MADISON GAS & ELECTRIC CO, 10-K405, 1998-03-31

MADISON GAS & ELECTRIC CO
10-K405, 1998-03-31
ELECTRIC & OTHER SERVICES COMBINED

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

(Mark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 1997

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from: _________ to _________

Commission File Number 0-1125

MADISON GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)

WISCONSIN
(State or other jurisdiction of incorporation or organization)

39-0444025
(IRS Employer Identification No.)

133 South Blair Street
Post Office Box 1231
Madison, Wisconsin 53701-1231
(Address of principal executive offices, including ZIP code)

(608) 252-7000
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
Common, Par Value $1 Per Share
(Title of Class)

Indicate by check mark whether the Registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No

Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of Registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. Yes X No

State the aggregate market value of the voting stock held by
nonaffiliates of the Registrant: $359,783,690 based on a closing
bid price of $22.375 on
March 1, 1998 (the record date for the Annual Meeting of
Shareholders).

The number of shares outstanding of each of the issuer's classes
of common stock, as of the close of the period covered by this
report, was 16,079,718 of Common Stock, Par Value $1 Per Share.

List hereunder the following documents if incorporated by
reference and the part of the Form 10-K (e.g., Part I, Part II,
etc.) into which the document is incorporated: (1) Any annual
report to security holders; (2) Any proxy or information
statement; and (3) Any prospectus filed pursuant to Rule 424(b)
or (c) under the Securities Act of 1933.

- - 1997 Annual Report to Shareholders (Parts I, II, and IV)

- - Definitive Proxy Statement filed on March 23, 1998 (Parts I
and III) <PAGE>
PART I.

Item 1. Business

General Description of Business

The registrant, Madison Gas and Electric Company (the Company), a
Wisconsin corporation organized as such in 1896, is a public
utility engaged in the generation and transmission of electric
energy and in its distribution in Madison and its environs (250
square miles) and in the purchase, transportation, and
distribution of natural gas in Columbia, Crawford, Dane, Iowa,
Juneau, Monroe, and Vernon counties, Wisconsin (1,325 square
miles). Exhibit No. 21 herein provides a description of the
Company's wholly owned subsidiaries.

In January 1997, the Company's two gas marketing subsidiaries,
Great Lakes Energy Corp. (GLENCO) and American Energy Management,
Inc. (AEM), formed a joint venture with another gas marketing
company. The joint venture will market natural gas and energy
services to industrial and commercial customers in the Great
Lakes region. The joint venture is called National Energy
Management, L.L.C. and is based in Chicago. (See Item 7,
page II-6, and Item 8, page F-17, for further discussion.)

The Company is subject to regulation by the Public Service
Commission of Wisconsin (PSCW) as to rates, accounts, issuance of
securities, plant and transmission line siting, and in other
respects. The Federal Energy Regulatory Commission (FERC) has
jurisdiction, under the Federal Power Act, over certain
accounting practices of the Company and in certain other
respects. The Nuclear Regulatory Commission (NRC) has
jurisdiction over the operation of the Kewaunee Nuclear Power
Plant (Kewaunee). The Company has a 17.8 percent ownership
interest in Kewaunee. The other owners are Wisconsin Public
Service Corporation (WPSC), which operates Kewaunee, and
Wisconsin Power and Light Company (WPL).

The Company is also subject to regulation with regard to air
quality, water quality, and solid waste (see I-6 and I-7) and may
be subject to regulation with regard to other environmental
matters by various federal, state, and local authorities
including the Wisconsin Department of Natural Resources (DNR),
which has jurisdiction over air and water quality, solid and
hazardous waste standards, and which regulates the electric
generating operations of the Company with respect to pollution
and environmental control matters. The Company has met the
requirements of current environmental regulations. Unknown
additional expenditures may be required for pollution control
equipment and for the modification of existing plants to comply
with future unknown environmental regulations.

For example, the ongoing issue of global warming could result in
significant compliance cost for carbon dioxide emission
reductions. Except as set forth below, the amounts of such
expenditures and the period of time over which they may be
required to be made are not known. The Company is unable to
predict whether compliance with future pollution control
regulations would involve curtailments of operations or
reductions in generating capacity or efficiency of present
generating facilities or delays in the construction and operation
of future generating facilities.

Under both the National Environmental Policy Act and the
Wisconsin Environmental Policy Act, the Company must obtain the
necessary authorizations or permits from regulatory agencies for
any new projects or other major actions significantly affecting
the quality of the human environment after all aspects of the
proposed project or action are subjected to a complete
environmental review and a detailed environmental impact
statement is issued.

Electric Operations

At December 31, 1997, the Company supplied electric service to
122,843 customers, of whom 109,658 were located in the cities of
Fitchburg, Madison, Middleton, and Monona, and 13,185 in adjacent
areas. Of the total number of customers, 106,349 were residential
and 16,357 were commercial. For 1997, residential and commercial
electric service revenues comprised 35 and 49 percent,
respectively, of total electric revenues. The remaining electric
revenues during 1997 were from industrial sales (7 percent),
sales to public authorities including the University of Wisconsin
(9 percent), and sales to other utilities (1 percent). The
electric operations accounted for 62 percent of the total
revenues of the Company.

See Item 2 for a description of the Company's electric utility
plant.

The Company is a member of Mid-America Interconnected Network,
Inc. (MAIN), a regional reliability group. Membership in this
group permits better utilization of reserve generating capacity
and coordination of long-range system planning and day-to-day
operations. MAIN seeks to maintain adequate planning generation
reserve margins as a group in the range of 15 to 22 percent. The
Company is also a member of the Midcontinent Area Power Pool
(MAPP) Regional Transmission Committee (RTC). The RTC members
pool their transmission systems together allowing each member to
easily utilize the combined system to access economical energy
across the Upper Midwest. Each member is then compensated for the
energy flows on their individual transmission system.

In February 1996, the PSCW submitted a report to the State
Legislature on electric utility restructuring in Wisconsin.
Included in the report was a 32-step work plan and time line
summarizing expected restructuring activities. During the summer
of 1997, Wisconsin and Illinois experienced electric supply
shortages due to outages of a number of nuclear plants in
Illinois and Wisconsin, including Kewaunee. The electric
reliability crisis caused the PSCW to revise its previous plans
for restructuring the electric industry. In October 1997, the
PSCW stated that retail competition cannot occur until all the
safeguards are in place to protect consumers. Also, prior to any
significant restructuring, reliability concerns must be
addressed. This conclusion was consistent with plans proposed by
the Company and a broad coalition of customers. (See Item 7,
page II-9, Electric Industry Trend for further discussion.)

Fuel supply and generation

The Company estimates its net kilowatt-hour requirements for 1998
will be provided from the following sources: 68 percent from
fossil-fueled steam plants, 21 percent from a nuclear-fueled
steam plant, 10 percent from low-cost power purchases, and
1 percent from a combination of natural gas- and oil-fired
combustion turbines.

The Company has a 22 percent ownership interest in the Columbia
Energy Center (Columbia). The other owners are WPL, which
operates Columbia, and WPSC. The first (Columbia I) and second
(Columbia II) units at Columbia were placed in commercial
operation in 1975 and 1978, respectively. The Columbia co-owners'
coal inventory supply for Columbia I and Columbia II increased
from 30 days on December 31, 1996, to 55 days on December 31,
1997, due to: (1) the lower-than-normal inventory levels at the
end of 1996; (2) the cooler-than-normal summer in 1997; and (3)
the warmer-than-normal temperatures in November and December
1997. The co-owners' goal is to maintain approximately a 40-day
inventory. Columbia, with two 527-megawatt units, uses coal from
the Wyoming-Montana coal fields. One hundred percent (100%) of
the low-sulfur coal supply for these units comes from Powder
River Basin sources in Montana and Wyoming.

About 200 megawatts of the Company's electric generating capacity
is provided by the Blount Generating Station (Blount) (see I-10).
The Company is able to burn a variety of coals, natural gas, and
other fuels such as paper-derived fuel at Blount.

The Kewaunee plant, a 562-megawatt pressurized water reactor
plant, began commercial operation in 1974. The Kewaunee operating
license expires in 2013.

Kewaunee returned to service on June 12, 1997, after having been
out of service since September 21, 1996, for refueling, routine
maintenance, and repair of the two steam generators. The Kewaunee
steam generator tubes sustained damage as a result of repairs
performed on the tubes in 1988 through 1991. Tubes were repaired
by inserting sleeves (tubes within tubes) in the original steam
generator tubes. The most recent repair was undertaken when
cracking was discovered in previously repaired tubes. The repair
consisted of removing old sleeves and inserting new slightly
longer sleeves which cover the areas of concern in the original
steam generator tubes. The new sleeves will be inspected during
the next refueling and maintenance outage, which is scheduled for
the fall of 1998. Kewaunee is operating at 97 percent of rated
capacity because certain steam generator tubes have been removed
from service rather than repaired.

Kewaunee operated for 238 consecutive days before being removed
from service on February 6, 1998, for repair of a reactor coolant
pump seal. The plant was returned to service on February 13,
1998.

Additional replacement power costs in the amount of about $1.0
million per month due to the extended Kewaunee outage were
recovered through a customer surcharge during the period March 6,
1997, through July 1, 1997.

The co-owners of Kewaunee filed an application with the PSCW in
November 1997 for a customer surcharge to recover costs
associated with the 1997 steam generator repairs. The Company's
portion of these costs is approximately $1.8 million (excluding
carrying costs). The Company requested recovery of these costs
through a customer surcharge which would be collected over a
four-month period in 1998. The PSCW approved, at its open meeting
on March 19, 1998, the Company's request for a customer surcharge
relating to recovery of 1997 steam generator repair costs.

Public hearings were held in January 1998 regarding the
application filed with the PSCW requesting replacement of the
steam generators at Kewaunee. A decision by the PSCW is expected
in late March or early April. The Company opposes replacement of
the steam generators at Kewaunee. Replacement of steam generators
must be approved by the PSCW and is estimated to cost
$89.0 million (the Company's share would be 17.8 percent or
$15.8 million), excluding additional replacement purchased power
costs associated with an extended shutdown.

The NRC's Systematic Assessment of Licensee Performance for
Kewaunee for the period February 19, 1995, through February 15,
1997, was received in 1997. The report evaluated Kewaunee's
performance in four categories: operations, maintenance,
engineering, and plant support. Maintenance was ranked
"superior," and the other areas were rated as "good." The NRC
stated that Kewaunee's overall performance was generally
characterized by effective management involvement and
interdepartmental communication and a clear emphasis on quality
by the staff. Areas for improvement that were identified were:
timely evaluation of errors by personnel, adequacy of procedures
and equipment for monitoring equipment performance, and the
timely resolution of plant-identified deficiencies.

On July 14, 1997, the NRC assessed a $50,000 penalty against
Kewaunee. The penalty was the result of an NRC inspection in
January 1997 where the NRC questioned the procedures and
equipment used to conduct routine operational tests on several
pumps. In response, the procedures were updated to improve the
test methods and more sensitive equipment was obtained. All
safety-related pumps in the plant were then retested and found to
be operating within standards.

The federal government has the responsibility to dispose of or
permanently store spent nuclear fuel. Spent nuclear fuel is
currently being stored at Kewaunee. With minor plant
modifications, Kewaunee should have sufficient fuel storage
capacity until the end of its licensed life in 2013. Legislation
is being considered on the federal level to provide for the
establishment of an interim storage facility as early as 2002.
Permanent storage pursuant to the Nuclear Waste Policy Act of
1982 (Nuclear Policy Act) is discussed below.

The Midwest Compact Commission on June 26, 1997, halted
development in Ohio of a six-state, regional disposal facility
for low-level radioactive waste. The Commission cited dwindling
regional waste volumes, continued access to existing disposal
facilities, and potentially high development costs as the primary
reasons for the decision. A site at Barnwell, South Carolina,
continues to be available for the storage of low-level
radioactive waste from Kewaunee. In addition, because of
technological advances, waste compaction, and the reduction of
waste generated, Kewaunee has on-site, low-level radioactive
waste storage capacity sufficient to store low-level waste
expected to be generated over a ten-year period.

The PSCW has directed the owners of Kewaunee to develop
depreciation and decommissioning cost levels based on full
recovery by the end of 2002 versus recovery by license expiration
in 2013. This was prompted by the uncertainty regarding the
expected useful life of the plant without steam generator
replacement. At December 31, 1997, the net carrying amount of the
Company's investment in Kewaunee was approximately $19.1 million.
The current cost of the Company's share of the estimated costs to
decommission Kewaunee, assuming early retirement, ($78.8 million)
exceeds the fair market value of decommissioning trust assets at
December 31, 1997, ($59.2 million) by $19.6 million.
Decommissioning costs are based on a site-specific study
performed in 1992 using immediate dismantlement as the method of
decommissioning. Decommissioning costs as studied are assumed to
inflate at an average rate of 6.0 percent. Physical
decommissioning is expected to occur during the period 2014
through 2021 with additional expenditures being incurred during
the period 2022 through 2039 related to the storage of spent
nuclear fuel at the plant site.

Nuclear decommissioning costs are being accrued to an end-of-
service life of 2002 for Kewaunee. These costs are currently
recovered from customers in rates and are deposited in external
trusts. For 1997, the decommissioning costs recovered in rates
were $4.9 million. (See page II-8 for further discussion of
Kewaunee.)

The co-owners purchase uranium concentrates, conversion services,
enrichment services, and fabrication services for nuclear fuel
assemblies at Kewaunee. New fuel assemblies replace used
assemblies that are removed from the reactor every 18 months and
placed in storage at the plant site pending removal by the United
States Department of Energy (DOE).

Uranium concentrates, conversion services, and enrichment
services are purchased at spot market prices, through a bid
process, or using existing contracts.

A uranium inventory policy requires that sufficient inventory
exist for up to two reactor reloads of fuel. At December 31,
1997, 960,000 pounds of yellowcake or its equivalent were held in
inventory for Kewaunee.

Two contracts are in place to provide conversion services for
Kewaunee nuclear fuel for reloads in 1998 and 2000.

A contract with COGEMA, Inc., provides a fixed quantity of
enrichment services through the year 2001. Additional enrichment
services will be acquired under a contract with the United States
Enrichment Corporation which is in effect for the life of
Kewaunee or by purchases on the spot market.

A contract with Siemens Power Corporation provides fuel
fabrication services through March 15, 2001, for Kewaunee. This
contract contains force majeure and termination provisions.

If, for any reason, Kewaunee was forced to suspend operations
permanently, fuel-related obligations are as follows: (1) there
are no financial penalties associated with the present uranium
supply, conversion service, and enrichment agreements; and (2)
the fuel fabrication contract contains force majeure and
termination for convenience provisions. As of the end of 1997,
the maximum exposure would not be expected to exceed $550,000.
Uranium inventories could be sold on the spot market.

The Nuclear Policy Act requires that the DOE accept, transport,
and dispose of spent nuclear fuel beginning no later than January
31, 1998. The DOE has announced that it will delay the acceptance
of spent nuclear fuel beyond 1998. The nuclear utilities have
been supported by a decision of the United States Court of
Appeals for the District of Columbia Circuit in their claim that
they may pursue the remedies provided in the DOE standard
contract in the event the DOE does not perform its duty to
dispose of spent nuclear fuel by the January 31, 1998, deadline.

The Energy Policy Act of 1992 requires that the federal
government and nuclear utilities fund the decontamination and
decommissioning of the government's three gaseous diffusion
plants in the United States. The Company is required to pay
approximately $250,000 per year (adjusted for inflation) through
the year 2007. The co-owners, as well as other nuclear utilities,
have filed suit in the United States Court of Federal Claims
disputing the decontamination and decommissioning assessment. The
suit has been stayed pending the outcome of the Yankee Atomic
Electric Company (Yankee Atomic) appeal. Yankee Atomic has
received an adverse decision in the United States Court of
Appeals for the Federal Circuit and has filed a petition for
certiorari with the United States Supreme Court.

Air quality

Phase II of the federal Clean Air Act amendments of 1990 sets
stringent SO2 and nitrogen oxide emission limitations which may
result in increased capital and operating and maintenance
expenditures. Phase II emission compliance strategies could
include the following: fuel switching, emission trading,
purchased power agreements, new emission control devices, or
installation of new fuel-burning technologies and clean-coal
technologies.

There is a Wisconsin acid rain law which imposes limitations of
SO2 emissions on the major utilities. Blount and the Company's
share of Columbia are required to meet a combined SO2 emission
rate of 1.20 pounds of SO2 per million Btu. No capital costs are
anticipated to meet compliance with this standard.

The federal Clean Air Act amendments of 1990 require the EPA to
perform certain studies concerning hazardous air emissions from
electric utilities. Regulation of power plants for these
emissions may occur as a result of these studies. The DNR
hazardous air emission regulations currently exempt fossil-fuel
combustion.

The Company believes all of its plants to be in full compliance
with all material aspects of present air-pollution control
regulations.

Water quality

The Company is subject to water quality regulation by the DNR.
These regulations include both categorical-effluent discharge
standards and general water quality standards. The regulations
limit discharges from the Company's plants into Lake Michigan and
other Wisconsin waters.

The categorical-effluent discharge standards require each
discharger to use effluent treatment processes equivalent to
categorical "best practicable" or "best available" technologies
under compliance schedules established pursuant to the federal
Water Pollution Control Act. The DNR has published categorical
regulations for chemical discharges from steam electric
generating plants. The Company is in compliance with applicable
standards.

Solid waste

The Company is listed as a potentially responsible party on the
roster of generators for the Refuse Hideaway Landfill in
Middleton, Wisconsin, and the Lenz Oil site in Lemont, Illinois.
The Refuse Hideaway Landfill was used for the disposal of fly-ash
sludge from 1980 to 1984. The Lenz Oil Site was operated for
several years as a facility for the storage and processing of
waste oil. The Environmental Protection Agency (EPA) has placed
the two sites on the national priorities Superfund list of sites
requiring clean up under the Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA). The scope of
liability under CERCLA is very broad.

A group of companies is currently negotiating with the EPA on the
cleanup of the sites. In the opinion of management and legal
counsel, the Company's share of the final cleanup costs will not
result in any materially adverse effects on the operations, cash
flows, or financial position of the Company. Significant
insurance recovery may also be available for the cleanup.

From 1855 through the 1950s, the Company and its predecessors
operated a manufactured gas plant at the present site of Blount.
The plant used coal and oil to produce a low-Btu gas used
primarily for residential cooking and heating. Wastes from the
gas manufacturing process included light oils and tars. These
materials were either recycled into the gas manufacturing process
or sold for other uses such as asphalt manufacturing. The
residual tars and oils from the operation of the plant may have
impacted the site near the gas holders. The Company has been
monitoring the groundwater and soils in cooperation with the DNR
for several years. In the opinion of management and legal
counsel, the resolution of this matter will not result in any
materially adverse effect on the operations or financial position
of the Company.

The City of Madison has identified the Company as a possible
potential responsible party for the remediation of the Demetral
Landfill. Waste materials disposed of at the site by the Company
consisted of fly ash and bottom ash from the combustion of coal
to generate electricity. The Company and many others used the
landfill in the early 1950s. The Company has the potential to
incur liability costs associated with its use of this landfill.
In the opinion of management and legal counsel, the resolution of
this matter will not result in any materially adverse effect on
the operations or financial position of the Company.

Gas Operations

On December 31, 1997, the Company supplied natural gas service to
107,226 customers in the cities of Elroy, Madison, Middleton,
Monona, Fitchburg, Lodi, Verona, and Viroqua; 22 villages; and
all or parts of 41 townships. Revenues received from residential
and commercial customers accounted for 55 and 37 percent,
respectively, of the total gas revenues for 1997. The gas
operations accounted for 38 percent of the total revenues of the
Company. Revenues from transportation service accounted for
2 percent of the total gas revenues for 1997. Sales and revenues
from best-efforts rate schedules accounted for 3 and 2 percent of
total retail sales and revenues, respectively.

The Company has the ability to peak shave through use of a
propane-air gas manufacturing plant for which it had on hand
adequate fuel supplies for its peak-shaving requirements during
the 1997 to 1998 heating season. In addition, the Company can
curtail gas deliveries to its interruptible customers.
Approximately 8 percent of gas sold in 1997 was sold to
interruptible customers.

Gas supply

The Company has physical interconnections with both ANR Pipeline
Company (ANR) and Northern Natural Gas Company (NNG). The
Company's primary service territory, which includes Madison and
the surrounding area, receives deliveries at four ANR gate
stations and one NNG gate station. The Company also receives
deliveries at NNG gate stations located in the communities of
Viroqua, Elroy, and Crawford County. Interconnections with two
major pipelines provide competition in interstate pipeline
service and a more reliable and economical supply mix including
gas from Canada and the United States Mid-Continent and
Gulf/Offshore regions.

By contract, a total of 5,576,600 dekatherms can be injected into
ANR's storage fields from April 1 through October 31. These gas
supplies are then available for withdrawal during the subsequent
heating season of November 1 through March 31. ANR's storage
fields are located in Michigan. Use of storage provides the
Company with the ability to purchase gas supplies during the
summer season when prices are normally lowest and withdraw these
supplies during the winter season when gas prices are typically
higher. Storage allows the Company greater ability to meet daily
load fluctuations.

During the winter months, when the demand of its customers is
highest, the Company is primarily concerned with meeting its
obligation to its firm customers. Long-term firm supply
contracts, supplies in storage injected during the summer, and
firm supplies purchased for the winter period are utilized to
meet customer demand. These gas supplies are contracted for prior
to the heating season so price levels can be locked in to assure
reliability of supply and stability in pricing.

The prior heating season (November 1996 and continuing through
March 1997) was colder than normal. Demand for natural gas
remained high during the summer (April 1997 through October 1997)
as gas was injected into storage to replenish inventories. Gas
prices also remained relatively high. The beginning of the
current heating season (starting November 1997 through March
1998) has been warmer than normal and caused storage levels to be
somewhat higher than normal.

Regarding transportation of supply, the Company has firm
transportation service on ANR for a maximum daily quantity of
33,618 dekatherms. The Company's NNG maximum daily quantity for
firm transportation service is 48,719 dekatherms. The Company
also holds 2,457 dekatherms of firm transportation service into
Viroqua's NNG gate station and firm transportation service of
1,432 dekatherms into Crawford County's NNG gate station.

General

The Company's business is seasonal to the same extent as other
Upper Midwest electric and natural gas utilities.

The Company had 669 permanent employees at December 31, 1997.

Information regarding Company executive officers is included
under Item 10 of this report, page III-1, which information is
incorporated herein by reference.

<PAGE>
<TABLE>
Item 2. Properties

The following table presents the generating capability in service at December 31, 1997:
<CAPTION>
Commercial Net
Operation Capability No. of
Plants Date Fuel (Megawatt) Units
Steam plants
<S> <C> <C> <C> <C>
Columbia 1975 & 1978 Low-sulfur coal 232 (1,2) 2
Kewaunee 1974 Nuclear 93 (1,3) 1
Blount
(Madison) 1957 & 1961 Coal/gas 98 2
1938 & 1942 Gas 40 2

1949 Coal/gas 23 1
1964-1968 Gas/oil 35 4
Combustion
turbines 1964-1973 Gas/oil 88 5
Total 609
</TABLE>
(1) Base load generation
(2) Company's 22 percent share of two 527-mw units located near Portage,
Wisconsin
(3) Company's 17.8 percent share of 525-mw unit located near Kewaunee,
Wisconsin
<TABLE>
Major electric transmission and distribution lines and substations in service at December 31, 1997, are as
follows:
<CAPTION>
MILES
Lines Overhead Lines Underground Lines
<S> <C> <C>
Transmission
345 kV 124 -

138 kV 96 3

69 kV 64 20

Distribution
13.8 kV and 1,022 748
under

Substation Installed Capacity (kVA)

Transmission (22) 4,132,350

Distribution (33) 361,700
</TABLE>
<PAGE>
Gas facilities include 1,886 miles of distribution mains
and one propane air plant capable of producing a maximum
daily capacity of 9,000 dekatherms of natural gas
equivalent.

Item 3. Legal Proceedings

None.

Item 4. Results of Votes of Security Holders

No matters were submitted to a vote of security holders during
the fourth quarter of the fiscal year. <PAGE>
PART II.

Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters

The principal market in which the common stock of the Company is
traded is The Nasdaq National Stock Market (Nasdaq) under the
symbol MDSN. The approximate number of stockholders of record on
January 31, 1998, was 18,383. The Company's transfer agent and
registrar is Harris Trust and Savings Bank, Chicago, Illinois.
The high and low sales prices for the common stock on Nasdaq and
the dividends paid per common share for each quarter for the past
two fiscal years are shown below.

<PAGE>
<TABLE>
<CAPTION>
Common stock
price range Dividends per
1997 share
High Low 1997
<S> <C> <C> <C>
First quarter $21 3/4 $18 1/2 $0.320
Second quarter $21 1/4 $19 1/2 $0.320
Third quarter $21 1/4 $19 7/8 $0.323
Fourth quarter $23 3/4 $19 5/8 $0.323

Common stock price range Dividends per
1996 share
High Low 1996

First quarter $27 1/2 $23 1/8 $0.317
Second quarter $25 3/4 $21 1/2 $0.317
Third quarter $23 3/4 $21 1/2 $0.320
Fourth quarter $22 3/8 $19 5/8 $0.320
</TABLE>
<PAGE>
<TABLE>
Item 6. Selected Financial Data
<CAPTION>
For the years ended December 31,
(In thousands of dollars, except
per-share amounts) 1997 1996 1995 1994 1993
<S> <C> <C> <C> <C> <C>
Summary of Operations

Operating Revenues:
Electric . . . . . . . . . . . . $163,123 $152,747 $153,554 $149,665 $147,201
Gas . . . . . . . . . . . . . . . 101,525 100,544 95,036 95,307 96,932
Total . . . . . . . . . . . . . 264,648 253,291 248,590 244,972 244,133
Operating expenses . . . . . . . . 212,921 200,486 191,725 187,469 187,717
Other general taxes . . . . . . . . 8,797 8,736 8,709 8,619 8,222
Income tax items . . . . . . . . . 11,940 12,553 14,285 14,822 13,964
Net operating income . . . . . . 30,990 31,516 33,871 34,062 34,230
Other (loss)/income (including
allowance 2,272 (14,177) 1,635 2,146 2,118
for funds used during construction)
Income before interest expense . 33,262 17,339 35,506 36,208 36,348
Interest expense . . . . . . . . . 10,739 10,912 11,536 11,197 11,673
Net income . . . . . . . . . . . 22,523 6,427 23,970 25,011 24,675
Preferred dividends . . . . . . . . - - 64 471 489
Earnings on common stock . . . . 22,523 6,427 $23,906 $24,540 $24,186
Average shares outstanding . . . . 16,080 16,080 16,080 16,080 16,055
Earnings per share . . . . . . . $1.40 $0.40 $1.49 $1.53 $1.51
Dividends paid per share . . . . $1.287 $1.273 $1.260 $1.247 $1.227
Ratio of earnings to fixed charges* 4.02 2.71 4.23 4.49 4.15

At December 31,
Assets
Electric . . . . . . . . . . . . . $313,855 $315,022 $327,053 $323,870 $328,048
Gas . . . . . . . . . . . . . . . . 118,339 116,723 119,968 118,210 114,626
Assets not allocated . . . . . . . 39,596 52,424 46,855 45,679 22,690
Total . . . . . . . . . . . . . . $471,790 $484,169 $493,876 $487,759 $465,364
Capitalization
Common shareholders' equity . . . . $180,923 $179,089 $193,137 $189,489 $184,995
Redeemable preferred stock . . . . - - - 5,100 5,400
Long-term debt . . . . . . . . . . 129,923 128,886 129,048 130,800 120,396
Short-term debt . . . . . . . . . . 33,500 29,750 20,500 28,600 23,500
Total Capitalization . . . . . . $344,346 $337,725 $342,685 $353,989 $334,291

<FN>
*For the purpose of computing the ratio of earnings to fixed charges, earnings have been calculated by
adding to income before interest expense, current and deferred federal and state income taxes, investment
tax credits deferred and restored charged (credited) to operations, and the estimated interest component
of rentals. Fixed charges represent interest expense, amortization of debt discount, premium and expense,
and the estimated interest component of rentals.
</TABLE>
<PAGE>
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations

GENERAL

The following discussion and analysis provides information which
management believes is relevant to an assessment and
understanding of Madison Gas and Electric Company's (the Company)
consolidated results of operations and financial condition. The
discussion should be read in conjunction with the consolidated
financial statements and notes thereto.

Certain matters that are discussed in the Management's Discussion
and Analysis are forward-looking statements and can generally be
identified by words such as "believes," "anticipates," or
"expects." These forward-looking statements are subject to
certain risks or uncertainties which could cause actual results
to differ materially from those currently anticipated.

RESULTS OF OPERATIONS

Earnings overview

Consolidated earnings for the Company were $1.40 per share in
1997 despite mild weather and an extended outage at the Kewaunee
Nuclear Power Plant (Kewaunee). As a result of Kewaunee being out
of service for the first half of the year, the Company had to
replace the generation normally provided by Kewaunee with more
expensive purchased power. The Company also faced regional power
shortages during the summer of 1997, incurring extra expenses for
actions taken by the Company to prevent power outages for the
Company's customers. The Company was the only major utility in
Wisconsin that did not interrupt service to any of its customers.

Earnings from core utility operations were $1.48 per share in
1996, but the consolidated earnings were negatively impacted by
the following items: a one-time charge of $10.4 million (after
tax) to reflect the current value of the Company's investments in
its gas marketing subsidiaries, a one-time charge of $1.6 million
(after tax) resulting from a refund to natural gas customers
under a sharing mechanism between Great Lakes Energy Corp.
(GLENCO) and the Company, and operating losses of $5.4 million
(after tax) from the Company's gas marketing subsidiaries.
Consolidated earnings per share for the Company were $0.40 in
1996.

Consolidated earnings for the Company were $1.49 per share in
1995. Above-normal temperatures experienced during the summer
months helped offset the negative impacts of a 3.3 percent
electric rate decrease which was effective January 1, 1995.

Electric sales and revenues

Electric retail sales for 1997 increased 2.9 percent from 1996
despite the cooler-than-normal temperatures experienced in the
summer. The increase in retail sales is due to an increase in the
number of electric customers and average usage per retail
customer. The electric sales breakdown by customer class is shown
in the table below:

Electric Sales

Megawatt %
Hours 1997 1996 Change

Residential 720,576 725,471 (0.7)
Commercial 1,420,347 1,381,043 2.8

Industrial 307,485 289,903 6.1
Other 332,995 305,962 8.8

Total
Retail 2,781,403 2,702,379 2.9

Resale -
Utilities 64,914 26,815 142.1

Total
Sales 2,846,317 2,729,194 4.3

Electric revenues increased $10.4 million or 6.8 percent in 1997
compared to 1996. The increase reflects higher electric sales, a
3.1 percent increase in electric rates effective August 20, 1997,
and an interim rate surcharge of 0.507 cents per kilowatt-hour
related to the extended outage at Kewaunee which was in effect
from March through June (see Item 8, page F-16, Note 3).

Electric retail sales for 1996 increased slightly from 1995.
This, too, can be attributed to an increase in the number of
electric customers. Electric revenues decreased slightly in 1996
compared to 1995.

Gas sales and revenues

Total gas therms delivered by the Company decreased 4.9 percent
in 1997 compared to 1996, largely reflecting the warmer weather
throughout the winter months of 1997. Total heating degree days
(as measured by the number of degrees the mean daily temperature
is below 65 degrees Fahrenheit) decreased 9.7 percent for the
winter heating season (January through March, November and
December) of 1997 when compared to 1996. The table below shows
total gas deliveries by customer class:

Therms Delivered

%
Thousands 1997 1996 Change

Residential 87,664 96,062 (8.7)
Commercial and 87,717 93,723 (6.4)
Industrial

Total Retail
System 175,381 189,785 (7.6)

Transport 40,947 37,707 8.6

Total Gas
Deliveries 216,328 227,492 (4.9)

Despite the decrease in gas delivered in 1997, gas revenues
increased by 1.0 percent when compared to 1996. The increase in
revenues, despite a decrease in gas deliveries, was due primarily
to higher-unit gas costs, specifically during the first quarter.
These costs were passed on to customers through the Purchased Gas
Adjustment Clause (PGAC) (see Regulatory and Accounting Issues,
page II-10). A gas rate increase of 3.5 percent went into effect
August 20, 1997, which also contributed to the increased
revenues.

Gas delivered to customers in 1996 increased 3.3 percent compared
to 1995, and revenues increased $5.5 million or 5.8 percent
during the same period. This was mainly attributable to the
increase in gas deliveries due to the colder weather experienced
during the first quarter of 1996.

Electric fuel and natural gas costs

Electric fuel and purchased power costs increased $6.4 million or
16.7 percent in 1997 compared to the same period a year ago. As
previously mentioned, this was due to the increased purchased
power costs associated with replacing generation lost from the
extended outage at Kewaunee. Kewaunee normally provides
approximately 25 percent of the generation requirements of the
Company. Higher generation costs during July due to the
unavailability of power resulting from the regional power
shortages also increased fuel and purchased power costs in 1997
compared to 1996. The Company's electric margin (revenues less
fuel and purchased power) increased $4.0 million or 3.5 percent
during 1997 compared to 1996.

Electric fuel and purchased power costs increased $2.3 million or
6.4 percent from 1995 to 1996. This increase is also due to the
higher cost of replacement power from the extended outage at
Kewaunee. Kewaunee was removed from service in September 1996 for
scheduled refueling and maintenance work and did not return to
service until June 1997. The electric margin decreased $3.1 million
or 2.6 percent during 1996 compared to 1995. This
decrease in the electric margin was a result of the increase in
replacement purchased power costs related to the extended outage
at Kewaunee.

Natural gas costs decreased $0.9 million or 1.4 percent from 1997
compared to 1996 due mainly to the decrease in gas delivered
caused by the warm winter weather. Gas margin (revenues less
natural gas purchased) increased by $1.9 million or 5.6 percent
in 1997 compared to 1996. This was a result of continued customer
growth and the rate increase mentioned previously.

Natural gas costs increased $8.5 million or 14.8 percent during
1996 compared to 1995. The cold first quarter and the subsequent
demand for natural gas increased the cost per therm accordingly.
The cost per therm in 1996 increased $0.04 or 13.4 percent over
1995.

Other operating expenses

Operations and maintenance (O&M) expenses increased $4.2 million
or 5.9 percent in 1997 compared to 1996. The primary reasons are
the higher repair costs for Company-owned generation due to the
extended outage of Kewaunee. The co-owners of Kewaunee received
authorization from the Public Service Commission of Wisconsin
(PSCW) to defer a majority of the costs for steam generator
repairs (see Item 8, page F-16, Note 3). O&M expenses decreased
$2.8 million or 3.8 percent during 1996 compared to 1995.

Depreciation and amortization expense increased $2.8 million or
11.0 percent for the year ended 1997 compared to the same period
a year ago. This increase is due, in part, to the accelerated
depreciation of Kewaunee. Depreciation expense related to
decommissioning costs increased $1.8 million or 37.9 percent in
1997 compared to 1996 because of the acceleration of
decommissioning of Kewaunee. The PSCW approved accelerated
depreciation and decommission funding for Kewaunee based on its
service life ending at the end of 2002.

Other nonoperating expenses

The Company's nonutility income for 1997 was $0.8 million
compared to operating losses of $5.4 million in 1996. The
Company's two gas marketing subsidiaries, GLENCO and American
Energy Management Inc. (AEM), formed a joint venture effective
January 1, 1997, with another gas marketing company to market
natural gas and energy services to industrial and commercial
customers in the Great Lakes region. The joint venture is called
National Energy Management, L.L.C., and is based in Chicago.

The Company recorded a one-time charge in 1996 of $10.4 million
(after tax) to properly reflect the current value of the
Company's investments in its gas marketing subsidiaries and
reorganizing these activities for the future (see Item 8,
page F-17, Note 4).

Electric and gas operations outlook

The Company anticipates electric and gas customer growth at a
compound rate of 1 to 2 percent over the next five-year period
ending December 31, 2002. The service territory remains well-
insulated against economic downturns. The Company expects to
remain a strong competitor in a restructured electric industry
because of its low generation costs, competitive rates, low
percentage of industrial customers, and lower risk of stranded
investments in power plants. The Company continues to offer
competitive rates and services to meet the needs of its customers
in a deregulated natural gas market.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities

Cash provided by operating activities decreased $7.5 million or
15.5 percent in 1997 compared to 1996. This is mainly due to the
reduction in current payables of the Company's gas marketing
subsidiaries, GLENCO and AEM. Cash provided by operating
activities decreased $2.5 million or 4.9 percent in 1996 compared
to 1995.

Capital requirements and investing activities

The Company's liquidity is primarily affected by the requirement
of its ongoing construction program. Capital expenditures in 1997
were $21.6 million. It is anticipated that capital expenditures
will be $46 million in 1998. The major capital projects for 1998
include the wind energy project in northeastern Wisconsin, which
will cost about $14 million, and Company-owned backup generation
projects costing about $3 million. The backup generation projects
will help maintain electric reliability. Estimated capital
expenditures for the years 1999 through 2002 will average $33
million per year.

Capital expenditures and nuclear fuel estimated for 1998, actual
for 1997, and the average for the three-year period 1994 through
1996 are shown below:

<PAGE>
<TABLE>
Expenditures for Construction and Nuclear Fuel
(Thousands of Dollars)
<CAPTION>
For the years ended 1998 Annual Average
December 31: Estimated 1997 1994 to 1996
<S> <C> <C> <C> <C> <C> <C>
Electric
Production $17,977 38.7% $ 5,005 23.1% $ 1,911 8.5%
Transmission 2,065 4.5 1,602 7.4 1,151 5.1
Distribution and
General 12,034 25.9 8,287 38.3 8,965 39.8
Nuclear Fuel 4,228 9.1 1,394 6.4 2,752 12.2
Total Electric 36,304 78.2 16,288 75.2 14,779 65.6
Gas 6,441 13.9 4,427 20.5 5,908 26.3
Common 3,655 7.9 920 4.3 1,812 8.1

TOTAL $46,400 100.0% $21,635 100.0% $22,499 100.0%
</TABLE>
<PAGE>
Financing activities and capitalization matters

In April 1997, the Company purchased on the open market $3.8
million of its First Mortgage Bonds. In June 1997, the Company
entered into a fixed interest rate agreement for $5.0 million
maturing June 2004.

At December 31, 1997, bank lines of credit available to the
Company were $52 million. Bank lines are generally used to
support the Company's commercial paper issued which represents a
primary source of short-term financing. The Company's dealer-
issued commercial paper carries the highest ratings assigned by
Moody's Investors Service and Standard & Poor's Corporation.

The Company's existing bonds are rated AA by Standard & Poor's
and Aa2 by Moody's Investors Service.

Kewaunee Nuclear Power Plant

The Company has a 17.8 percent ownership interest in Kewaunee,
which it owns jointly with two other utilities. Kewaunee is
operating with a license that expires in 2013. Kewaunee returned
to service in June 1997, after having been out of service since
September 1996, for refueling, routine maintenance, and repair of
the steam generators. Kewaunee is currently operating at
97 percent of rated capacity because certain steam generator
tubes have been removed from service rather than repaired.
Additional replacement power costs due to the extended outage
were recovered through a customer surcharge from March 6, 1997,
through July 1, 1997 (see Item 8, page F-16, Note 3).

Effective March 20, 1997, the Kewaunee co-owners received
authorization from the PSCW to defer all costs associated with
the resleeving repair of the steam generators. The co-owners of
Kewaunee have received approval from the PSCW on their requested
rate recovery of these deferred costs through a customer
surcharge (see Item 8, page F-16, Note 3).

Electric industry trend

The new plan focuses on the construction of a generation and
transmission infrastructure by all Wisconsin utilities to
increase the amount of power in the state and the state's ability
to obtain electricity from other regions. The PSCW plans to
remove any barriers to open access to the transmission system
that currently exist and to move forward in its efforts to
develop a strong state and regional Independent System Operator
(ISO). This would assure that the transmission system is operated
safely, reliably, and with open and nondiscriminatory access.
Also in its revised plan, the PSCW plans to explore new ways to
promote the development of renewable energy sources. The Company
is in the process of building a $14 million wind generation
project which will allow its customers to purchase blocks of
energy produced with renewable resources. The PSCW has not set a
date for retail competition and has concluded that any decision
to go to retail competition in the electric industry remains to
be made in the future. The Company cannot predict what impact
future PSCW actions may have on its future financial condition,
cash flows, or results of operations. However, the Company
believes it is well-positioned to compete in a deregulated
market.

Regulatory and accounting issues

The Company's recent rate order authorized a gas cost recovery
mechanism that allows recovery of pipeline capacity, Federal
Energy Regulatory Commission (FERC)-approved/mandated charges,
and supply demand costs. Under the new mechanism, gas commodity
costs will be compared to a monthly benchmark equal to the first-
of-the-month index plus adders reflecting the effects on pricing
for reliability, flexibility, weather, and variable
transportation costs. If actual costs are below the benchmark,
full recovery is allowed. Gas commodity costs above the benchmark
will be reviewed by the PSCW. A target will also be determined
for capacity release. Capacity release above the target will be
shared 60 percent with the ratepayers and 40 percent with the
shareholders. Any shortfalls in capacity release will be shared
40 percent with the ratepayers and 60 percent with the
shareholders.

The restructuring of the electric industry could affect the
eligibility of the Company to continue applying Statement of
Financial Accounting Standard (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation." Under this situation,
continued deferral of certain regulatory asset and liability
amounts on the Company's books may no longer be appropriate as
allowed under SFAS No. 71. The Company is unable to predict
whether any adjustments to regulatory assets and liabilities will
occur in the future. The PSCW's restructuring plan specifically
recognizes the need to allow recovery for commitments made under
prior regulatory regimes.

Effective January 1, 1996, the Company adopted SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to be Disposed Of." This statement requires that
long-lived assets and certain identifiable intangibles held and
used by the Company be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. SFAS No. 121 also requires that
assets to be disposed of be reported at the lower of the carrying
amount or the fair value less costs to sell. Adoption of this
statement did not have a material impact on the Company's
financial position, results of operations, or cash flows.

In February 1997, SFAS No. 128, "Earnings Per Share," was issued.
SFAS No. 128 simplifies the standards for computing earnings per
share and requires the presentation of two new amounts, basic and
diluted earnings per share. The Company has retroactively adopted
this standard for all prior periods reported.

In June 1997, SFAS No. 131, "Disclosure about Segments of an
Enterprise and Related Information," was issued. SFAS No. 131
requires that public business enterprises report certain
information about operating segments in complete sets of
financial statements of the Company and in condensed financial
statements of interim periods issued to shareholders. The
objective of requiring disclosures about segments of an
enterprise and related information is to provide information
about different types of business activities in which the Company
engages and the different economic environments in which it
operates in order to help users of financial statements better
understand the Company's performance, assess its prospects for
future net cash flows, and make more informed judgments about the
Company as a whole.

Mergers

In May 1995, Northern States Power Company (NSP) and Wisconsin
Energy Corporation (WEC) announced a proposed $6 billion merger.
A company called Primergy Corporation (Primergy) was contemplated
to be formed as a result of the merger. On May 14, 1997, the FERC
rejected the merger as filed, citing concerns over dominance in
the Midwest power and transmission markets. The FERC stated that
Primergy would be able to dominate the eastern Wisconsin and
upper Michigan power generation market. On May 16, 1997, the
Board of Directors from both NSP and WEC agreed to terminate
their merger agreement.

Inflation

The current financial statements report operating results in
terms of historical cost. Even though the statements provide a
reasonable, objective, quantifiable statement of financial
results, they do not evaluate the impact of inflation. For
ratemaking purposes, projected normal operating costs include
impacts of inflation recoverable in revenues. However, electric
and gas utilities, in general, are adversely impacted by
inflation because depreciation of the utility plant is limited to
the recovery of historical costs. Thus, cash flows from the
recovery of existing utility plant, to a certain extent, may not
be adequate to provide replacement of plant investment.

Environmental issues

Phase II of the Federal Clean Air Act amendments of 1990 sets
stringent SO2 and nitrogen oxide emission limitations, which
generally take effect January 1, 2000. These may result in
increased expenditures. Phase II emission compliance strategies
for the Company include the following: fuel switching, emission
trading, purchased power agreements, new emission control devices,
or installation of new fuel-burning technologies and clean coal
technologies. Phase II emission compliance strategies and their
costs are currently being evaluated. The Company expects no major
capital expenditures as a result of Phase II.

Year 2000

The Company has established a Year 2000 project coordinator and a
Year 2000 compliance team to identify our systems, equipment, and
operations that will be impacted by the year 2000. These actions
are necessary to ensure that the systems and applications will
recognize and process the year 2000 and beyond. The Year 2000
team has started to identify the major areas that will be
impacted by the year 2000 and initial conversion efforts are
under way. The Company is working with suppliers, dealers,
financial institutions, and others with which it does business to
coordinate year 2000 conversion. The Company is estimating a cost
of $2.9 million to become Year 2000 compliant.

Item 8. Financial Statements and Supplementary Data

Index of Consolidated Financial Statements, Footnotes, and
Supplementary Data

Responsibility for Financial Statements F-1
Report of Independent Accountants F-2
Consolidated Statements of Income and Retained Income F-3
Consolidated Statements of Cash Flows F-4
Consolidated Balance Sheets F-5
Consolidated Statements of Capitalization F-6
Notes to Consolidated Financial Statements F-7 - F-20

Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure

None. <PAGE>
Responsibility for Financial Statements

The management of Madison Gas and Electric Company is responsible
for the preparation and presentation of the financial information
in this Annual Report. The following financial statements have
been prepared in accordance with generally accepted accounting
principles consistently applied and reflect management's best
estimates and informed judgments as required.

To fulfill these responsibilities, management has developed and
maintains a comprehensive system of internal operating,
accounting, and financial controls. These controls provide
reasonable assurance that the Company's assets are safeguarded,
transactions are properly recorded, and the resulting financial
statements are reliable. An internal audit function assists
management in monitoring the effectiveness of the controls.

The Report of Independent Accountants on the financial statements
by Coopers & Lybrand L.L.P. appears on page F-2. The
responsibility of the independent accountants is limited to the
audit of the financial statements presented and the expression of
an opinion as to their fairness.

The Board of Directors maintains oversight of the Company's
financial situation through its monthly review of operations and
financial condition and its selection of the independent
accountants. The Audit Committee, comprised of all Board members
who are not employees or officers of the Company, also meets
periodically with the independent accountants and the Company's
internal audit staff who have complete access to and meet with
the Audit Committee, without management representatives present,
to review accounting, auditing, and financial matters. Pertinent
Items discussed at the meetings are reviewed with the full Board
of Directors.

/s/ David C. Mebane
Chairman, President and
Chief Executive Officer

/s/ Terry A. Hanson
Vice President - Finance
<PAGE>
Report of Independent Accountants

To the Shareholders and Board of Directors, Madison Gas and
Electric Company:

We have audited the accompanying consolidated balance sheets and
statements of capitalization of MADISON GAS AND ELECTRIC COMPANY
and subsidiaries as of December 31, 1997 and 1996, and the
related consolidated statements of income and retained income and
cash flows for the years ended December 31, 1997, 1996, and 1995.
These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion
on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of Madison Gas and Electric Company and subsidiaries as of
December 31, 1997 and 1996, and the consolidated results of their
operations and their cash flows for the years ended December 31,
1997, 1996, and 1995, in conformity with generally accepted
accounting principles.

/s/ Coopers & Lybrand L.L.P.
Milwaukee, Wisconsin
February 6, 1998
<PAGE>
<TABLE>
Consolidated Statements of Income and Retained Income
(Thousands of dollars, except per-share amounts)
<CAPTION>
For the years ended December 31 1997 1996 1995
<S> <C> <C> <C>
CONSOLIDATED STATEMENT OF INCOME

Operating Revenues:
Electric $163,123 $152,747 $153,554
Gas 101,525 100,544 95,036
Total Operating Revenues 264,648 253,291 248,590
Operating Expenses:
Fuel for electric generation 30,764 26,676 28,017
Purchased power 14,008 11,687 8,048
Natural gas purchased 65,079 66,021 57,488
Other operations 62,018 58,178 61,499
Maintenance 12,735 12,414 11,858
Depreciation and amortization 28,317 25,510 24,815
Other general taxes 8,797 8,736 8,709
Income tax items 11,940 12,553 14,285
Total Operating Expenses 233,658 221,775 214,719
Net Operating Income 30,990 31,516 33,871
AFUDC - equity funds 28 40 57
Other income, net 1,445 1,517 549
Writedown of nonregulated gas - (10,400) -
subsidiaries, net
Non-utility operating (loss)/income, net 784 (5,355) 1,000
Income Before Interest Expense 33,247 17,318 35,477
Interest Expense:
Interest on long-term debt 9,641 9,815 10,331
Other interest 1,098 1,097 1,205
AFUDC - borrowed funds (15) (21) (29)
Net Interest Expense 10,724 10,891 11,507
Net Income 22,523 6,427 23,970
Preferred stock dividends - - 64
Earnings on Common Stock $ 22,523 $ 6,427 $ 23,906
Earnings Per Share of Common Stock (basic
and diluted) (Average shares outstanding -
16,079,718 for all years) $1.40 $0.40 $1.49

CONSOLIDATED STATEMENTS OF RETAINED INCOME
Balance - Beginning of Year $50,451 $64,499 $60,851
Add - Net income 22,523 6,427 23,970
Deduct - Cash dividends on common stock (20,689) (20,475) (20,258)
(Dividends per share were $1.29,
$1.27, and $1.26, respectively)
Preferred stock dividend - - (64)
Balance - End of Year $52,285 $50,451 $64,499
<FN>
The accompanying notes are an integral part of the above statements.
</TABLE>
<PAGE>
<TABLE>
Consolidated Statements of Cash Flows
(Thousands of dollars, except per-share amounts)
<CAPTION>
For the years ended December 31, 1997 1996 1995
<S> <C> <C> <C>
Operating Activities:
Net income $22,523 $ 6,427 $23,970
Items not affecting cash:
Depreciation and amortization 28,317 25,510 24,815
Deferred income taxes (1,400) (7,181) (2,442)
Amortization of nuclear fuel 1,517 2,098 2,740
Amortization of investment tax credits (753) (792) (768)
AFUDC - equity funds (28) (40) (57)
Writedown of nonregulated gas - 15,741 -
subsidiaries
Other 431 1,146 1,729
Net Funds Provided from Operations 50,607 42,909 49,987
Changes in working capital, excluding
cash equivalents, sinking funds,
maturities, and interim loans:
Decrease/(increase) in current assets 6,162 (3,445) (12,168)
(Decrease)/increase in current (21,174) 2,458 11,287
liabilities
Other noncurrent items, net 5,244 6,386 1,716
Cash Provided by Operating Activities 40,839 48,308 50,822
Financing Activities:
Cash dividends on common and preferred (20,689) (20,475) (20,322)
stock
Maturities/redemptions of First Mortgage (3,800) (7,840) (13,263)
Bonds
Increase in long-term debt 5,000 - 11,000
Other decreases in First Mortgage Bonds (163) (162) (199)
Decrease in preferred stock - - (5,300)
Decrease in bond construction funds, net - - 8,090
Increase/(decrease) in interim loans 3,750 9,250 (8,100)
Cash Used for Financing Activities (15,902) (19,227) (28,094)
Investing Activities:
Acquisition of nonregulated subsidiary - - (8,036)
Additions to utility plant and nuclear fuel (21,635) (21,906) (19,162)
AFUDC - borrowed funds (15) (21) (29)
Increase in nuclear decommissioning fund (6,467) (4,710) (4,191)
Cash Used for Investing Activities (28,117) (26,637) (31,418)
Change in Cash and Cash Equivalents (3,180) 2,444 (8,690)
Cash and cash equivalents at beginning of
period 5,288 2,844 11,534
Cash and cash equivalents at end of period $2,108 $ 5,288 $ 2,844
<FN>
The accompanying notes are an integral part of the above statements.
</TABLE>
<PAGE>
<TABLE>
Consolidated Balance Sheets
(Thousands of dollars)
<CAPTION>
At December 31, 1997 1996
<S> <C> <C>
ASSETS
Utility Plant, at original cost, in service:
Electric $510,405 $500,690
Gas 181,861 178,312
Gross Plant in Service 692,266 679,002
Less accumulated provision for depreciation (407,602) (374,315)
Net Plant in Service 284,664 304,687
Construction work in progress 10,995 7,517
Nuclear decommissioning fund 59,179 44,617
Nuclear fuel, net 8,255 8,378
Total Utility Plant 363,093 365,199
Other Property and Investments 8,252 7,115
Current Assets:
Cash and cash equivalents 2,108 5,288
Accounts receivable, less reserves of $1,235 and
$1,220, respectively 28,395 39,145
Unbilled revenue 13,580 13,852
Materials and supplies, at lower of average cost
or market 5,557 5,740
Fossil fuel, at lower of average cost or market 3,605 1,808
Stored natural gas, at lower of average cost or
market 9,851 7,189
Prepaid taxes 7,190 7,258
Other prepayments 2,081 1,429
Total Current Assets 72,367 81,709
Deferred Charges 28,078 30,146
Total Assets $471,790 $484,169

CAPITALIZATION AND LIABILITIES
Capitalization (see statement) $310,846 $307,975
Current Liabilities:
Long-term debt sinking fund requirements 200 200
Interim loans - commercial paper outstanding 33,500 29,750
Accounts payable 14,528 30,094
Accrued interest 2,206 2,322
Accrued nonregulated items 4,837 7,923
Other 5,326 7,732
Total Current Liabilities 60,597 78,021
Other Credits:
Deferred income taxes 45,572 46,972
Regulatory liability - SFAS 109 24,875 23,914
Investment tax credit - deferred 10,685 11,439
Other regulatory liabilities 19,215 15,848
Total Other Credits 100,347 98,173
Commitments - -
Total Capitalization and Liabilities $471,790 $484,169
<FN>
The accompanying notes are an integral part of the above balance sheets.
</TABLE>
<PAGE>
<TABLE>
Consolidated Statements of Capitalization
(Thousands of dollars)
<CAPTION>
At December 31, 1997 1996
<S> <C> <C>
Common Shareholders' Equity:
Common stock - par value $1 per share:
Authorized 50,000,000 shares
Outstanding 16,079,718 shares $ 16,080 $ 16,080
Amount received in excess of par value 112,558 112,558
Retained income 52,285 50,451
Total Common Shareholders' Equity 180,923 179,089

First Mortgage Bonds:
6 1/2%, 2006 Series:
Pollution Control Revenue Bonds 6,675 6,875
8.50%, 2022 Series 40,000 40,000
6.75%, 2027A Series:
Industrial Development Revenue Bonds 28,000 28,000
6.70%, 2027B Series:
Industrial Development Revenue Bonds 19,300 19,300
7.70%, 2028 Series 21,200 25,000
First Mortgage Bonds Outstanding 115,175 119,175
Unamortized discount and premium on (1,052) (1,089)
bonds, net
Long-term debt sinking fund requirements (200) (200)
Total First Mortgage Bonds 113,923 117,886

Other Long-Term Debt:
6.01%, due 2000 11,000 11,000
6.91%, due 2004 5,000 -
Total Capitalization $310,846 $307,975
<FN>
The accompanying notes are an integral part of the above statements.
</TABLE>
<PAGE>
Notes to Consolidated Financial Statements
December 31, 1997, 1996, and 1995

1. Summary of Significant Accounting Policies

a. General

Madison Gas and Electric Company (the Company) is an
investor-owned public utility headquartered in Madison,
Wisconsin. The Company generates, transmits, and
distributes electricity to about 123,000 customers in a
250-square-mile area of Dane County. The Company also
transports and distributes natural gas to over
107,000 customers in 1,325 square miles of service
territories in seven counties.

The consolidated financial statements reflect the
application of certain accounting policies described in
this note. The financial statements include the accounts
of the Company and its subsidiaries. All significant
intercompany accounts and transactions have been
eliminated in consolidation. The Company records unbilled
revenue on the basis of service rendered. Gas revenues
are subject to an adjustment clause related to periodic
changes in the cost of gas.

Preparation of the consolidated financial statements in
conformity with generally accepted accounting principles
requires management to make estimates and assumptions
that affect the reported amounts of assets and
liabilities at the dates of the financial statements and
the reported amounts of revenues and expenses during the
reporting periods. They also affect the disclosure of
contingencies. Actual results could differ from those
estimates.

b. Utility Plant

Utility plant is stated at the original cost of
construction, which includes indirect costs consisting of
payroll taxes, pensions, postretirement benefits, other
fringe benefits, administrative and general costs, and an
allowance for funds used during construction (AFUDC).

AFUDC represents the approximate cost of debt and equity
capital devoted to plant under construction. The Company
presently capitalizes AFUDC at a rate of 10.76 percent on
50 percent of construction work in progress. The AFUDC
rate approximates the Company's cost of capital. The
portion of the allowance applicable to borrowed funds is
presented in the Consolidated Statements of Income as a
reduction of interest expense, while the portion of the
allowance applicable to equity funds is presented as
other income. Although the allowance does not represent
current cash income, it is recovered under the ratemaking
process over the service lives of the related properties.

Substantially all of the Company's utility plant is
subject to a first mortgage lien.

c. Nuclear Fuel

The cost of nuclear fuel used for electric generation is
being amortized to fuel expense and recovered in rates
based on the quantity of heat produced for the generation
of electric energy by the Kewaunee Nuclear Power Plant
(Kewaunee). Such cost includes a provision for estimated
future disposal costs of spent nuclear fuel. The Company
currently pays disposal fees to the Department of Energy
based on net nuclear generation. The Company has
recovered through rates and satisfied its known fuel
disposal liability for past nuclear generation.

The National Energy Policy Act enacted in 1992 contains a
provision for all utilities that have used federal
enrichment facilities to pay a special assessment for
decontamination and decommissioning for these facilities.
This special assessment will be based on past enrichment,
and the Company has accrued and deferred an estimate of
$2.2 million for the Company's portion of the special
assessment. The Company believes all costs will be
recovered in future rates.

d. Joint Plant Ownership

The Company and two other Wisconsin investor-owned
utilities jointly own two electric generating facilities,
which account for 54 percent (325 mw) of the Company's
net generating capability. Power from the facilities is
shared in proportion to the companies' ownership
interests. The Company's interests are 22 percent (232
mw) of the coal-fired Columbia Energy Center (Columbia)
and 17.8 percent (93 mw) of Kewaunee. Each owner provides
its own financing and reflects its respective portion of
facilities and operating costs in its financial
statements. The Company's portions of these facilities,
included in its gross utility plant in service, and the
related accumulated depreciation reserves at December 31,
were as follows:

Columbia Kewaunee
(Thousands of 1997 1996 1997 1996
dollars)

Utility plant $85,183 $85,377 $57,883 $57,929
Accumulated
depreciation (48,762) (46,704) (38,799) (36,271)

Net Plant $36,421 $38,673 $19,084 $21,658

e. Depreciation

Provisions at composite straight-line depreciation rates,
excluding decommissioning costs discussed as follows,
approximate the following percentages of the cost of
depreciable property: electric, 3.4 percent in 1997 and
3.3 percent in 1996 and 1995; gas, 3.4 percent in 1997
and 1996 and 3.5 percent in 1995. Depreciation rates are
approved by the Public Service Commission of Wisconsin
(PSCW) and are generally based on the estimated economic
lives of property.

Nuclear decommissioning costs are being accrued to an
end-of-service life of 2002 for Kewaunee. These costs are
currently recovered from customers in rates and are
deposited in external trusts. For 1997, the
decommissioning costs recovered in rates were
$4.9 million.

Decommissioning costs are recovered through depreciation
expense, excluding earnings on the trusts. Net earnings
on the trusts are included in other income. The long-
term, after-tax earnings assumption on these trusts is
5.6 percent. As of December 31, 1997, the decommissioning
trusts, totaling $59.2 million, are shown on the balance
sheet in the utility plant section and offset by an equal
amount under accumulated provision for depreciation.

The Company's share of Kewaunee decommissioning costs is
estimated to be $78.8 million in current dollars based on
a site-specific study performed in 1992 using immediate
dismantlement as the method of decommissioning.
Decommissioning costs as studied are assumed to inflate
at an average rate of 6.0 percent. Physical
decommissioning is expected to occur during the period
2014 through 2021, with additional expenditures being
incurred during the period 2022 through 2039 related to
the storage of spent nuclear fuel at the plant site.

f. Income Taxes

Total income taxes in the Consolidated Statements of
Income are as follows:

(Thousands of dollars) 1997 1996 1995

Income taxes charged to
operations $11,940 $12,553 $14,285
Income taxes charged to
other income 1,571 (7,942) 786
Total income taxes $13,511 $ 4,611 $15,071

Total income taxes consist of the following provision
(benefit) components for the years ended December 31:

(Thousands of 1997 1996 1995
dollars)
Currently payable
Federal $12,229 $9,317 $14,602
State 3,435 3,267 3,679
Net deferred
Federal (1,308) (7,079) (2,217)
State (92) (102) (225)
Amortized investment
tax credits (753) (792) (768)
Total income taxes $13,511 $ 4,611 $15,071

Deferred income taxes are provided to reflect the
expected tax consequences of temporary differences
between the tax basis of assets and liabilities and their
reported amounts in the financial statements. Investment
tax credits from regulated operations are amortized over
the service lives of the property to which they relate.

The differences between the federal statutory income tax
rate and the Company's effective rate are as follows:
<PAGE>
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Statutory federal income tax rate 35.0% 35.0% 35.0%
Amortized investment tax credits (2.1) (7.2) (2.0)
State income taxes, net of
federal benefit 5.9 7.3 5.8
Valuation allowance (0.2) 10.9 -
Other, individually insignificant (1.1) (4.2) (0.2)
Effective income tax rate 37.5% 41.8% 38.6%
</TABLE>
<PAGE>
The significant components of deferred tax liabilities
(assets) that appear on the Consolidated Balance Sheets
as of December 31 are as follows:

(Thousands of dollars) 1997 1996

Property-related $57,951 $59,522
Other 6,026 6,788
Gross deferred income tax
liabilities 63,977 66,310
Accrued expenses (6,344) (7,629)
Other (3,166) (3,311)
Deferred tax regulatory (9,983) (9,598)
account
Gross deferred income tax
assets (19,493) (20,538)
Less valuation allowance 1,088 1,200
Net deferred income tax
assets (18,405) (19,338)
Deferred income taxes $ 45,572 $ 46,972

Excess deferred income taxes, resulting chiefly from
taxes provided at rates higher than current rates, have
been recorded as a net regulatory liability ($24.9
million and $23.9 million at December 31, 1997 and 1996,
respectively), refundable through future rates.

As discussed in Note 4, on page F-17, the Company's
nonregulated gas marketing subsidiaries have entered into
a joint venture with an unrelated third party.
Realization of state deferred tax assets including net
operating loss carryforwards of these subsidiaries is
dependent on future income of the joint venture in states
where the subsidiaries file separate tax returns. Due to
the circumstances associated with these temporary
differences, a valuation allowance was established at
December 31, 1997 and 1996, for these deferred tax
assets.

For tax purposes, these subsidiaries, as of December 31,
1997, had approximately $10.4 million of state tax net
operating loss carryforwards which expire, if unused, in
the year 2012.

g. Pension Plans

The Company maintains two defined benefit plans for its
employees. The pension benefit formula used in the
determination of pension costs is based on the average
compensation earned during the last five years of
employment for the salaried plan and career earnings for
the nonsalaried plan subject to a monthly maximum.

Effective January 1, 1995, the Company began recovering
pension costs in customer rates under Statement of
Financial Accounting Standard (SFAS) No. 87, "Employers'
Accounting for Pensions." Prior to this date, pension
costs were recovered in rates as funded. The plans'
assets are in a master trust with a bank.

The funded status of the plans at December 31 is as
follows:

(Thousands of dollars) 1997 1996

Fair value of plan assets $70,298 $58,770

Actuarial present value of
benefits rendered to date -
Accumulated benefits based on
compensation to date, including
vested benefits of $47,958 and
$40,840 respectively 54,025 46,019
Additional benefits based on
estimated future salary levels 11,085 9,093

Projected benefit obligation $65,110 $55,112

Plan assets greater than
projected benefit obligation 5,188 3,658
Unrecognized net (gain) (6,390) (5,381)

Unrecognized prior service cost 1,140 1,004

Net liability $ (62) $ (719)

Components of net pension costs for the years ended December 31 are:

(Thousands of dollars) 1997 1996 1995

Service costs (benefits
earned during the period) $1,616 $1,715 $1,416
Interest costs on projected
benefit obligation 4,421 4,090 3,724
Actual return on plan (12,244 (7,302) (10,033)
Net amortization and
Net pension costs $649 $1,056 $1,573

The assumed rates for calculations used in the above tables
were:

1997 1996 1995
Expected long-term rate of
return on plan assets 9.50% 9.50% 9.50%
Average rate of increase in
salaries 5.00% 5.00% 5.00%
Weighted average discount
rate 7.25% 7.75% 7.25%

In addition to the noted plans, the Company also
maintains two defined-contribution 401(k) benefit plans
for its employees. The Company's costs of the 401(k) plan
was $0.3 million in 1997 and $0.2 million in years 1996
and 1995.

h. Postretirement Benefits Other Than Pensions

The Company provides health care and life insurance
benefits for its retired employees, and substantially all
of the Company's employees may become eligible for these
benefits upon retirement. These benefits are accrued over
the period in which employees provide services to the
Company.

The Company has elected to recognize the cost of its
transition obligation (the accumulated postretirement
benefit obligation as of January 1, 1993) by amortizing
it on a straight-line basis over 20 years. The Company's
obligation and costs are based on a discount rate of
7.25 percent in 1997, 7.75 percent in 1996, and
7.25 percent in 1995. The net periodic benefit costs for
the years 1997 through 1995 were based on an assumed
long-term rate of return on plan assets of 9.5 percent.
The assumed rate of increase in health care costs
(health-care-cost trend rate) is 10 percent in 1997,
decreasing gradually to 5 percent in 2003 and remaining
constant thereafter. Increasing the health-care-cost
trend rates of future years by one percentage point would
increase the accumulated postretirement benefit
obligation by $2.8 million and would increase annual
aggregate service and interest costs by $0.4 million.

The Company's policy is to fund the obligation to the
yearly maximum through tax-advantaged vehicles. The
plan's assets are in trust or on reserve with an
insurance company.

The funded status of the plan at December 31 is as follows:

(Thousands of dollars) 1997 1996

Accumulated postretirement
benefit obligation (APBO):
Retirees $(4,122) $(4,192)
Fully eligible active plan
participants (2,091) (1,662)
Other active plan
participants (9,570) (8,526)
Total $(15,783) $(14,380)
Plan assets at fair value 4,467 3,602
APBO in excess of plan assets (11,316) (10,778)
Unrecognized transition
obligation 6,511 6,945
Unrecognized prior service
costs 2,111 2,000
Unrecognized gain (1,832) (1,825)
Accrued postretirement
benefit liability $(4,526) $(3,658)

Components of net periodic benefit costs for the years
ended December 31 are as follows:

(Thousands of dollars) 1997 1996 1995

Service cost $490 $546 $429
Interest cost on APBO 1,062 1,062 989
Actual return on plan
assets (388) (287) (177)
Net amortization and
deferral 583 622 606
Regulatory effect based
on phase in - 402 95
Net periodic benefit
cost $1,747 $2,345 $1,942

i. Fair Value of Financial Instruments

At December 31, 1997, the carrying amount of cash and
cash equivalents approximates fair value. The estimated
fair market value of the Company's First Mortgage Bonds
and other long-term debt, based on quoted market prices
at December 31, is as follows:

(Thousands of dollars) 1997 1996

Carrying amount
(includes sinking
funds) $131,175 $130,175
Fair market value $137,611 $136,332

2. Capitalization Matters

a. First Mortgage Bonds and Other Long-Term Debt

On April 18, 1997, the Company purchased on the open
market $3.8 million of its 7.70%, 2028 series, First
Mortgage Bonds. The Company purchased these bonds at a
discount and later retired them. On June 10, 1997, the
Company entered into a fixed interest rate agreement in a
principal amount of $5.0 million at 6.91%, maturing on
June 10, 2004.

The annual sinking fund requirements of the outstanding
First Mortgage Bonds is $0.2 million in 1998 through
2002.

b. Preferred Stock

The Company has 1,175,000 shares of $25 par value
redeemable preferred stock, cumulative, that is
authorized but unissued at December 31, 1997.

c. Notes Payable to Banks, Commercial Paper, and Lines of
Credit

For short-term borrowings, the Company generally issues
commercial paper (issued at the prevailing discount rate
at the time of issuance) which is supported by unused
bank lines of credit. Through negotiations with several
banks, the Company had $52 million in bank lines of
credit.

Information concerning short-term borrowings for the years
is set forth below:

(Thousands of dollars)
December 31: 1997 1996 1995

Available lines of credit
(MGE) $52,000 $45,000 $35,000
Available lines of credit
(GLENCO) $ - $10,000 $ 5,000
Commercial paper outstanding $33,500 $29,750 $20,500
Weighted average interest
rate 6.06% 5.63% 5.86%
During the year:
Maximum short-term
borrowings $33,500 $29,750 $28,600
Average short-term
borrowings $16,816 $13,805 $16,091
Weighted average interest
rate 5.68% 5.53% 6.03%

3. Rate Matters

The Company received an interim rate order from the PSCW in
March 1997. Effective with the order, the Company collected
a 0.507 cents per kilowatt-hour surcharge on customers'
bills to cover costs incurred by the Company while Kewaunee
remained out of service. Additional replacement power costs
in the amount of about $1.0 million per month were recovered
through the customer surcharge during the period March 6,
1997, through July 1, 1997.

In August 1997, the PSCW's rate order became effective
increasing electric rates $4.9 million, or 3.1 percent, and
natural gas rates $3.5 million, or 3.5 percent. These rates
will remain in place until the next test year, which is
scheduled to begin January 1, 1999. These current rates are
based on an authorized return on common stock equity of 12.0
percent. The proposed early recovery of the Kewaunee
investment and accelerated decommissioning collections are
the primary reasons for the increase in electric rates. Gas
rates increased due to substantial technology upgrades and
infrastructure improvements as well as higher operating
costs due to inflation. Prior to the recently approved
increases, electric rates had not been increased since 1990
and were reduced in 1993 and 1994. Gas rates had not been
increased since 1989 and were reduced in 1990, 1992 and
1993.

The co-owners of Kewaunee filed an application with the PSCW
in November 1997 for a customer surcharge to recover costs
associated with the 1997 steam generator repairs. The
Company's portion of these costs is approximately $1.8
million (excluding carrying costs). The Company requested
recovery of these costs through a customer surcharge which
would be collected over a four-month period in 1998. The
PSCW approved, at its open meeting on March 19, 1998, the
Company's request for a customer surcharge relating to
recovery of 1997 steam generator repair costs.

4. Gas Marketing Subsidiaries

In December 1996, the Company wrote down its investment in
both Great Lakes Energy Corp. (GLENCO) and American Energy
Management Inc. (AEM), the Company's gas marketing
subsidiaries, to properly reflect current value. The write
down resulted in an after-tax charge to income of $10.4
million. As of December 31, 1997, a $4.8 million liability
remains to account for the remaining commitment and
contingencies related to this writedown. GLENCO and AEM
formed a joint venture with another gas marketing company
effective January 1, 1997. The joint venture is called
National Energy Management L.L.C. and is based in Chicago.

Also in December 1996, the Company had a one-time after-tax
charge of $1.6 million on net income. The charge resulted
from a refund to the Company's natural gas customers. Under
a sharing mechanism with GLENCO, an economic benefit based
on GLENCO's net income was passed back to the Company's
natural gas utility customers.

5. Commitments

Utility plant construction expenditures for 1998, including
the Company's proportional share of jointly owned electric
power production facilities and purchases of fuel for
Kewaunee, are estimated to be $46 million and substantial
commitments have been incurred in connection with such
expenditures. Significant commitments have also been made
for fuel for Columbia.

6. Segments of Business

The table below presents information pertaining to the
Company's segments of business. Information regarding the
distribution of net assets between electric and gas for the
years ended December 31 is set forth on page II-2.
<PAGE>
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
<S> <C> <C> <C>
Electric Operations

Total revenues $163,123 $152,747 $153,554
Operation and maintenance
expenses 100,854 90,862 89,994

Depreciation and
amortization 22,799 20,094 19,503

Other general taxes 6,937 7,000 6,908
Pre-tax Operating
Income $ 32,533 $ 34,791 $ 37,149

Income taxes 9,106 10,221 11,193

Net Operating Income $ 23,427 $ 24,570 $ 25,956
Construction and Nuclear
Fuel Expenditures
(Electric) $ 16,849 $ 16,855 $ 14,006

Gas Operations

Operating revenues $101,525 $100,544 $ 95,036

Revenues from sales to
electric utility 6,038 2,304 3,100

Total Revenues 107,563 102,848 98,136

Operation and maintenance
expenses 89,788 86,418 80,017

Depreciation and
amortization 5,518 5,416 5,312

Other general taxes 1,860 1,736 1,801

Pre-tax Operating
Income 10,397 9,278 11,006

Income taxes 2,834 2,332 3,091

Net Operating Income $ 7,563 $ 6,946 $ 7,915

Construction Expenditures
(Gas) $ 4,786 $ 5,051 $ 5,156
</TABLE>
<PAGE>
7. Supplemental Cash Flow Information

For purposes of the Consolidated Statements of Cash Flows,
the Company considers cash equivalents to be those
investments that are highly liquid with maturity dates of
less than three months.

Cash payments for interest and income taxes for the years
ended December 31 were as follows:

(Thousands of
Dollars) 1997 1996 1995

Interest
paid, net of
amounts
capitalized $10,841 $10,932 $11,894

Income taxes
paid, net $15,365 $16,041 $18,016

8. Regulatory Assets and Liabilities

Pursuant to SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation," the Company capitalizes, as
deferred charges, incurred costs that are expected to be
recovered in future electric and natural gas rates. The
Company also records as other credits, obligations to
customers to refund previously collected revenue or to spend
revenue collected from customers on future costs. The
Company's regulatory assets and liabilities, included in
deferred charges and credits on the balance sheet, consisted
of the following as of December 31:

<PAGE>
<TABLE>
<CAPTION>
1997 1996
(Thousands of Dollars) Assets Liabilities Assets Liabilities
<S> <C> <C> <C> <C>
Demand-side management $10,052 $ 759 $12,284 $ 728

Decommissioning and
decontamination 2,300 2,211 2,403 2,403

Unamortized debt
expense 5,072 - 5,260 -

Other postretirement
benefits 58 4,567 - 3,481

Kewaunee
outage/repairs 2,052 933 - -

Summer power shortages 1,704 - - -

Subtotal regulatory
assets/liabilities 21,238 8,470 19,947 6,612

Other deferred items 6,840 10,745 10,199 9,236

Subtotal deferred
items 28,078 19,215 30,146 15,848

Regulatory liability -
SFAS 109 - 24,875 - 23,914

TOTAL $28,078 $44,090 $30,146 $39,762
</TABLE>
<PAGE>
PART III.

Item 10. Directors and Executive Officers of the Registrant

Information concerning the Directors of the Company is contained
in the definitive proxy statement under the section "Election of
Directors" filed on March 23, 1998, with the Securities and
Exchange Commission, which is incorporated herein by reference.
<PAGE>
<TABLE>
Executive Officers of the Registrant (elected annually by Directors)
<CAPTION>
Effective Service Years
Executive Title Date as an Officer
<S> <C> <C> <C>
David C. Mebane Chairman, President and CEO 05/09/94 17
Age: 64 President, CEO and COO 01/01/94
President and COO 10/01/91

Mark C. Williamson Senior Vice President - Energy Services 05/01/95 6
Age: 44 Vice President - Energy Services 05/03/93
Assistant Vice President - Energy Services 11/01/92
Gary J. Wolter Senior Vice President - Administration and 7
Age: 43 Secretary 05/01/95
Vice President - Administration and Secretary
12/01/91

Ronald L. Semmann Group Vice President 01/01/98 1
Age: 62 Vice President - Human Resources 07/18/97
Special Assistant to the Chairman 05/12/97

James C. Boll Vice President - Law and Corporate 5
Age: 62 Communications 10/20/95
Assistant Vice President - Law and Corporate
Comms. 05/03/93
Executive Director - Law and Corporate Comms.
01/13/92

Terry A. Hanson Vice President - Finance 11/01/97 7
Age: 46 Vice President and Treasurer 10/01/96
Treasurer 12/01/91

Lynn K. Hobbie Vice President - Marketing 05/01/96 4
Age: 39 Assistant Vice President - Marketing 11/01/94
Senior Director - Marketing 07/01/93
Director - Market Planning and Programs 11/01/92

Thomas R. Krull Vice President - Gas and Electric Operations 5
Age: 48 Vice President - Electric Transmission and 11/01/97
Distribution
Assistant Vice President - Electric Trans. and 05/01/96
Dist.
Executive Director -Electric Transmission and 05/03/93
Dist.

Peter J. Waldron Vice President - Power Supply Ops. and Eng. 04/23/97 2
Age: 40 Assistant Vice President - Power Supply Ops. and
Eng. 05/01/96
Executive Director - Power Supply Ops. and Eng. 10/01/95
Senior Director - Power Supply Ops. and Eng. 12/01/94
Director - Power Supply Ops. and Eng. 04/01/93
Manager - Power Supply Ops. and Eng. 02/01/92

Jeffrey C. Newman Treasurer 11/01/97 1
Age: 35 Executive Director - Budgets and Financial
Management 05/01/96
Director - Budgets and Financial Management 08/01/92

Scott A. Neitzel Assistant Vice President - Gas Rates and Fuels 08/04/97 1
Age: 37

Joe R. Trueblood Assistant Vice President - Gas Operations 11/01/97 1
Age: 63 Director - Gas System Planning and Construction 05/01/92

Carol A. Wiskowski Assistant Vice President - Admin. and Assistant 19
Age: 58 Secretary 05/01/92
</TABLE>
<PAGE>
Item 11. Executive Compensation

See Item 12 below.

Item 12. Security Ownership of Certain Beneficial Owners and
Management

The required information for Items 11 and 12 is included in the
Company's definitive proxy statement under the section "Executive
Compensation," not including "Report on Executive Compensation"
and "Company Performance," and under the section "Beneficial
Ownership of Common Stock by Directors and Executive Officers"
filed with the Securities and Exchange Commission on March 23,
1998, which is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

None.

<PAGE>
PART IV.

Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K

1a. Financial statements (consolidated, as of December 31, 1997
and 1996, and for each of the three years in the period
ended December 31, 1997). Included in Part II, Item 8, of
this report:

- Responsibility for Financial Statements
- Report of Independent Accountants
- Statements of Income and Retained Income
- Statements of Cash Flows
- Balance Sheets
- Statements of Capitalization
- Notes to Consolidated Financial Statements

b. Financial statement schedules.

None.

2. All exhibits including those incorporated by reference.

Exhibits (an asterisk (*) indicates a management contract or
compensatory plan or arrangement):

No. Description of document

3.(i)Articles of Incorporation as in effect at May 6, 1996.
(Incorporated by reference to Exhibit 3.(i) with 1996 10-K
in File No. 0-1125.)

3.(ii)By-Laws as in effect at January 1, 1991. (Incorporated
by reference to Exhibit 3B with 1991 10-K in File No. 0-
1125.)

4A Indenture of Mortgage and Deed of Trust between the
Company and Firstar Trust Company, as Trustee, dated as of
January 1, 1946, and filed as Exhibit 7-D to SEC File No. 0-
1125 and the following indentures supplemental thereto are
incorporated herein by reference:

Supplemental Dated Exhibit
Indenture as of No. SEC File No.

Tenth(1) 11/01/76 2.03 2-60227
Fourteenth 04/01/92 4C 0-1125 (1992 10-K)
Fifteenth 04/01/92 4D 0-1125 (1992 10-K)
Sixteenth 10/01/92 4E 0-1125 (1992 10-K)
Seventeenth 02/01/93 4F 0-1125 (1992 10-K)

No. Description of document

10A Copy of Joint Power Supply Agreement with Wisconsin
Power and Light Company and Wisconsin Public Service
Corporation dated February 2, 1967. (Incorporated by
reference to Exhibit 4.09 in File No. 2-27308.)

10B Copy of Joint Power Supply Agreement (Exclusive of
Exhibits) with Wisconsin Power and Light Company and
Wisconsin Public Service Corporation dated July 26,
1973, amending Exhibit 5.04. (Incorporated by reference
to Exhibit 5.04A in File No. 2-48781.)

10D Copy of revised Agreement for Construction and
Operation of Columbia Generating Plant with Wisconsin
Power and Light Company and Wisconsin Public Service
Corporation dated July 26, 1973. (Incorporated by
reference to Exhibit 5.07 in File No. 2-48781.)

10F* Form of Severance Agreement. (Incorporated by reference
to Exhibit 10F with 1994 10-K in File No. 0-1125.)

12 Statement regarding computation of ratios (page II-2).

21 Subsidiaries of the Registrant.

23 Consent of Independent Accountants.

27 Appendix E to Item 601(c) of Regulation S-K: Public
Utilities Companies Financial Data Schedule UT.

3. Reports on Form 8-K - No Current Report on Form 8-K was
filed for the quarter ended December 31, 1997. <PAGE>
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

MADISON GAS AND ELECTRIC COMPANY
(Registrant)

Date: March 23, 1998 /s/ David C. Mebane
David C. Mebane
Chairman, President and Chief
Executive Officer

Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities indicated on
March 23, 1998.

/s/ David C. Mebane Chairman, President and Chief
Executive Officer and Director
(Principal Executive Officer)

/s/ Terry A. Hanson Vice President - Finance
(Principal Financial Officer and
Principal Accounting Officer)

/s/ Frank C. Vondrasek Vice Chairman and Director

Jean Manchester Biddick Director

/s/ Richard E. Blaney Director

/s/ Regina M. Millner Director

/s/ Frederic E. Mohs Director

/s/ Phillip C. Stark Director

/s/ H. Lee Swanson Director

Exhibit No. 21

Madison Gas and Electric Company and Consolidated Subsidiaries

SUBSIDIARIES OF THE REGISTRANT

As of December 31, 1997, the Company owned 100 percent of the
voting securities of the following subsidiaries (all Wisconsin
corporations):

- - MAGAEL INC. - holds title to property acquired by the Company
for future utility plant expansion and nonutility property.

- - Central Wisconsin Development Corporation - assists new and
expanding businesses throughout Central Wisconsin by
participating in planning, financing, property acquisition,
joint ventures, and associated activities.

- - Great Lakes Energy Corp. - formed a joint venture on January
1, 1997, with American Energy Management, Inc., and another
gas marketing company that markets fuels and energy services
to commercial and industrial customers. (See Item 7, page II-
6, and Item 8, page F-17, for further discussion.)

- - Wisconsin Resources Corporation - Inactive.

- - North Central Technologies, Inc. - Inactive.

- - Mid America Technologies, Inc. - Inactive.

As of December 31, 1997, Great Lakes Energy Corp. owned 100
percent of the voting securities of the following subsidiary (a
Wisconsin corporation):

- - American Energy Management, Inc. - formed a joint venture on
January 1, 1997, with Great Lakes Energy Corp. and another gas
marketing company that markets nonregulated energy services,
including the purchase and transportation of natural gas and
other fuels for commercial and industrial customers. (See
Item 7, page II-6, and Item 8, page F-17, for further
discussion.)

Exhibit No. 23

CONSENT OF INDEPENDENT ACCOUNTANTS

We consent to the incorporation by reference in the registration
statements of Madison Gas and Electric Company on Form S-3
(Registration No. 33-52491 and Registration No. 33-24115) of our
report dated February 6, 1998, on our audits of the consolidated
financial statements of Madison Gas and Electric Company as of
December 31, 1997 and 1996, and for the years ended December 31,
1997, 1996, and 1995, which report is included in this annual
report on Form 10-K.

/s/ Coopers & Lybrand L.L.P.
Milwaukee, Wisconsin

<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from SEC Form
10-K. Items 1 through 22 are as of December 31, 1997. Items 23 through 38 are
for the twelve months ended December 31, 1997.
</LEGEND>
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 363,093
<OTHER-PROPERTY-AND-INVEST> 8,252
<TOTAL-CURRENT-ASSETS> 72,367
<TOTAL-DEFERRED-CHARGES> 28,078
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 471,790
<COMMON> 16,080
<CAPITAL-SURPLUS-PAID-IN> 112,558
<RETAINED-EARNINGS> 52,285
<TOTAL-COMMON-STOCKHOLDERS-EQ> 180,923
0
0
<LONG-TERM-DEBT-NET> 129,923
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 33,500
<LONG-TERM-DEBT-CURRENT-PORT> 200
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 127,244
<TOT-CAPITALIZATION-AND-LIAB> 471,790
<GROSS-OPERATING-REVENUE> 264,648
<INCOME-TAX-EXPENSE> 11,940
<OTHER-OPERATING-EXPENSES> 221,718
<TOTAL-OPERATING-EXPENSES> 233,658
<OPERATING-INCOME-LOSS> 30,990
<OTHER-INCOME-NET> 2,257
<INCOME-BEFORE-INTEREST-EXPEN> 33,247
<TOTAL-INTEREST-EXPENSE> 10,724
<NET-INCOME> 22,523
0
<EARNINGS-AVAILABLE-FOR-COMM> 22,523
<COMMON-STOCK-DIVIDENDS> (20,689)
<TOTAL-INTEREST-ON-BONDS> 8,758
<CASH-FLOW-OPERATIONS> 40,839
<EPS-PRIMARY> 1.40
<EPS-DILUTED> 1.40

</TABLE>