| Interest and other | 2,468 | 2,341 | 604 | 1,896 | |||
| Earnings on common stock before cumulative effect of a change in accounting principle | 9,614 |
5,406 |
5,997 |
6,345 |
|||
| Cumulative effect of a change in accounting principle, net of tax benefit of $78 | (117) | - | - | - | |||
| Net income | $ 9,497 | $ 5,406 | $ 5,997 | $ 6,345 | |||
| Earnings per share before cumulative effect of a change in accounting principle | $0.58 | $0.32 | $0.36 | $0.37 | |||
| Cumulative effect of a change in accounting principle | (0.01) | - | - | - | |||
| Basic and diluted earnings per share | $0.57 | $0.32 | $0.36 | $0.37 | |||
| Dividends per share | $0.331 | $0.331 | $0.333 | $0.333 | |||
| 2000 | |||||||
| Operating revenues: | |||||||
| Electric | $46,904 | $48,161 | $59,563 | $48,548 | |||
| Gas | 37,639 | 15,994 | 12,398 | 54,901 | |||
| Total | 84,543 | 64,155 | 71,961 | 103,449 | |||
| Operating expenses | 72,136 | 59,043 | 59,964 | 92,864 | |||
| Net operating income | 12,407 | 5,112 | 11,997 | 10,585 | |||
| Interest and other | 2,297 | 2,733 | 3,551 | 4,165 | |||
| Net income | $10,110 | $ 2,379 | $ 8,446 | $ 6,420 | |||
| Basic and diluted earnings per share | $0.62 | $0.15 | $0.51 | $0.39 | |||
| Dividends per share | $0.328 | $0.328 | $0.331 | $0.331 | |||
| Notes: - The quarterly results of operations within a year are not comparable because of seasonal and other factors. - The sum of earnings per share of common stock for any four quarters may vary slightly from the earnings per share of common stock for the equivalent 12-month period due to rounding. |
|||||||
Second Quarter 2001 vs. 2000. First, MGE's growth during the second quarter of 2001, when compared to 2000, can be attributed to electric sales rising 2.0% during the second quarter of 2001. During this period, all base-load power plants were operating at full capacity, and MGE's new 83-MW natural gas-fired power plant was available to help meet peak demand. Second, purchased power costs decreased $4.2 million, or 64.0%. During the second quarter of 2000, Kewaunee was out of service for scheduled refueling and maintenance. As a result, MGE had to buy more expensive replacement power on the open market. Finally, maintenance costs were 33.0% higher during the second quarter of 2000 for work required at Kewaunee and at Blount. Please see MGE's complete Form 10-Q filing dated June 30, 2001.
Third Quarter 2001 vs. 2000. MGE's 2001 third-quarter earnings reflected a decrease in electric revenues compared to the third quarter of 2000, primarily due to an after-tax adjustment of $2.7 million, which reflects a revised estimate of unbilled revenues. Electric operations and maintenance expense increased during the third quarter of 2001 due, in large part, to increased costs at Kewaunee. MGE sold its 17.8% interest in Kewaunee effective as of Sept. 24, 2001. Please see MGE's complete Form 10-Q filing dated September 30, 2001.
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 10 - Directors and Executive Officers of the Registrant
Information concerning the Directors of MGE is contained in the definitive proxy statement under the section "Election of Directors" filed prior to April 30, 2002, with the Securities and Exchange Commission, which is incorporated herein by reference.
Executive Officers of the Registrant (elected annually by Directors)
| Executive |
Title |
Effective Date |
Service Years as an Officer |
| Gary J. Wolter Age: 47 |
Chairman of the Board, President and Chief
Executive Officer President and Chief Executive Officer Senior Vice President - Administration and Secretary |
02/01/02 02/01/00 05/01/95 |
12 |
| David C. Mebane Age: 68 |
Vice Chairman of the Board Chairman of the Board Chairman, President and CEO |
02/01/02 02/01/00 05/09/94 |
21 |
| Mark C. Williamson Age: 48 |
Executive Vice President and Chief Strategic
Officer Senior Vice President - Energy Services |
02/01/00 05/01/95 |
9 |
| Lynn K. Hobbie Age: 43 |
Senior Vice President Vice President - Marketing |
02/01/00 05/01/96 |
7 |
| Mark T. Maranger Age: 53 |
Senior Vice President, MGE President and CEO, Wisconsin Fuel and Light Company |
04/09/01 1996-2001 |
- |
| James G. Bidlingmaier Age: 55 |
Vice President - Admin. and Chief Information
Officer Executive Director - Information Management Systems |
02/01/00 09/01/94 |
2 |
| Kristine A. Euclide Age: 49 |
Vice President and General Counsel, MGE Partner, in the law firm of Stafford Rosenbaum LLP Executive Assistant to County Executive of Dane County, Wisconsin, in which capacity she served as one of the senior policy advisors to the top-elected official in Dane County. |
11/15/01 1982-05/97 06/99-11/01 05/97-05/99 |
- |
| Terry A. Hanson Age: 50 |
Vice President, Chief Financial Officer and
Secretary Vice President and Chief Financial Officer Vice President - Finance Vice President and Treasurer |
10/01/01 05/01/00 11/01/97 10/01/96 |
10 |
| Jeffrey C. Newman Age: 39 |
Vice President and Treasurer Treasurer Executive Director - Budgets and Financial Management |
01/01/01 11/01/97 05/01/96 |
4 |
Note: Ages, years of service and positions as of February 1, 2002.
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 MGE'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 prior to April 30, 2002, which is incorporated herein by reference.
Item 13 - Certain Relationships and Related Transactions - None
Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form 8-K
| Index |
| (a) 1. Financial Statements. |
| Report of Independent Accountants |
| Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999 |
| Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999 |
| Consolidated Balance Sheets as of December 31, 2001 and 2000 |
| Consolidated Statements of Capitalization as of December 31, 2001 and 2000 |
| Consolidated Statements of Common Equity and Comprehensive Income as of December 31, 2001, 2000, and 1999 |
| Notes to Consolidated Financial Statements |
2. Financial Statement Schedules.
Schedule II - Valuation and Qualifying Accounts.
All other schedules have been omitted because they are not applicable or not required, or because the required information is shown in the consolidated financial statements or notes thereto.
3. All Exhibits Including Those Incorporated by Reference.
Exhibits. An asterisk (*) indicates a management contract or compensatory plan or arrangement.
No. Description
3.(i) Articles of Incorporation as in effect at May 6, 1996. (Incorporated by reference to Exhibit 3.(i) with 1996 Form 10-K in File No. 0-1125.)
3.(ii) By-Laws as in effect at September 21, 2001. (Incorporated by reference to Exhibit 3.2 with October 5, 2001, Form S-3 in File No. 333-71038.)
4A Indenture of Mortgage and Deed of Trust between MGE 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 Indenture | Dated as of | Exhibit No. | SEC File No. | |||
| Fourteenth | 04/01/1992 | 4C | 0-1125 (1992 10-K) | |||
| Fifteenth | 04/01/1992 | 4D | 0-1125 (1992 10-K) | |||
| Sixteenth | 10/01/1992 | 4E | 0-1125 (1992 10-K) | |||
| Seventeenth | 02/01/1993 | 4F | 0-1125 (1992 10-K) |
4B Indenture between MGE and Bank One, N.A., as Trustee, dated as of September 1, 1998. (Incorporated by reference to Exhibit 4B with 1999 Form 10-K in File No. 0-1125.)
10A Copy of Joint Power Supply Agreement with Wisconsin Power and Light Company and Wisconsin Public Service Corp. 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 Corp. 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 Corp. 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 Form 10-K in File No. 0-1125.)
12 Statement regarding computation of ratio of earnings to fixed charges.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
4. Reports on Form 8-K.
No current report on Form 8-K was filed for the quarter ended December 31, 2001.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
| Additions | |||||||||
| Balance at beginning of period |
(1)
Charged to costs and expenses |
(2)
Charged to other accounts |
Net Accounts written off |
Balance at end of period |
|||||
| Fiscal Year 1999: Accumulated provision for uncollectibles |
(1,281,301) |
(1,331,000) |
- |
1,221,244 |
(1,391,057) |
||||
| Fiscal Year 2000: Accumulated provision for uncollectibles |
(1,391,057) |
(2,032,909) |
- |
1,352,862 |
(2,071,104) |
||||
| Fiscal Year 2001: Accumulated provision for uncollectibles |
(2,071,104) |
(2,887,124) |
- |
1,193,901 |
(3,764,327) |
||||
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 1, 2002 | /s/ Gary J. Wolter |
| 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 1, 2002.
| /s/ Gary J. Wolter | Chairman, President and Chief Executive Officer and Director (Principal Executive Officer) |
| /s/ Terry A. Hanson | Vice President, Chief Financial Officer and Secretary (Principal Financial Officer and Principal Accounting Officer) |
| /s/ David C. Mebane | Vice Chairman of the Board and Director |
| /s/ Richard E. Blaney | Director |
| /s/ F. Curtis Hastings | Director |
| /s/ Regina M. Millner | Director |
| /s/ Frederic E. Mohs | Director |
| /s/ John R. Nevin | Director |
| /s/ Donna K. Sollenberger | Director |
| /s/ H. Lee Swanson | Director |