Item 1 - Business
GENERAL DESCRIPTION OF BUSINESS
Madison Gas and Electric Company (MGE), a Wisconsin corporation organized in 1896, is a public utility that generates, transmits and distributes electricity in Dane County, Wisconsin (250 square miles). MGE also purchases, transports and distributes natural gas in seven Wisconsin counties: Columbia, Crawford, Dane, Iowa, Juneau, Monroe and Vernon (1,325 square miles). Exhibit No. 21 describes MGE's wholly owned subsidiaries.
The Public Service Commission of Wisconsin (PSCW) has authority to regulate MGE's rates, accounts, issuance of securities, plant and transmission line siting, and other aspects of its business. The Federal Energy Regulatory Commission (FERC) has jurisdiction, under the Federal Power Act, over certain accounting practices and certain other aspects of MGE's business. The Nuclear Regulatory Commission (NRC) has jurisdiction over operation of the Kewaunee Nuclear Power Plant (Kewaunee). MGE has a 17.8% ownership interest in Kewaunee. The other owners are Wisconsin Public Service Corp. (WPSC), which operates Kewaunee, and Alliant Energy Corp.
MGE is also subject to state and federal regulations concerning air quality, water quality and solid waste. MGE may be subject to other environmental regulations set by various federal, state and local authorities including the Wisconsin Department of Natural Resources (DNR), which 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. MGE has met the requirements of current environmental regulations. It is not known if additional expenditures will be required for pollution control equipment and/or modifying existing plants to comply with future unknown environmental regulations.
The ongoing issue of global warming could result in significant compliance costs for reducing carbon dioxide emissions. MGE does not yet know the amounts of these expenditures or the period of time over which they may be required. MGE is unable to predict if complying with future pollution control regulations could involve: (1) curtailing operations, (2) reducing capacity or efficiency at existing plants or (3) delaying the construction and operation of future generating facilities.
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.
ELECTRIC OPERATIONS
At Dec. 31, 2000, MGE supplied electric service to approximately 126,000 customers, of whom 113,000 were located in the cities of Fitchburg, Madison, Middleton and Monona, and 13,000 in adjacent areas. Of the total number of customers, approximately 109,000 were residential and 17,000 were commercial and industrial. Electric revenues for 2000 comprised of residential (34%), commercial (48%), industrial (7%), sales to public authorities including the University of Wisconsin (7%) and sales to other utilities (4%). Electric operations accounted for 63% of MGE's total 2000 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 better utilize reserve generating capacity and coordinate long-range system planning and day-to-day operations. MAIN seeks to maintain adequate planning generation reserve margins in the region, ranging from 15% to 22%.
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 the energy flows on their individual transmission system.
On Oct. 29, 1999, Reliability 2000 legislation took effect (Part of 1999 Wisconsin Act 9). Part of Reliability 2000 was the creation of a statewide for-profit transmission company (American Transmission Company LLC [ATC]) that will own the transmission assets formerly owned by investor-owned utilities. Formation of the ATC was to provide reliable, economic transmission service to all customers in a fair and equitable manner. ATC will plan, construct, operate, maintain and expand transmission facilities it owns to provide adequate and reliable transmission of power.
MGE along with the other Wisconsin investor-owned utilities, several municipals and retail cooperatives have joined ATC by either contributing cash and/or transferring their transmission assets. ATC began operations on Jan. 1, 2001, at which time MGE transferred its electric transmission facilities. In exchange for its transmission plant and related deferred taxes and deferred investment tax credits, MGE receives an approximate 6.0% ownership interest in the ATC. MGE expects to receive a return on its investment in ATC approximately equal to the return it would have earned by retaining its transmission facilities. ATC is regulated by FERC.
In 2001, MGE started paying a network service fee for using the ATC transmission system. MGE's transmission assets 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 the ATC will be deferred subject to regulatory treatment.
Fuel Supply and Generation
MGE estimates its net kilowatt-hour requirements for 2001 will be provided from the following sources: 69% from fossil-fueled steam plants, 19% from a nuclear-fueled steam plant, 10% from power purchases and 2% from a combination of wind turbines, diesel generators and oil-fired combustion turbines.
MGE has a 22% ownership interest in the Columbia Energy Center (Columbia). The other owners are Alliant Energy Corp., which operates Columbia, and WPSC. The first (Columbia I) and second (Columbia II) units at Columbia were placed in commercial operation in 1975 and 1978, respectively. The Columbia co-owners' coal inventory supply for Columbia I and Columbia II decreased from 68 days on Dec. 31, 1999, to 40 days on Dec. 31, 2000. The co-owners' goal is to maintain approximately a 40-day inventory. Columbia, with two 527-megawatt (MW) units, obtains 100% of its low-sulfur coal from the Powder River Basin coal fields located in Wyoming and Montana.
For information about a request from the Environmental Protection Agency (EPA) that affects Columbia, refer to the following section on "air quality."
The Kewaunee plant is a pressurized water reactor plant with a nameplate capacity of 562 MW. It began commercial operation in 1974. The Kewaunee operating license expires in 2013.
On April 7, 1998, WPSC received state regulatory approval to replace two steam generators at Kewaunee. The replacement work, which will take approximately 60 days, is scheduled for fall 2001. The project will cost approximately $120 million. MGE will not be responsible for any portion of this cost due to a change in ownership described below.
On Sept. 29, 1998, MGE finalized an agreement to sell its share of Kewaunee to WPSC. MGE will receive a cash payment from WPSC for Kewaunee upon closing. The payment will be comprised of Kewaunee's book value (currently $8.9 million) plus the book value of other assets related to Kewaunee. MGE believes it can secure electric capacity and energy more cost effectively from other sources and eliminate the risk of future stranded costs. On May 18, 2000, MGE and WPSC received state regulatory approval to transfer MGE's ownership share in Kewaunee to WPSC, subject to the terms of the agreement described above.
MGE has an option under the sale agreement to enter into an electric capacity and energy agreement (up to 90 MW) at a fixed price from WPSC for two years after the sale closes. MGE's decommissioning liability will be limited to the current fund balance until the sale closes, plus all decommissioning collections through 2002. The qualified decommissioning trust will be transferred to WPSC upon closing. MGE is beginning to discuss with WPSC the disposition of the nonqualified nuclear decommissioning trust.
On April 22, 2000, Kewaunee shut down for its scheduled spring refueling outage. The plant had operated continuously (511 days) since start-up from the 1998 refueling outage. On June 2, 2000, the plant returned to service from its planned maintenance and refueling outage. Inspection of the plant's two steam generators showed that tubes repaired in previous outages were holding up well. A major overhaul was also performed on the main electrical generator. The next shutdown for refueling and maintenance is scheduled for fall 2001. Kewaunee ended 2000 with 206 days of continuous operation since start-up from the last refueling outage.
The Kewaunee co-owners have requested approval from state regulators to defer all anticipated operating and capital costs related to the replacement of the steam generators of Kewaunee in 2001. In addition, MGE is negotiating with the co-owners to share the incremental 2001 costs required to keep Kewaunee on-line until the steam generator replacement starts.
The federal government has the responsibility to dispose of or permanently store spent nuclear fuel. Legislation is being considered on the federal level to establish an interim storage facility. Spent nuclear fuel is currently being stored at Kewaunee. Minor plant modifications being made to the spent fuel pools are almost complete. Upon completion, Kewaunee should have sufficient fuel storage capacity until the end of its licensed life in 2013.
The Midwest Compact Commission continues to monitor the availability of disposal facilities for the low-level radioactive waste created by all Midwest generators. A site at Barnwell, S.C., has been available for the storage of low-level radioactive waste from Kewaunee in the past. The availability of this site for future waste storage is uncertain. As a result of technology advances, waste compaction and the reduction of waste generated, Kewaunee has on-site low-level radioactive waste storage capacity sufficient to store all low-level waste expected at the plant over the next 10 years.
In 1997, the PSCW directed the owners of Kewaunee to develop depreciation and decommissioning cost levels based on full recovery by the end of 2002. Previously, cost estimates had been based on full collection of funds required for decommissioning by 2013, the year in which the operating license expires. The order was prompted by uncertainty about the expected useful life of the plant without steam generator replacement. On Dec. 31, 2000, the net carrying amount of MGE's investment in Kewaunee was approximately $8.9 million. MGE's share of Kewaunee decommissioning costs is an estimated $93.1 million in current dollars based on a site-specific study performed in 1992 using immediate dismantlement as the method of decommissioning.
Decommissioning trust assets at Dec. 31, 2000, totaled $102.9 million, its pretax fair market value. The study assumed decommissioning costs would inflate at an average rate of 6.0% per year. MGE's decommissioning liability is limited to the current fund balances plus all decommissioning contributions through 2002 (under the agreement that allows MGE to sell its share of Kewaunee to WPSC). Physical decommissioning is expected to occur from 2014 through 2021. Additional expenses will likely be incurred from 2022 through 2039 to store spent nuclear fuel at the plant site.
Nuclear decommissioning costs are currently recovered from customers in rates and are deposited in external trusts. For 2000, the decommissioning costs recovered in rates were $8.1 million.
The Kewaunee co-owners purchase uranium concentrates, conversion services, enrichment services and fabrication services for nuclear fuel assemblies at Kewaunee. Approximately one-third of the 121 fuel assemblies are removed from the reactor every 18 months and replaced with new assemblies. Removed assemblies are placed in storage at the plant site pending permanent disposal by the Department of Energy (DOE).
If for any reason Kewaunee was forced to suspend operations permanently, the maximum exposure related to fuel contracts is not expected to exceed $6.5 million. The increased exposure is due to a new long-term fuel fabrication contract with Westinghouse. No financial penalties associated with the present supply, conversion service and enrichment agreements exist. In addition, the exposure is further mitigated since the uranium inventories could be sold on the spot market.
A surcharge imposed by the National Energy Policy Act of 1992 requires nuclear power companies to fund the decontamination and decommissioning of DOE 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 Oct. 23, 1992. On an inflation-adjusted basis, MGE's portion of the obligation related to Kewaunee is approximately $1.6 million at Dec. 31, 2000. MGE has agreed to continue to pay its portion of this annual assessment after the transfer of its ownership interest in the plant to WPSC.
Air Quality
MGE is meeting the Phase II requirements of the 1990 Federal Clean Air Act amendments which sets limits for allowable emissions of sulfur dioxides (SO2) and nitrogen oxides (NOx).
On Jan. 1, 2000, Phase II of the 1990 Federal Clean Air Act amendments took effect, setting new emission limits for SO2 and NOx. MGE's generating 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 Oct. 27, 1998, the EPA issued final rules requiring more NOx emission reductions from utilities located in southern Wisconsin. However, a legal challenge resulted in excluding Wisconsin from this rule and returning the issue to the EPA on March 3, 2000, for further action. On Jan. 8, 2001, former EPA Administrator Carol Browner signed a proposed rule that would exclude Wisconsin (and MGE) from further NOx emission reductions required by the original rule. The proposed rule must still be finalized.
If the EPA or DNR imposes additional NOx controls, MGE is evaluating alternative 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, operating and maintenance expenditures.
Wisconsin's acid rain law imposes limitations of 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.
On Dec. 14, 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 Dec. 15, 2003, and final regulations published no later than Dec. 15, 2004. The DNR is also evaluating its rules to limit mercury emissions from coal-fired boilers. If either of these regulations are issued, they may require MGE to evaluate emission control options for its Blount facility in order to comply with the regulations. These controls would likely increase capital, operating and maintenance expenses.
In December 2000 and February 2001, the EPA requested certain information relating to the operation of Columbia and other major coal-fired generating units in Wisconsin. The Columbia co-owners responded to the December 2000 request and are in the process of preparing a response to the February 2001 request. In some cases involving other electric generating facilities, penalties and capital expenditures have resulted. MGE cannot presently predict what impact, if any, the EPA's request may have on its financial condition or results of operations.
MGE believes all of its plants to be in full compliance with all material aspects of present air-pollution control regulations.
Water Quality
MGE is subject to water quality regulations by the DNR. These regulations include both 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 pursuant to 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 two sites that the EPA has placed on the national priorities Superfund list: (1) the Refuse Hideaway Landfill in Middleton, Wis., where MGE disposed of fly-ash sludge and general office waste from 1980 to 1984 and (2) the Lenz Oil site in Lemont, Ill., which was used for storing and processing waste oil for several years. These sites require clean up under the Comprehensive Environmental Response, Compensation and Liability Act. A group of companies including MGE is currently negotiating with the EPA on the cleanup of these two sites.
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 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 Dec. 31, 2000, MGE accrued a $250,000 liability on its balance sheet for this matter.
GAS OPERATIONS
On Dec. 31, 2000, MGE supplied natural gas service to approximately 114,000 customers in the cities of Elroy, Madison, Middleton, Monona, Fitchburg, Lodi, Verona and Viroqua; 22 villages; and all or parts of 41 townships. Gas revenues for 2000 comprised of residential (56%), commercial (37%), industrial (2%) and other (5%). Transportation service accounted for slightly more than 2% of the total 2000 gas revenues. Gas operations accounted for 37% of MGE's total revenues.
MGE can curtail gas deliveries to its interruptible customers. Approximately 4% of gas sold in 2000 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 four ANR and one NNG gate station. MGE also receives deliveries at NNG gate stations located in Viroqua and Elroy and in 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 U.S. mid-continent and Gulf/offshore regions.
By contract, a total of 4,944,328 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 1999 through March 2000) was warmer than normal (13% fewer heating degree days). The current heating season (November 2000 through March 2001) has been 8% colder than normal (based on actual heating degree days through February) and has caused storage levels to be lower than normal.
MGE's contracts for firm transportation service include maximum daily quantities of:
- 46,572 dekatherms (excluding storage) on ANR.
- 48,719 dekatherms on NNG.
- 2,457 dekatherms into Viroqua's NNG gate station.
- 1,432 dekatherms into Crawford County's NNG gate station.
GENERAL
MGE's business is seasonal based on fluctuations in seasonal weather conditions.
MGE had 693 permanent employees at Dec. 31, 2000.
Information regarding MGE executive officers is included under Item 10, Directors and Executive Officers of the Registrant.
Item 2
Item 2 - Properties
The following table presents the generating capability in service at Dec. 31, 2000:
Plants
Commercial Operation Date
Fuel
Net Capability (MW)
No. of Units
Steam plants:
Columbia
1975 & 1978
Low-sulfur coal
232 (1,2,4)
Kewaunee
Nuclear
93 (1,3,5)
Blount (Madison)
1957 & 1961
Coal/gas
1938 & 1942
Gas
Coal/gas
1964-1968
Gas/oil
Combustion turbines
1964-2000
Gas/oil
Portable generators
1998-2000
Diesel
Wind turbines
Wind
Total
1 Base load generation
2 MGE's 22% share of two 527-MW units located near Portage, Wis.
3 MGE's 17.8% share of 525-MW unit located near Kewaunee, Wis.
4 See Item 3, Legal Proceedings.
5 See Item 1, Kewaunee, and Item 7, Kewaunee, for more information.
Major electric transmission and distribution lines and substations in service at Dec. 31, 2000, are as follows:
Gas facilities include 1,994 miles of distribution mains.
Item 3
Item 3 - Legal Proceedings
In May 1999, MGE brought an arbitration proceeding against Alliant Energy Corp., the parent company of Wisconsin Power and Light Co. (WPL). The arbitration was based on a claim regarding WPL's merger into Alliant and the manner in which the Columbia Energy Center is run that triggered MGE's right to acquire WPL's interest in the plant at book value.
MGE recently 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 did recognize one of MGE's primary arguments. MGE argued that WPL had transferred its interest in the Columbia to its parent company, Alliant, after Alliant's merger in 1998. The arbitrators recognized MGE's argument by formally requiring Alliant to accept responsibility as the operator and manager of the plant.
Item 4
Item 4 - Results of Votes of Security Holders
No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year.
PART II.
Item 5
Item 5 - Market For The Registrant's Common Stock And Related Stockholder Matters
MGE common stock is traded on The Nasdaq Stock Market (Nasdaq) under the symbol MDSN. On March 1, 2001, there were approximately 17,785 stockholders of record. During 2000, MGE's transfer agent and registrar, Harris Trust and Savings Bank Shareholder Services, was acquired by Computershare Investor Services, L.L.C. Effective Jan. 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 (1) high and low sales prices for the common stock on Nasdaq and (2) dividends paid per common share for each quarter over the past two years.
Item 6
Item 6 - Selected Financial Data
(In thousands, except per-share amounts)
For the years ended Dec. 31
Summary of Operations
Operating Revenues:
Electric
$203,176 $185,955 $169,563 $163,123 $152,747
Gas
120,932
88,079
80,189
101,525
100,544
Total
324,108 274,034 249,752 264,648 253,291
Operating expenses 258,411 219,910 199,954 212,921 200,486
Other general taxes 10,180 9,306 9,263 8,797 8,736
Income tax items 15,416
12,268
10,723
11,940
12,553
Net operating income
40,101 32,550 29,812 30,990 31,516
Other (loss)/income (including AFUDC-equity) 1,383
3,235
3,273
2,257
(14,198)
Income before interest expense
41,484 35,785 33,085 33,247 17,318
Interest expense (including AFUDC-debt) 14,129
12,039
10,855
10,724
10,891
Net income
27,355 23,746 22,230 22,523 6,427
Preferred dividends -
-
-
-
-
Earnings on common stock
$ 27,355
$ 23,746
$ 22,230
$ 22,523
$ 6,427
Average shares outstanding 16,382 16,084 16,080 16,080 16,080
Earnings per share
$1.67 $1.48 $1.38 $1.40 $0.40
Dividends paid per share
$1.318 $1.308 $1.298 $1.287 $1.273
Assets
Electric $395,622 $342,130 $311,563 $313,855 $315,022
Gas 123,486 114,881 111,762 118,339 116,723
Assets not allocated 52,496
38,499
42,940
39,596
52,424
Total
$571,604
$495,510
$466,265
$471,790
$484,169
Capitalization including Short-Term Debt
Common shareholders' equity $200,312 $185,686 $182,275 $180,923 $179,089
Long-term debt* 183,637 159,799 159,761 129,923 128,886
Short-term debt 44,000
15,750
-
33,500
29,750
Total Capitalization
$427,949
$361,235
$342,036
$344,346
$337,725
*Includes current maturities.
Item 7
Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations
GENERAL
The following discussion and analysis provides information which management believes is relevant to an assessment and understanding of Madison Gas and Electric Company's (MGE) consolidated results of operations and financial condition. This discussion should be read in conjunction with the consolidated financial statements and notes.
This report, and certain other MGE public documents, contain forward-looking statements that reflect management's current assumptions and estimates of 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 Safe Harbor 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.
RESULTS OF OPERATIONS
Earnings Overview
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 contributed significantly to higher net income: (1) performance-based natural gas incentives, which added $0.7 million (after tax) and (2) pension costs, which were down $1.1 million (after tax) due to 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: (1) a 5.1% electric rate increase effective in January and (2) increase in gas margin due to higher deliveries in 1999.
In 1998, MGE achieved earnings of $22.2 million, or $1.38 per share, despite one of the warmest heating seasons on record. MGE minimized the impact of weather on earnings by: (1) controlling costs, (2) selling its remaining assets in National Energy Management, L.L.C. (NEM) and (3) implementing risk management strategies to limit the loss of gas revenue due to abnormally warm weather.
Electric Sales and Revenues
Electric retail sales increased 2.5% for the 12 months ending Dec. 31, 2000, 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 Jan. 1, 2000, combined with customer growth and greater use per customer ($14.5 million) (see Item 8, Rate Matters).
- Increased revenues associated with MGE's new electric generating assets: an 83-megawatt (MW) natural gas-fired combustion turbine ($2.5 million) and wind energy and customer backup generation ($0.7 million).
In 1999, MGE had a fourth-quarter electric fuel surcharge (described below), which was not in effect for 2000.
Electric sales (megawatt-hours)
% Change
Residential 780,446 770,153
1.3
Commercial 1,577,165 1,524,641
3.4
Industrial 319,394 315,238
1.3
Other 307,263
301,147
2.0
Total retail
2,984,268 2,911,179
2.5
Resale - utilities 283,809
312,861
(9.3)
Total sales
3,268,077
3,224,040
1.4
In 1999, electric retail sales increased 2.1% and sales for resale rose 306.9%. The sharp rise in sales for resale occurred when MGE started selling 30 MW of firm capacity to Wisconsin Public Power Inc. in March 1999 (see Item 8, Commitments).
Electric revenues in 1999 increased $16.4 million, or 9.7%, primarily due to:
-A 5.1% electric rate increase effective in January 1999, combined with customer growth and greater use per customer ($12.8 million).
-A 3.6% interim electric fuel surcharge in effect during the fourth quarter ($1.8 million) (see Item 8, Rate Matters).
-Higher sales for resale compared to 1998.
Gas Sales and Revenues
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. This resulted in higher customer demand for natural gas. The higher volume of gas delivered to customers contributed to our bottom line. We did not profit from unusually high gas prices. The Public Service Commission of Wisconsin (PSCW) requires utilities to pass along to customers the price paid for gas, whether it goes up or down.
Gas revenues were up $32.9 million, or 37.3%, in 2000 due to: (1) increased deliveries, (2) higher gas costs that were passed on to customers through the Purchased Gas Adjustment clause (PGA) and (3) an increase of $1.2 million in other gas revenues from MGE's Gas Cost Incentive Mechanism (GCIM). The table below shows total gas deliveries by customer class.
Terms delivered (In thousands)
% Change
Residential 90,446 81,219
11.4
Commercial and industrial 78,190
69,246
12.9
Total retail system
168,636 150,465
12.1
Transport 45,193
46,013
(1.8)
Total gas deliveries
213,829
196,478
8.8
In 1999, total retail gas therms delivered by MGE rose 4.9% over the prior year. Total heating degree days were up 10.4% compared to 1998. Gas revenues were up $7.9 million, or 9.8%, in 1999 due to: (1) increased deliveries and (2) higher gas costs that were passed on to customers through the PGA.
Electric Fuel and Natural Gas Costs
During 2000, fuel costs for electric generation rose $4.0 million, or 12.2%. MGE customers set a record for peak demand (664 MW) on Aug. 31.
The Kewaunee Nuclear Power Plant (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 was primarily because MGE added new generation in 2000 (previously described) and the company relied more on purchased power in 1999 during unexpected outages at the coal-fired Columbia Energy Center (Columbia).
Electric margins (revenues less fuel and purchased power expenses) were up $16.5 million, or 12.6%, due to: (1) a 5.5% electric rate increase and growth in retail sales stemming from an increase in customers and usage per customer ($14.5 million) and (2) 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.
In 1999, purchased power costs increased $12.6 million, or 130.7%, from the prior year. MGE paid more for purchased power when Columbia was out of service and during summer peak demand. Electric margins were up $3.7 million, or 2.9%, due to the electric rate increases previously described and higher sales for resale.
Natural Gas Costs
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/therm) increased more than 60.0% in 2000 compared to 1999. These higher gas costs were passed on to MGE customers through the PGA. Gas margins (revenues less gas purchased) increased $4.8 million, or 12.3%, in 2000 primarily as a result of: (1) higher retail deliveries, (2) a $1.0 million gain for recovering certain regulatory gas assets and (3) a $1.2 million increase in other gas revenues related to MGE's GCIM.
In 1999, natural gas costs increased $3.9 million, or 8.7%, because retail deliveries were up 4.9%. Gas margins rose $4.0 million, or 11.4%, in 1999. Contributing factors included: (1) a rise in retail deliveries and (2) a 0.7% rate increase effective in January 1999.
Other Operating Expenses
Electric: In 2000, electric operating expense rose $2.9 million, or 6.1%, primarily due to higher: (1) operating cost at Kewaunee ($0.9 million), (2) expense for outside services ($0.8 million) and (3) 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.
In 1999, electric operating expense increased $2.3 million, or 4.9%, primarily due to payroll and benefits of $1.3 million and transmission wheeling expenses of $1.0 million.
Gas: In 2000, gas operating expense rose $1.3 million, or 7.0%, due to higher distribution costs and other general expenses.
In 1999, gas operating expense rose approximately $0.9 million, or 5.5%, due to higher administrative and general expenses.
Maintenance Expense: Electric: In 2000, electric maintenance expense rose $5.2 million, or 44.1%, due to costs related to the Kewaunee outage ($3.0 million), additional maintenance at Blount Generating Station (Blount) ($0.9 million), one of MGE's combustion turbines ($0.5 million) and Columbia ($0.2 million).
In 1999, electric maintenance expense was down $1.8 million, or 13.6%, primarily because of lower costs at Kewaunee. Kewaunee completed 1999 with 100.0% availability.
Depreciation: In 2000, depreciation expense decreased slightly. Certain utility plant assets became fully depreciated in 2000, offsetting the impact on depreciation of utility plant additions.
In 1999, depreciation expense increased $2.0 million, or 5.9%. Electric depreciation expense totaling $1.7 million resulted from increased plant additions and decommissioning depreciation expense.
Other General Taxes: The increase ($0.9 million, or 9.4%, over 1999) in other general taxes reflects a higher utility license fee tax, which is based on operating revenues.
Income Taxes: Effective income tax rates were generally consistent over the three-year period. Increases in income tax provision ($3.1 million and $1.5 million in 2000 and 1999, respectively) are due to progressively higher operating income.
Interest Expense: In 2000, total interest increased $2.1 million, or 17.3%. Compared to 1999, MGE had higher levels of short-term debt and the interest on $35.0 million in new long-term debt ($20.0 million issued on May 4, 2000, and $15.0 million issued on Sept. 20, 2000).
In 1999, interest on long-term debt increased $1.3 million, or 12.4%. In September 1998, MGE issued $30.0 million in unsecured debt, which was outstanding throughout 1999.
Other Nonoperating Items
In 2000, other income decreased $1.9 million, or 64.5%. MGE donated $1.8 million to the MGE Foundation and the MGE Innovation Center. 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 (see Item 8, 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 gas marketing subsidiaries, Great Lakes Energy Corp. (GLENCO) and American Energy Management, Inc. (AEM), to reflect its current value. These outstanding contingencies included: (1) expired lighting warranties and outstanding accounts payable for AEM and (2) one-time benefits on some outstanding legal and tax issues for GLENCO and AEM.
In 1998, MGE sold its remaining assets in NEM for $1.8 million. NEM was formed in January 1997 as a joint venture between MGE's gas marketing subsidiaries and National Gas and Electric L.P. Earnings on the decommissioning trusts totaled $1.8 million in 1998. This amount is included in other income and depreciation expense.
Year 2000
MGE did not experience any latent Year 2000 issues and does not expect any further expenditures.
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 2005. MGE expects to maintain a competitive advantage because of its:
-Vibrant service territory, which is well-insulated against economic downturns.
-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 will sell its ownership interest (17.8%) 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 currently regulates MGE for both its electric and gas operations. 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 University of Wisconsin (UW) propose building a $170.0 million natural gas-fired cogeneration plant to help meet 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 100 MW of electricity to help meet growing customer demand in the Madison area. MGE will own the electric-generating portion of the plant. MGE and the UW plan to jointly operate and maintain the plant. The unit is expected to start operating in 2004.
MGE has a memorandum of understanding to own a portion of the coal-fired base load generation included in Wisconsin Energy Corp.'s (WEC) modified "Power the Future" proposal. The proposal includes three 600-MW coal-fired units of new generation. MGE's option secures ownership of 50 MW in each unit for a total of 150 MW. If WEC's proposal is approved and MGE exercises its option, MGE's expected investment over the next 10 years would range from $150.0 million to $175.0 million.
KEWAUNEE NUCLEAR POWER PLANT
Kewaunee is jointly owned by MGE, Wisconsin Public Service Corp. (WPSC) and Alliant Energy Corp. Kewaunee has been operated since 1974 by WPSC. The plant's license will expire in 2013.
On April 7, 1998, WPSC received state regulatory approval to replace two steam generators at Kewaunee. The replacement work, which will take approximately 60 days, is scheduled for fall 2001. The project will cost approximately $120.0 million. MGE will not be responsible for any portion of this cost due to a change in ownership described below.
On Sept. 29, 1998, MGE finalized an agreement to sell its share of Kewaunee to WPSC. MGE is expected to transfer its ownership interest in Kewaunee in the fall of 2001. MGE will receive a cash payment from WPSC for Kewaunee upon closing (date plant shuts down for steam generator replacement).
The payment will be comprised of MGE's share of Kewaunee's book value (currently $8.9 million) plus the book value of other assets related to Kewaunee. MGE believes it can secure electric capacity and energy more cost-effectively from other sources and eliminate the risk of future stranded costs. On May 18, 2000, MGE and WPSC received state regulatory approval to transfer MGE's ownership share in Kewaunee to WPSC, subject to the terms of the agreement described above.
MGE has an option under the sale agreement to enter into an electric capacity and energy agreement (up to 90 MW) at a fixed price from WPSC for two years after the sale closes.
As part of the sale agreement, MGE's decommissioning liability and the related trust fund assets are assumed by WPSC at closing. In exchange for this assumption, MGE is required to continue funding the decommissioning trusts through 2002. MGE expects to fully recover its decommissioning costs for Kewaunee in future rates.
On April 22, 2000, Kewaunee shut down for its scheduled spring refueling outage. The plant had operated continuously (511 days) since startup after the 1998 refueling outage. On June 2, 2000, the plant returned to service from its planned maintenance and refueling outage. Inspection of the plant's two steam generators showed that tubes repaired in previous outages were holding up well. A major overhaul was also performed on the main electrical generator. The next shutdown for refueling and maintenance is scheduled for fall 2001. Kewaunee ended 2000 with 206 days of continuous operation since startup from the last refueling outage.
The Kewaunee co-owners have requested approval from state regulators to defer all anticipated operating and capital costs related to the replacement of the steam generators of Kewaunee in 2001. In addition, MGE is negotiating with the co-owners to share only the costs required to keep Kewaunee on-line until the steam generator replacement starts.
LIQUIDITY AND CAPITAL RESOURCES
Cash Provided by Operating Activities
In 2000, cash provided by operating activities decreased $12.6 million, or 20.8%, compared to last year. This is primarily due to a $24.5 million increase in current assets (excluding cash and cash equivalents) compared to 1999. Record-high gas costs forced average utility bills up about 40.0% 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 $9.6 million in 2000 compared to 1999, somewhat offsetting the increase in current assets.
In 1999, cash provided by operating activities decreased $10.2 million, or 14.5%, primarily due to a decrease in net working capital.
Capital Requirements and Investing Activities
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 83-MW gas-fired combustion turbine previously described).
MGE's liquidity is primarily affected by its construction requirements. Capital expenditures in 2000 totaled $73.6 million, which included: (1) purchasing an 83-MW natural gas-fired combustion turbine ($31.3 million), which started operating in June, (2) MGE-owned customer backup generators ($5.1 million), (3) a gas pipeline expansion project ($2.1 million), (4) improvements at Blount ($1.2 million) and (5) nitrogen oxide (NOx) emissions equipment at the jointly owned Columbia plant ($2.5 million). The remaining capital expenditures were related to normal system upgrades.
It is anticipated 2001 capital expenditures will be $44.6 million, which will include improvements at the Blount plant. These improvements comply with new legislation or help maintain the reliability of MGE's system.
Capital expenditures for the years 2002 through 2005 will average an estimated $45.0 million per year (including the UW cogeneration project previously described). The table below shows capital expenditures and nuclear fuel estimates for 2001, actuals for 2000 and the three-year average for 1997 to 1999.
MGE used internally generated funds and short-term debt to satisfy most of its capital requirements. For larger capital investments, MGE issued additional long-term debt and common stock.
In 1999, MGE's cash used for investing activities increased $21.0 million, or 51.5%, also due to new plant additions. MGE's capital requirements in 1999 included $13.0 million for a wind project, $10.0 million in distributed generation and $3.0 million for improvements at Blount.
Financing Activities and Capitalization Matters
In 2000, cash provided by financing activities increased $43.2 million from 1999. MGE had several large capital investments in 2000, which required the issuance of long-term debt ($35.0 million) and short-term debt ($28.3 million). MGE raised $9.0 million through the issuance of common stock for its Dividend Reinvestment and Direct Stock Purchase Plan (Plan).
In 1999, cash used for financing activities decreased $20.8 million, or 84.6%. MGE added short-term debt totaling $15.8 million. In December 1999, MGE started issuing new shares of common stock for the Plan to improve cash flow and capitalization ratios.
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.
BUSINESS AND REGULATORY ENVIRONMENT
American Transmission Company LLC (ATC)
Based on a commitment made in June 2000, MGE transferred to ATC on Jan. 1, 2001, its electric transmission facilities with a net book value of $43.6 million. ATC is a joint venture authorized by Reliability 2000 legislation in Wisconsin (1999 Wis. Act 9) to independently own and operate the transmission system in Wisconsin. ATC provides equal and fair access to Wisconsin's transmission system to all joint-venture partners. All of Wisconsin's investor-owned utilities have contributed their transmission facilities to ATC. In addition, several Wisconsin municipal utilities, retail electric cooperatives and power supply agencies are participating by contributing cash and/or transferring transmission assets.
In exchange for its transmission plant and related regulatory deferred taxes and deferred investment tax credits, MGE received an approximate 6.0% interest in ATC. In 2001, each member of the ATC will be subject to an independent audit of its contributed transmission assets in order to finalize initial ownership interests.
MGE will account for its investment in ATC on the equity method of accounting.
ATC is regulated by the Federal Energy Regulatory Commission. MGE expects to receive a return on its investment in ATC approximately equal to the return it would have earned by retaining its transmission facilities.
In 2001, MGE started paying a network service fee for using the ATC transmission system. MGE's transmission assets 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 the ATC will be deferred subject to regulatory treatment.
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 won't work if there is a supply shortage. 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 Financial Accounting Standard (FAS) 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 Incentive Mechanism
Under MGE's GCIM, 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 2000, MGE shareholders gained approximately $0.9 million in gas commodity incentives and $0.3 million in capacity release incentives in 1999.
New Accounting Pronouncements
In June 2000, the Financial Accounting Standards Board (FASB) issued FAS No. 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities, An Amendment of FAS No. 133." This standard includes several amendments to FAS No. 133 and is effective for all fiscal years beginning after June 15, 2000. MGE adopted FAS No. 133 and FAS No. 138 as of Jan. 1, 2001.
The new standard requires that all derivative instruments be reported on the balance sheet at their fair values. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. It also requires MGE to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. For derivative instruments classified as fair-value hedges, the changes in the fair value of the derivative instrument will be offset on the income statement by the changes in the fair value of the hedged item. For derivative instruments classified as cash-value hedges, the effective portion of the hedge is reported in other comprehensive income until it is cleared to earnings. The ineffective portion of all hedges would be recognized through current earnings. For derivative instruments not classified as a hedge, the change in the fair value of the derivative will be recorded each period in current earnings.
MGE adopted FAS No. 133 on Jan. 1, 2001. There was no material effect on net income from adopting this new standard or making the transition adjustment.
The determination of the impact of FAS No. 133 is based on current interpretations of this statement, including interpretations of the Derivatives Implementation Group of the FASB. Final guidance, when issued, may affect MGE's implementation of FAS No. 133.
In September 2000, the FASB issued FAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a Replacement of FASB Statement No. 125." FAS No. 140 revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, but it carries over most of FAS No. 125's provisions without reconsideration. The standard provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. Those standards are based on consistent application of a financial-components approach that focuses on control. The standard is effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001, and should be applied prospectively. At Dec. 31, 2000, MGE did not anticipate entering into any transactions that would be subject to FAS No. 140.
INFLATION
The current financial statements report operating results in terms of historical cost, but they do not evaluate the impact of inflation. Since 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.
ENVIRONMENTAL ISSUES
On Jan. 1, 2000, Phase II of the 1990 Federal Clean Air Act amendments took effect, setting new emission limits for sulfur dioxides and NOx. MGE's generating 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 Oct. 27, 1998, the Environmental Protection Agency (EPA) issued final rules requiring more NOx emission reductions from utilities located in southern Wisconsin. However, a legal challenge resulted in excluding Wisconsin from this rule and returning the issue to the EPA on March 3, 2000, for further action. On Jan. 8, 2001, former EPA Administrator Carol Browner signed a proposed rule that would exclude Wisconsin (and MGE) from further NOx emission reductions required by the original rule. The proposed rule must still be finalized. If it is determined that Wisconsin is subject to the original rule, MGE will likely need to evaluate emission control options to bring the Blount plant into compliance. These controls would likely increase capital, operating and maintenance expenses.
On Dec. 14, 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 Dec. 15, 2003, and final regulations published no later than Dec. 15, 2004. The Wisconsin Department of Natural Resources (DNR) is also evaluating its rules to limit mercury emissions from coal-fired boilers. If either of these regulations are issued, they may require MGE to evaluate emission control options for its Blount facility in order to comply. These controls would likely increase capital, operating and maintenance expenses.
MGE is one of the first Wisconsin companies to participate in a voluntary Environmental Cooperation Program with the DNR. This gives MGE flexibility as it works with the DNR to maintain superior environmental performance at the Blount plant.
In December 2000, Columbia (in which MGE has an ownership interest) received a Request for Information from the EPA to evaluate compliance with the Clean Air Act. Alliant Energy, the plant operator, submitted a response to the EPA on approximately Jan. 15, 2001. Management does not believe this will have a significant impact on the financial statements.
MGE is listed as a potentially responsible party for two sites that the EPA has placed on the national priorities Superfund list: (1) the Refuse Hideaway Landfill in Middleton, Wis., where MGE disposed of fly ash sludge and general office waste from 1980 to 1984 and (2) the Lenz Oil site in Lemont, Ill., which was used for storing and processing waste oil for several years. These sites require clean up under the Comprehensive Environmental Response, Compensation and Liability Act. A group of companies is currently negotiating with the EPA on the cleanup of these two sites.
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 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 Dec. 31, 2000, MGE accrued a $250,000 liability on its balance sheet for this matter.
Item 7A
Item 7A - Qualitative and Quantitative Disclosures about Market Risk
Market Risks: MGE is potentially exposed to market risk associated with interest rates, commodity prices and equity returns. MGE currently has no exposure to foreign currency risk. MGE has risk management policies to monitor and assist in controlling these market risks and uses derivative instruments to manage some of the exposures.
Interest Rate Risk: MGE issues commercial paper at varying interest rates for its short-term borrowings (see Item 8, Notes Payable to Banks, Commercial Paper, and Lines of Credit). 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 retire 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 such debt matures and is refinanced at the then applicable rates.
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 Item 8, Fair Value of Financial Instruments). MGE's commodity risks are somewhat mitigated by the current ratemaking process in place for the recovery of electric fuel, purchased energy and the cost of natural gas purchased for resale. MGE's electric fuel costs are subject to fuel rules, 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, a refund to customers would be ordered.
MGE uses weather derivatives to reduce the impact of weather volatility on its margins related to gas operations. In February 2000, MGE purchased a nonexchange-traded heating degree day put option covering the periods of March 2000 and November 2000 through March 2001.
MGE has purchased put options to reduce the impact on customers of wintertime price declines on gas purchased and injected into storage during the summer and withdrawn during winter months. Under MGE's natural gas risk management program, the cost of the put options as well as the gains or losses realized will not affect net income as they are not subject to the GCIM and will be recovered in their entirety under the PGA.
Equity Price Risks: MGE currently funds its liabilities related to employee benefits and nuclear decommissioning through trust funds. These funds are managed by various investment managers and hold investments in debt and equity securities. 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 payment variations as a result of changes in the market value of the trust funds is mitigated in part through future rate actions by the PSCW.
Item 8
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 subsidiaries at December 31, 2000 and December 31, 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits 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 7, 2001
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per-share amounts)
For the years ended December 31
Operating Revenues
Electric $203,176 $185,955 $169,563
Gas 120,932
88,079
80,189
Total Operating Revenues
324,108
274,034
249,752
Operating Expenses
Fuel for electric generation 36,338 32,388 32,289
Purchased power 18,963 22,198 9,624
Natural gas purchased 77,482 49,395 45,458
Other operations 72,015 67,471 64,231
Maintenance 18,532 13,304 15,167
Depreciation and amortization 35,081 35,154 33,185
Other general taxes 10,180 9,306 9,263
Income tax provision 15,416
12,268
10,723
Total Operating Expenses
284,007
241,484
219,940
Net Operating Income 40,101 32,550 29,812
AFUDC - equity funds
Other income, net 1,040
2,933
3,151
Income Before Interest Expense
41,484
35,785
33,085
Interest Expense
Interest on long-term debt 12,622 11,500 10,234
Other interest 1,683
AFUDC - borrowed funds (176)
(155)
(66)
Net Interest Expense
14,129
12,039
10,855
Net Income $ 27,355
$ 23,746
$ 22,230
Earnings Per Share of Common Stock (basic and diluted) $1.67
$1.48
$1.38
Average Shares Outstanding (basic and diluted) 16,382
16,084
16,080
The accompanying notes are an integral part of the above statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the years ended December 31
Operating Activities
Net income $27,355 $23,746 $22,230
Items not affecting cash:
Depreciation and amortization
35,081 35,154 33,185
Deferred income taxes
(1,074) (708) (1,229)
Amortization of nuclear fuel
2,194 2,638 2,321
Amortization of investment tax credits
(727) (739) (747)
AFUDC - equity funds
(343) (302) (122)
Other items
(825) (1,430) (2,066)
Changes in working capital, excluding cash equivalents,sinking funds, maturities and short-term debt:
(Increase)/decrease in current assets
(27,019) (2,512) 3,577
Increase in current liabilities
12,911 3,354 1,283
Other noncurrent items, net
1,142
12,093
Cash Provided by Operating Activities
47,774
60,343
70,525
Investing Activities
Additions to utility plant and nuclear fuel (73,606) (50,988) (30,829)
AFUDC - borrowed funds (176) (155) (66)
Increase in nuclear decommissioning fund (11,059)
(10,692)
(9,910)
Cash Used for Investing Activities
(84,841)
(61,835)
(40,805)
Financing Activities
Issuance of common stock 8,964 1,678 -
Cash dividends on common stock (21,588) (21,038) (20,878)
Increase in long-term debt 35,000 - 30,000
Maturity/redemption of long-term debt (11,200) (200) (200)
Increase/(decrease) in short-term debt 28,250
15,750
(33,500)
Cash Provided by/(Used) for Financing Activities
39,426
(3,810)
(24,578)
Change in Cash and Cash Equivalents 2,359 (5,302) 5,142
Cash and cash equivalents at beginning of period 1,948
7,250
2,108
Cash and cash equivalents at end of period $ 4,307
$ 1,948
$ 7,250
The accompanying notes are an integral part of the above statements.
CONSOLIDATED BALANCE SHEETS
(In thousands)
At December 31
ASSETS
Utility Plant (at original cost, in service)
Electric $622,209 $554,392
Gas 197,093
190,137
Gross Plant in Service
819,302 744,529
Less accumulated provision for depreciation (510,381)
(484,428)
Net Plant in Service
308,921 260,101
Construction work in progress 22,863 31,134
Nuclear decommissioning fund 102,891 97,056
Nuclear fuel, net 6,979
6,534
Total Utility Plant
441,654
394,825
Other Property and Investments 3,988
3,591
Current Assets
Cash and cash equivalents 4,307 1,948
Accounts receivable, less reserves of $2,071 and $1,391, respectively 38,161 27,913
Unbilled revenue 27,900 13,167
Materials and supplies, at lower of average cost or market 7,735 6,149
Fossil fuel, at lower of average cost or market 3,872 4,061
Stored natural gas, at lower of average cost or market 9,785 10,039
Prepaid taxes 7,539 6,802
Other prepayments 1,221
1,063
Total Current Assets
100,520
71,142
Deferred Charges 25,442
25,952
Total Assets
$571,604
$495,510
CAPITALIZATION AND LIABILITIES
Capitalization (see statement) $383,749
$334,285
Current Liabilities
Long-term debt due within one year 11,200
Short-term debt - commercial paper 44,000 15,750
Accounts payable 28,792 19,553
Accrued taxes 2,550
Accrued interest 3,162 2,770
Accrued payroll-related items 4,968 4,064
Other 3,565
2,848
Total Current Liabilities
87,237
57,076
Other Credits
Deferred income taxes 43,321 42,981
Investment tax credit - deferred 8,472 9,199
Regulatory liability - FAS No. 109 21,532 22,875
Other regulatory liabilities 4,985 5,078
Other deferred liabilities 22,308
24,016
Total Other Credits
100,618
104,149
Total Liabilities
187,855
161,225
Total Capitalization and Liabilities
$571,604
$495,510
The accompanying notes are an integral part of the above statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(In thousands)
At December 31
Common Equity
Common stock - par value $1 per share:
Authorized 50,000,000 shares
Outstanding 16,618,729 and 16,161,305 shares, respectively
$ 16,619 $ 16,161
Additional paid-in capital 122,661 114,155
Retained earnings 62,112 56,345
Accumulated other comprehensive income/(loss) (1,080)
(975)
Total Common Shareholders' Equity
200,312
185,686
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 6,275
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
114,575 114,775
Unamortized discount and premium on bonds, net (938) (976)
Long-term debt sinking fund requirements (200)
(200)
Total First Mortgage Bonds
113,437 113,599
Other Long-Term Debt
Variable rate, due 2002 20,000 -
6.91%, due 2004 5,000 5,000
7.49%, due 2007 15,000 -
6.02%, due 2008 30,000
30,000
Total Long-Term Debt
183,437
148,599
Total Capitalization
$383,749
$334,285
The accompanying notes are an integral part of the above statements.
CONSOLIDATED STATEMENTS OF COMMON EQUITY
(In thousands, except per-share amounts)
Common Stock
Additional Paid-in Capital
Retained Earnings
Accumulated Other Comprehensive Income/(Loss)
Comprehensive Income
Beginning balance - Jan. 1, 1998 $16,080 $112,558 $ 52,285 $ - $ -
Net income - - 22,230 - 22,230
Other comprehensive
income/(loss)
-
-
-
-
-
Total comprehensive income
$22,230
Common stock dividends ($1.30 per share) -
-
(20,878)
-
Ending balance - Dec. 31, 1998 $16,080 $112,558 $ 53,637 $ -
Net income $ - $ - $ 23,746 $ - $23,746
Other comprehensive income/(loss):
Minimum pension liability
adjustment (net of $654 tax)
-
-
-
(975)
(975)
Total comprehensive income
$22,771
Common stock dividends ($1.31 per share) - - (21,038) -
Common stock issued
1,597
-
-
Ending balance - Dec. 31, 1999 $16,161 $114,155 $ 56,345 $ (975)
Net income $ - $ - $ 27,355 $ - $27,355
Other comprehensive income/(loss):
Minimum pension liability
adjustment (net of $70 tax)
-
-
-
(105)
(105)
Total comprehensive income
$27,250
Common stock dividends ($1.32 per share) - - (21,588) -
Common stock issued
8,506
-
-
Ending balance - Dec. 31, 2000 $16,619
$122,661
$ 62,112
$(1,080)
The accompanying notes are an integral part of the above statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Dec. 31, 2000, 1999, and 1998
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
a. General
Madison Gas and Electric Company (MGE) is an investor-owned public utility headquartered in Madison, Wis. MGE generates, transmits and distributes electricity to more than 126,000 customers in a 250-square-mile area of Dane County. MGE also transports and distributes natural gas to nearly 114,000 customers in 1,325 square miles of service territory in seven south-central counties in Wisconsin.
The consolidated financial statements reflect the application of certain accounting policies described in this note. Certain 1999 balances have been reclassified to conform to the 2000 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 the following: (1) reported amounts of assets and liabilities at the dates of the financial statements, (2) reported amounts of revenues and expenses during the reported periods and (3) disclosure of contingencies. Actual results could differ from management's estimates.
b. Revenues
Revenues are recorded based on services rendered or energy delivered to customers. MGE accrues a monthly estimate for unbilled revenue. Gas revenues are subject to an adjustment clause related to periodic changes in the cost of gas. In November 1999, MGE started operating under the new GCIM. Under the GCIM, if actual gas commodity costs are above or below a benchmark set by state regulators, MGE 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 plant.
These costs include a provision for estimated future disposal costs of spent nuclear fuel. MGE currently pays disposal fees to the 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 $1.6 million for its portion of the special assessment. MGE believes any additional costs will be recovered in future rates.
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: (1) borrowed funds is presented in the Consolidated Statements of Income as a reduction of interest expense and (2) 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.
e. Depreciation
Provisions at composite straight-line depreciation rates, excluding decommissioning costs, approximate the following percentages for the cost of depreciable property:
- Electric: 3.2% in 2000 and 3.6% in 1999 and 1998
- Gas: 3.4% in 2000, 1999 and 1998
Depreciation rates are approved by the PSCW and are generally based on the estimated economic lives of property.
Nuclear decommissioning costs are being accrued to an end-of-service life of 2002 for Kewaunee. These costs are currently recovered from customers in rates and are deposited in external trusts. For 2000, the decommissioning costs recovered in rates were $8.1 million.
Decommissioning costs are recovered through depreciation expense with a corresponding liability in accumulated depreciation. Net earnings on the trusts are included in other income. It is expected that the decommissioning contributions to the trusts, along with earnings on the trusts, will provide sufficient funds for decommissioning the plant. It is assumed the long-term, after-tax earnings on the assets held by the trusts are 5.6%.
As required by Statement of Financial Accounting Standards (FAS) 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 Dec. 31, 2000, the decommissioning trusts totaled $102.9 million, its pre-tax fair market value. Realized earnings on the trusts were $3.5 million, $3.1 million and $1.8 million for the years ended Dec. 31, 2000, 1999 and 1998, respectively. Unrealized earnings of the trusts totaled $28.0 million, $33.3 million and $26.0 million at Dec. 31, 2000, 1999 and 1998, respectively.
MGE's share of Kewaunee decommissioning costs is an estimated $93.1 million in current dollars based on a site-specific study performed in 1992 using immediate dismantlement as the method of decommissioning. This study assumed decommissioning costs would inflate at an average rate of 6.0% per year. MGE's decommissioning liability is limited to the current fund balances plus all decommissioning contributions through 2002. This is based on the agreement that allows MGE to sell its share of Kewaunee to WPSC. Physical decommissioning is expected to occur from 2014 through 2021. Additional expenses will likely be incurred from 2022 through 2039 to store spent nuclear fuel at the plant site.
f. Regulatory Matters
Pursuant to FAS 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.
Restructuring the electric industry could affect MGE's ability to continue establishing certain regulatory asset and liability amounts allowed under FAS 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 Dec. 31:
MGE contracted with WPSC to build an 83-MW natural gas-fired combustion turbine near Marinette, Wis. MGE received a return component on this asset in rate order Docket 3270-UR-109. The revenue for this asset was deferred until the unit came on-line in June 2000. This allowed MGE to match the revenues with the expenses. MGE recorded revenues of $2.5 million on this asset in 2000. The cost of the unit ($31.3 million) was added to MGE's utility plant balances in 2000.
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 for interest and income taxes for the years ended Dec. 31 were as follows:
(In thousands)
Interest paid, net of amount capitalized $13,822 $12,053 $10,227
Income taxes paid, net $16,078 $15,857 $14,188
Noncash investing items $ - $ 5,301 $ -
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.
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. New Accounting Pronouncements
In June 2000, the Financial Accounting Standards Board (FASB) issued FAS No. 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities, An Amendment of FAS No. 133." This standard includes several amendments to FAS No. 133 and is effective for fiscal years beginning after June 15, 2000. MGE adopted FAS No. 133 and FAS No. 138 as of Jan. 1, 2001.
The new standard requires that all derivative instruments be reported on the balance sheet at their fair values. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. It also requires MGE to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. For derivative instruments classified as fair-value hedges, the changes in the fair value of the derivative instrument will be offset on the income statement by the changes in the fair value of the hedged item. For derivative instruments classified as cash-value hedges, the effective portion of the hedge is reported in other comprehensive income until it is cleared to earnings. The ineffective portion of all hedges would be recognized through current earnings. For derivative instruments not classified as a hedge, the change in the fair value of the derivative will be recorded each period in current earnings.
MGE adopted FAS No. 133 on Jan. 1, 2001. There was no material effect on net income from adopting this new standard or making the transition adjustment.
The determination of the impact of FAS No. 133 is based on current interpretations of this statement, including interpretations of the Derivatives Implementation Group of the FASB. Final guidance, when issued, may affect MGE's implementation of FAS No. 133.
In September 2000, the FASB issued FAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a Replacement of FASB Statement No. 125." FAS No. 140 revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, but it carries over most of FAS No. 125's provisions without reconsideration. The standard provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. Those standards are based on consistent application of a financial-components approach that focuses on control. The standard is effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001, and should be applied prospectively. At Dec. 31, 2000, MGE did not anticipate entering into any transactions that would be subject to FAS No. 140.
2. JOINT PLANT OWNERSHIP
MGE and two other utilities jointly own two electric generating facilities, which account for 54.0% of MGE's net generating capability, 325 MW. Power from these facilities is shared in proportion to each company's ownership interest. MGE owns:
-22.0% (232 MW) of the coal-fired Columbia, which is operated by Alliant Energy Corp.
-17.8% (93 MW) of Kewaunee, which is operated by WPSC.
On Sept. 29, 1998, MGE finalized an agreement to sell its share of Kewaunee to WPSC. MGE is expected to transfer its ownership interest in Kewaunee in the fall of 2001. MGE will receive a cash payment from WPSC for Kewaunee upon closing (date plant shuts down for steam generator replacement). The payment will be comprised of MGE's share of Kewaunee's book value (currently $8.9 million) plus the book value of other assets related to Kewaunee. MGE's decommissioning liability will be limited to the current value of the trust assets balance until the sale closes, plus all decommissioning collections through 2002. MGE believes it can secure electric capacity and energy more cost-effectively from other sources and eliminate the risk of future stranded costs. This agreement, approved by state regulators in 2000, will close when the plant shuts down for steam generator replacement. The work, which will take approximately 60 days, is scheduled for fall 2001.
Each owner provides its own financing and reflects its respective portion of facilities and operating costs in its financial statements. MGE's interest in these facilities, included in its gross utility plant in service, and the related accumulated depreciation reserves at Dec. 31 were as follows:
3. INCOME TAXES
Total income taxes in the Consolidated Statements of Income are as follows:
(In thousands)
Income taxes charged to operations $15,416 $12,268 $10,723
Income taxes charged to other income
1,608
2,384
Total income taxes $15,752
$13,876
$13,107
Total income taxes consist of the following provision (benefit) components for the years ended Dec. 31:
(In thousands)
Currently payable:
Federal $14,280 $11,772 $11,832
State 3,273 3,551 3,251
Net-deferred:
Federal (878) (476) (1,092)
State (196) (232) (137)
Amortized investment tax credits (727)
(739)
(747)
Total income taxes $15,752
$13,876
$13,107
Deferred income taxes are provided to reflect the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not. A valuation allowance is recorded for those benefits which do not meet the more-likely-than-not criterion. Investment tax credits from regulated operations are amortized over related property service lives.
The differences between the federal statutory income tax rate and MGE's effective rate are as follows:
Statutory federal income tax rate
35.0%
35.0%
35.0%
Amortized investment tax credits
(1.7)
(2.0)
(2.1)
State income taxes, net of federal benefit
5.0
5.7
5.7
Valuation allowance
(1.1)
(0.3)
(0.4)
Renewable electricity production credit
(0.9)
(0.5)
-
Other, individually insignificant
0.2
(1.0)
(1.1)
Effective Income Tax Rate
36.5%
36.9%
37.1%
The significant components of deferred tax liabilities (assets) that appear on the Consolidated Balance Sheets as of Dec. 31 are as follows:
(In thousands)
Property-related $57,564 $56,869
Bond transactions 1,720 1,803
Energy conservation 1,030 1,757
Pension expense 2,282 1,598
Other 1,002
Gross deferred income tax liabilities
63,598
62,583
Accrued expenses (4,513) (3,836)
Retirement benefits, other than pension (2,107) (1,929)
Other (1,986) (1,813)
Deferred tax regulatory account (12,042)
(12,873)
Gross deferred income tax assets
(20,648) (20,451)
Less valuation allowance
Net deferred income tax assets
(20,277)
(19,602)
Deferred income taxes
$43,321
$42,981
The valuation allowance reduces MGE's deferred tax assets to estimated realizable value. The deferred tax assets for which a valuation allowance is necessary arise primarily from state tax carryforward losses. In 2000, MGE reduced the valuation allowance applied against these state tax carryforward losses based upon management's estimate that, more likely than not, these deferred tax assets will be realized. The remaining valuation allowance at Dec. 31, 2000, is necessary due to the uncertainty of future income estimates.
For tax purposes, as of Dec. 31, 2000, MGE had approximately $14.0 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 regulatory liability--FAS No. 109 associated with these excess deferred income taxes and investment tax credit--deferred was $21.5 million and $22.9 million at Dec. 31, 2000 and 1999, respectively.
4. PENSION PLANS
MGE maintains qualified and nonqualified pension plans. MGE also provides health care and life insurance benefits for its retired employees. The table on page II-27 provides a reconciliation of benefit obligations, plan assets and funded status of the plans.
The funded status information reported on page II-27 includes a nonqualified pension plan and a postretirement 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 $7.6 million, $7.2 million and $0, respectively, at Dec. 31, 2000, and $6.9 million, $6.6 million and $0, respectively, at Dec. 31, 1999. Similarly, the accumulated benefit obligation and fair value of assets for a postretirement plan were $18.3 million and $7.0 million at Dec. 31, 2000, and $15.6 million and $6.4 million at Dec. 31, 1999.
MGE has elected to recognize the cost of its transition obligation (the accumulated postretirement benefit obligation as of Jan. 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 2000, $0.5 million in 1999 and $0.5 million in 1998.
Sensitivity of retiree welfare results: The assumed health care cost percentage was 7.0% as of Dec. 31, 2000. Assumed health care trend rates, which have a significant effect on the amounts reported for health care plans, have been declining as shown in the table on page II-28. The following table shows how an assumed 1% increase or 1% decrease in health care cost trends could impact postretirement benefits in 2000 dollars.
(In thousands)
1% Increase
1%
D ecrease
Effect on:
Total service and interest cost components
$ 369 $ (294)
Postretirement benefit obligation
$3,103 $(2,513)
MGE reports comprehensive income in accordance with FAS 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.
5. FAIR VALUE OF FINANCIAL INSTRUMENTS
At Dec. 31, 2000 and 1999, 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 trusts are 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 Dec. 31. The estimated fair market value of MGE's financial instruments are as follows:
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 interest rate swap agreements with commercial banks totaling $5.0 million for 2000 and $16.0 million for 1999, with effective interest rates of 6.3% and 5.1%, respectively. These agreements have a fixed rate and are backed by MGE's commercial paper. MGE believes counterparties to the agreements will meet their obligations based on their high credit ratings.
In February 2000, MGE entered into a nonexchange-traded heating degree day (HDD) put option covering March 2000 and November 2000 through March 2001. 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 these weather derivatives in accordance with EITF 99-2, "Accounting for Weather Derivatives," which uses the intrinsic value method.
The premium cost is amortized over the expected HDD of the contract and any gains or losses are recorded in other income. Nonperformance of counterparties to these weather 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 counterparty default. No gain or loss has been recognized on this weather derivative.
MGE purchased nonexchange-traded financial put options to reduce the impact on customers if winter gas prices drop below the price MGE paid for its gas in storage. MGE typically injects gas into storage in the summer and draws it out during the winter months. The put options have contract terms of January and February 2001. Under MGE's natural gas risk management program approved by the PSCW, the cost of these put options (as well as the gains or losses realized) will be recovered under the PGA and will not affect net income. These financial put options had no fair market value at Dec. 31, 2000.
6. CAPITALIZATION MATTERS
a. Common Stock
Beginning in December 1999, MGE switched from buying shares on the open market to issuing new shares for its Dividend Reinvestment and Direct Stock Purchase Plan (Plan). Issuing new shares, rather than buying shares on the open market, helps improve cash flow and strengthen MGE's capital structure.
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.
In 1999, a total of 81,000 new shares of common stock were issued under the Plan. The proceeds were allocated to common stock and amounts received in excess of par value.
b. Preferred Stock
MGE has authorized but not issued 1,175,000 shares of $25 par value redeemable preferred stock, cumulative, at Dec. 31, 2000 and 1999.
c. First Mortgage Bonds and Other Long-Term Debt
MGE's utility plant is subject to the lien of its First Mortgage Bonds.
On May 4, 2000, MGE issued $20.0 million of unsecured, variable-rate Medium-Term Notes (MTN) maturing on May 3, 2002. Interest on these notes will be paid quarterly on the third Wednesday of March, June, September and December. The variable rate, based on the three-month London Interbank Offering Rate (LIBOR) plus 13.0 basis points, was 6.67% as of Dec. 31, 2000. The proceeds were used to finance the 83-MW natural gas-fired combustion turbine that MGE purchased from WPSC.
On Sept. 20, 2000, MGE issued $15.0 million of unsecured MTN at a rate of 7.49%. Interest on these notes will be paid semiannually on March 1 and Sept. 1 until the notes mature on Sept. 20, 2007. The proceeds were used to retire the $11.0 million, 6.01% debt issue that matured in November.
Long-term debt maturities, including mandatory sinking fund requirements relating to the 6-1/2%, 2006 Series, First Mortgage Bonds are:
(In thousands)
Amount
Debt Issue
$ 200
-
20,200
VAR%, MTN
-
6,000
6.91%, SWAP
2,000
-
d. Notes Payable to Banks, Commercial Paper and Lines of Credit
For short-term borrowings, MGE generally issues commercial paper (at the prevailing discount rate when issued) that is supported by unused bank lines of credit. Through negotiations with several banks, MGE has $55.0 million in bank lines of credit.
Information concerning short-term borrowings for the past three years is shown below:
(In thousands)
As of December 31:
Available lines of credit
$55,000 $40,000 $45,000
Commercial paper outstanding
$44,000 $15,750 $ -
Weighted-average interest rate
6.73% 6.44% 0.00%
During the year:
Maximum short-term borrowings
$44,000 $15,750 $33,500
Average short-term borrowings
$17,117 $ 1,899 $ 9,223
Weighted-average interest rate
6.07% 5.68% 5.70%
7. RATE MATTERS
In January 2001, the PSCW authorized: (1) an electric rate increase of $7.5 million, or 3.9%, to cover rising fuel costs and increased system demands, (2) a natural gas rate increase of $3.4 million, or 2.7%, for improving the gas delivery system and (3) a return on common stock equity of 12.9%. MGE's next rate case period is expected to begin Jan. 1, 2003. MGE has a limited reopener in its current rate case to reflect items that may significantly impact rates for 2002. MGE's reopener will reflect the full-year impact of the disposition of Kewaunee and also address implementing a proposed automated meter reading system.
MGE contracted with WPSC to build and operate an 83-MW natural gas-fired combustion turbine near Marinette, Wis. 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.
In January 1999, the PSCW authorized an electric rate increase of $8.4 million, or 5.1%, and a natural gas rate increase of $0.7 million, or 0.7%. These rates were based on a 12.2% authorized return on common stock equity.
In August 1999, the PSCW approved a temporary retail electric rate surcharge of 3.6%, on average. This surcharge, which ended Dec. 31, 1999, covered higher fuel and purchased power costs caused by extended outages at the Columbia plant, which MGE owns jointly with Alliant Energy and WPSC.
8. GAS MARKETING SUBSIDIARIES
After selling its interest in a gas marketing joint venture in December 1998, MGE favorably resolved various contingencies in 2000 and 1999, including: warranty claims, accounts payable, and legal and tax issues related to its former investment. The after-tax benefit was approximately $0.3 million and $1.0 million in 2000 and 1999, respectively.
9. COMMITMENTS
Coal Contracts: MGE has no coal contracts that contain demand obligations for Blount. Fuel procurement for MGE's jointly owned Columbia plant is handled by Alliant Energy, 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 Dec. 31, 2000, MGE's total commitments for energy and purchased power contracts for capacity are estimated to be $6.3 million in 2001, $10.9 million in 2002, $14.7 million in 2003 and $11.0 million in 2004 and 2005. Management expects to recover these costs in future customer rates.
In March 1999, MGE entered into an agreement with Commonwealth Edison to purchase 60 MW of firm capacity and energy for approximately $10.2 million (which includes about $0.5 million for securing firm transmission to deliver firm capacity and energy to MGE's system). In March 1999, MGE also agreed to sell 30 MW of the 60 MW to Wisconsin Public Power, Inc., for approximately $4.8 million, plus any applicable taxes.
Purchased Gas Contracts: MGE has natural gas transportation contracts that provide for the availability of firm pipeline 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 Federal Energy Regulatory Commission (FERC). These payments are estimated to be: $16.2 million in 2001, $14.2 million in 2002, $12.6 million in 2003, $11.8 million in 2004 and $9.8 million in 2005. Management expects to recover these costs in future customer rates.
Environmental: On Jan. 1, 2000, Phase II of the 1990 Federal Clean Air Act amendments took effect, setting new emission limits for sulfur dioxides and NOx. MGE's generating 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 Oct. 27, 1998, the EPA issued final rules requiring more NOx emission reductions from utilities located in southern Wisconsin. However, a legal challenge resulted in excluding Wisconsin from this rule and returning the issue to the EPA on March 3, 2000, for further action.
On Jan. 8, 2001, former EPA Administrator Carol Browner signed a proposed rule that would exclude Wisconsin (and MGE) from further NOx emission reductions required by the original rule. The proposed rule must still be finalized. If it is determined Wisconsin is subject to the original rule, MGE will likely need to evaluate emission control options to bring the Blount plant into compliance. These controls would likely increase capital, operating and maintenance expenses.
On Dec. 14, 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 Dec. 15, 2003, and final regulations published no later than Dec. 15, 2004. The DNR is also evaluating its rules to limit mercury emissions from coal-fired boilers. If either of these regulations are issued, they may require MGE to evaluate emission control options for its Blount facility in order to comply. These controls would likely increase capital, operating and maintenance expenses.
MGE is one of the first Wisconsin companies to participate in a voluntary Environmental Cooperation Program with the DNR. This gives MGE flexibility as it works with the DNR to maintain superior environmental performance at the Blount plant.
In December 2000, Columbia (in which MGE has an ownership interest) received a Request for Information from the EPA to evaluate compliance with the Clean Air Act. Alliant Energy, the plant operator, submitted a response to the EPA on approximately Jan. 15, 2001. Management does not believe this will have a significant impact on the financial statements.
MGE is listed as a potentially responsible party for two sites that the EPA has placed on the national priorities Superfund list: (1) the Refuse Hideaway Landfill in Middleton, Wis., where MGE disposed of fly ash sludge and general office waste from 1980 to 1984 and (2) the Lenz Oil site in Lemont, Ill., which was used for storing and processing waste oil for several years. These sites require clean up under the Comprehensive Environmental Response, Compensation and Liability Act. A group of companies is currently negotiating with the EPA on the cleanup of these two sites.
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 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 Dec. 31, 2000, MGE accrued a $250,000 liability on its balance sheet for this matter.
10. AMERICAN TRANSMISSION COMPANY LLC (ATC)
Based on a commitment made in June 2000, MGE transferred to ATC on Jan. 1, 2001, its electric transmission facilities with a net book value of $43.6 million. ATC is a joint venture authorized by Reliability 2000 legislation in Wisconsin (1999 Wis. Act 9) to independently own and operate the transmission system in Wisconsin. ATC provides equal and fair access to Wisconsin's transmission system to all joint-venture partners. All of Wisconsin's investor-owned utilities have contributed their transmission facilities to ATC. In addition, several Wisconsin municipal utilities, retail electric cooperatives and power supply agencies are participating by contributing cash and/or transferring transmission assets.
In exchange for its transmission plant and related regulatory deferred taxes and deferred investment tax credits, MGE received an approximate 6.0% interest in ATC. In 2001, each member of the ATC will be subject to an independent audit of its contributed transmission assets in order to finalize initial ownership interests.
MGE will account for its investment in ATC on the equity method of accounting.
ATC is regulated by the FERC. MGE expects to receive a return on its investment in ATC approximately equal to the return it would have earned by retaining its transmission facilities.
In 2001, MGE started paying a network service fee for using the ATC transmission system. MGE's transmission assets 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 the ATC will be deferred subject to regulatory treatment.
11. SEGMENTS OF BUSINESS
MGE has two main business segments, electric and gas, which are both regulated. The electric business generates, transmits and distributes electricity. The gas business transports and distributes natural gas. The following table shows key information about MGE's electric and gas operations, including the distribution of net assets for the years ended Dec. 31.
(In thousands)
Electric Operations
Total revenues $203,176 $185,955 $169,563
Operation and maintenance expenses 124,101 115,204 102,006
Depreciation and amortization 29,137 29,319 27,586
Other general taxes 8,296
7,622
7,378
Pre-tax operating income
$ 41,642 $ 33,810 $ 32,593
Income tax provision 11,534
9,599
8,883
Net Operating Income
$ 30,108
$ 24,211
$ 23,710
Electric Construction and Nuclear Fuel Expenditures
$ 65,312
$ 44,297
$ 25,970
Gas Operations
Operating revenues $120,932 $ 88,079 $ 80,189
Revenues from sales to electric utility 6,106
7,352
6,362
Total revenues
127,038 95,431 86,551
Operation and maintenance expenses 105,335 76,904 71,125
Depreciation and amortization 5,944 5,835 5,599
Other general taxes 1,884
1,684
1,885
Pre-tax operating income
13,875 11,008 7,942
Income tax provision 3,882
2,669
1,840
Net Operating Income
$ 9,993
$ 8,339
$ 6,102
Gas Construction Expenditures $ 8,294
$ 6,691
$ 4,859
Assets (year-end)
Electric $395,622 $342,130 $311,563
Gas 123,486 114,881 111,762
Assets not allocated 52,496
38,499
42,940
Total
$571,604
$495,510
$466,265
12. QUARTERLY SUMMARY OF OPERATIONS (unaudited)
(In thousands, except per-share amounts)
Notes:
(1)The quarterly results of operations within a year are not comparable because of seasonal and other factors.
(2)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.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III.
Item 10
Item 10 - Directors and Executive Officers of the Registrant
Information concerning the Directors of the Company is contained in the definitive proxy statement under the section "Election of Directors" filed prior to April 30, 2001, 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
David C. Mebane
Age: 67
Chairman of the Board
Chairman, President & CEO 02/01/00
05/09/94
Gary J. Wolter
Age: 46
President & Chief Executive Officer
Senior Vice President - Administration & Secretary
02/01/00
05/01/95
Mark C. Williamson
Age: 47
Executive Vice President & Chief Strategic Officer
Senior Vice President - Energy Services
02/01/00
05/01/95
Ronald L. Semmann
Age: 65
Executive Vice President
Group Vice President
Vice President - Human Resources
Special Assistant to the Chairman
02/01/00
01/01/98
07/18/97
05/12/97
Lynn K. Hobbie
Age: 42
Senior Vice President
Vice President - Marketing
02/01/00
05/01/96
Thomas R. Krull
Age: 51
Group Vice President
Vice President - Gas & Electric Operations
Vice President - Electric Transmission & Distribution
02/01/00
11/01/97
05/01/96
James G. Bidlingmaier
Age: 54
Vice President - Admin. & Chief Information Officer
02/01/00
-
Mark A. Frankel
Age: 52
Vice President, General Counsel & Secretary
Vice President & General Counsel
02/01/00
08/23/99
-
Terry A. Hanson
Age: 49
Vice President and Chief Financial Officer
Vice President - Finance
Vice President & Treasurer
05/01/00
11/01/97
10/01/96
Scott A. Neitzel
Age: 40
Vice President - Business Development & Fuels
Vice President - Gas Rates & Fuels
Assistant Vice President - Gas Rates & Fuels
09/22/00
02/01/00
08/04/97
Jeffrey C. Newman
Age: 38
Vice President and Treasurer
Treasurer
Exec. Director - Budgets & Financial Management
01/01/01
11/01/97
05/01/96
Peter J. Waldron
Age: 43
Vice President - Power Supply
Vice President - Power Supply Ops. & Eng.
Asst. Vice President - Power Supply Ops. & Eng.
Executive Director - Power Supply Ops. & Eng.
04/24/98
04/23/97
05/01/96
10/01/95
Note: Ages, years of service and positions as of Jan. 1, 2001.
Item 11
Item 11 - Executive Compensation
See Item 12
Item 12 - Security Ownership of Certain Beneficial Owners And Management
The required information for Items 11 and 12 is included in the Company's definitive proxy statement under the section "Executive Compensation," not including "Report on Executive Compensation" and "Company Performance," and under the section "Beneficial Ownership of Common Stock by Directors and Executive Officers" filed with the Securities and Exchange Commission prior to April 30, 2001, which is incorporated herein by reference.
Item 13
Item 13 - Certain Relationships and Related Transactions
None.
PART IV.
Item 14
Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Index
(a)1. Financial Statements
- Report of Independent Accountants
- Consolidated Statements of Income for the years ended Dec. 31, 2000, 1999 and 1998
- Consolidated Statements of Cash Flows for the years ended Dec. 31, 2000, 1999 and 1998
- Consolidated Balance Sheets as of Dec. 31, 2000 and 1999
- Consolidated Statements of Capitalization as of Dec. 31, 2000 and 1999
- Consolidated Statements of Common Equity as of Dec. 31, 2000, 1999 and 1998
- Notes to Consolidated Financial Statements
2. Financial Statement Schedules
None.
3. All Exhibits Including Those Incorporated by Reference
Exhibits (an asterisk (*) indicates a management contract or compensatory plan or arrangement):
No. Description of document
3.(i) - Articles of Incorporation as in effect at May 6, 1996. (Incorporated by reference to Exhibit 3.(i) with 1996 Form 10-K in File No. 0-1125.)
3.(ii) - By-Laws as in effect at May 4, 1999. (Incorporated by reference to Exhibit 3.(ii) with 1999 Form 10-K in File No. 0-1125.)
4A - Indenture of Mortgage and Deed of Trust between MGE and Firstar Trust Co., as Trustee, dated as of Jan. 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.
Tenth 11/01/76 2.03 2-60227
Fourteenth 04/01/92 4C 0-1125 (1992 10-K)
Fifteenth 04/01/92 4D 0-1125 (1992 10-K)
Sixteenth 10/01/92 4E 0-1125 (1992 10-K)
Seventeenth 02/01/93 4F 0-1125 (1992 10-K)
4B - Indenture between the Company and Bank One, N.A., as Trustee, dated as of Sept. 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 Co. and Wisconsin Public Service Corp. dated Feb. 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 Co. 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 Co. 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 Dec. 31, 2000.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MADISON GAS AND ELECTRIC COMPANY
(Registrant)
Date: March 30, 2001 /s/ Gary J. Wolter
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 30, 2001.
/s/ Gary J. Wolter President and Chief Executive Officer and Director (Principal Executive Officer)
/s/ Terry A. Hanson Vice President and Chief Financial Officer (Principal Financial Officer
and Principal Accounting Officer)
/s/ David C. Mebane Chairman of the Board and Director
/s/ Jean M. Biddick 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
Donna K. Sollenberger Director
H. Lee Swanson Director