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, 1996

                                     or

 [ ] 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                               39-0444025
     (State or other jurisdiction of               (IRS Employer
     incorporation or organization)              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) 
<PAGE>
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: $345,713,937 based on a closing bid price of $21.50 on
March 1, 1997 (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.

- 1996 Annual Report to Shareholders (Parts I, II, and IV)

- Definitive Proxy Statement filed on March 24, 1997 (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 National Gas and Electric L.P. (NG&E). The joint venture
will market natural gas and energy services to industrial and commercial
customers in the Great Lakes region. The joint venture is called National
Energy Management, L.L.C. and is based in Chicago. (See Item 7, page II-7, and
Item 8, page F-16, 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. 
<PAGE>
For example, the ongoing issue of global warming could result in significant
compliance cost for carbon dioxide emission reductions. Except as set forth
below, the amounts of such expenditures and the period of time over which they
may be required to be made are not known. The Company is unable to predict
whether compliance with future pollution control regulations would involve
curtailments of operations or reductions in generating capacity or efficiency
of present generating facilities or delays in the construction and operation
of future generating facilities.

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

Electric Operations

At December 31, 1996, the Company supplied electric service to 121,959
customers, of whom 109,009 were located in the cities of Fitchburg, Madison,
Middleton, and Monona, and 12,950 in adjacent areas. Of the total number of
customers, 105,848 were residential and 15,972 were commercial. For 1996,
residential and commercial electric service revenues comprised 35 and
49 percent, respectively, of total electric revenues. The remaining electric
revenues during 1996 were from industrial sales (7 percent), sales to public
authorities including the University of Wisconsin (9 percent), and sales to
other utilities (less than 1 percent). The electric operations accounted for
60 percent of the total revenues of the Company.

See Item 2 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.

In December 1995, the PSCW outlined its plan for the restructuring of the
electric utility industry in Wisconsin. This plan was largely consistent with
the plan proposed by the Company. The PSCW's plan was presented by the
Commissioners to the state legislature and included a work plan and a series
of dockets and proceedings over the next several years to implement the work
plan. (See Item 7, page II-10, Electric Industry Trend for further
discussion.) 
<PAGE>
Fuel supply and generation

The Company estimates its net kilowatt-hour requirements for 1997 will be
provided from the following sources: 69 percent from fossil-fueled steam
plants, 9 percent from a nuclear-fueled steam plant, 19 percent from low-cost
power purchases, and 3 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 decreased from 40 days on
December 31, 1995, to 30 days on December 31, 1996, due to lower-planned
inventories and higher-than-anticipated coal burns with the extended shutdown
of Kewaunee for the repair of the steam generator tubes, as explained below.
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 began commercial operation in 1974. The Kewaunee capability
factor was 71.3 percent in 1996, compared to a projected industry average of
79.8 percent. The capability factor is the percentage of maximum energy
generation a plant is capable of supplying to the electrical grid limited only
by factors within the control of plant management. The comparable amounts for
1995 were 83.1 and 84.5 percent, respectively. The lower Kewaunee percentage
for 1996 reflects the extended shutdown of Kewaunee for the repair of the
steam generator tubes.

Kewaunee was removed from service on September 21, 1996, for scheduled
refueling and maintenance. Inspection of previously repaired steam generator
tubes disclosed more extensive tube damage than had been anticipated. Repair
of the tubes using laser welding was undertaken. As of December 31, 1996, it
was anticipated repairs would be completed sometime during the first quarter
of 1997. Welding was completed late in January 1997. Subsequent testing
indicated the repair of a number of the tubes was not effective. After further
inspection and laboratory testing, it is now planned to undertake additional
repairs which could allow Kewaunee to return to service sometime in mid-1997. 
<PAGE>
The additional repairs involve removing metal sleeves previously installed to
repair the parent tubes. New, slightly longer sleeves will be installed to
cover the areas of concern in the original steam generator tubes. The
operating company believes the NRC will approve this repair process because it
only requires minor changes to the presently approved sleeving process. The
cost of the additional repairs is expected to be between $4.5 million and
$10.0 million, depending on the number of previously repaired sleeves that can
remain in service. The Company's share of the costs is in the range of
$0.8 million to $1.8 million.

At its open meeting, the PSCW approved deferred accounting treatment for steam
generator repair costs at Kewaunee incurred on or after March 20, 1997.

All three owners have approached the PSCW for recovery of the additional
repair costs in customer rates. The Company's portion of the additional power
costs resulting from the extended shutdown of Kewaunee are presently being
recovered from customers through an interim rate order. Returning Kewaunee to
service would provide needed power supply during the summer months when the
demand for electricity is usually high.

If for any reason the steam generators cannot be repaired, the Kewaunee owners
would need to decide on alternatives ranging from replacing the existing steam
generators to early plant closure with replacement power options. Replacement
of steam generators must 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.

If Kewaunee remains in operation until expiration of the operating license,
physical decommissioning is expected to occur during the period 2014 through
2021 with additional expenditures being incurred during the period 2022
through 2050 related to the storage of spent nuclear fuel at the site. In July
1994, the PSCW issued an order covering all Wisconsin utilities with nuclear
generation. The order standardizes cost escalation assumptions used in
determining decommissioning liabilities. Based on this methodology and
considering other assumption changes, Kewaunee decommissioning costs are
estimated to be $398.0 million in current dollars and $1.9 billion in
year-of-expenditure dollars. The Company's share of Kewaunee decommissioning
costs is estimated to be $70.8 million in current dollars and $338.2 million
in year-of-expenditure dollars. These costs are recovered currently in
customer rates and deposited in external trusts. As of December 31, 1996, the
Company's external trusts totaled $44.6 million (fair market value). (See
Item 7, page II-9, for further detailed discussion of Kewaunee.) 
<PAGE>
The supply of nuclear fuel for Kewaunee requires the purchase of uranium
concentrates, the conversion of uranium concentrates to uranium hexafluoride,
enrichment of the uranium hexafluoride, and fabrication of the enriched
uranium into usable fuel assemblies. After a region of spent fuel
(approximately one-third of the nuclear fuel assemblies in the reactor) is
removed from the reactor, it is placed in temporary storage in a spent fuel
pool at the plant site. Permanent storage is addressed below. There are
presently no operating facilities in the United States that are reprocessing
commercial nuclear fuel. A discussion of the nuclear fuel supply for Kewaunee
follows.

- Requirements for uranium are met through spot or contract purchases. An
  inventory policy, which takes advantage of economical spot market purchases
  of uranium, results in inventories sufficient for up to two reactor reloads
  of fuel, excluding in-process uranium.

- Uranium hexafluoride from inventory and from spot market purchases was used
  to satisfy converted material requirements in 1996. The co-owners intend to
  purchase future conversion services on the spot market but have contracts
  with primary suppliers for services in 1997, 1998, and 1999.

- In 1996, enrichment services were procured from COGEMA, Inc., pursuant to a
  contract executed in 1983 and last amended in 1995. Enrichment services can
  be purchased from the United States Enrichment Corporation (USEC) under the
  terms of the utility services contract which is in effect for the life of
  Kewaunee. The co-owners are committed to take 70 percent of its annual
  enrichment requirements in 1997 and, in alternate years thereafter, from
  USEC.

- Fuel fabrication services through March 15, 2001, are covered by contract
  with Siemens Power Corporation.

- Beyond the stated periods set forth above, additional contracts for uranium
  concentrates, conversion to uranium hexafluoride, enrichment, fabrication,
  and spent fuel storage will have to be procured. The co-owners anticipate
  the prices for the foregoing will modestly increase. 
<PAGE>
Pursuant to the Nuclear Waste Policy Act of 1982 (Nuclear Policy Act), the
U.S. Department of Energy (DOE) entered into a contract with the co-owners to
accept, transport, and dispose of spent nuclear fuel beginning no later than
January 31, 1998. The DOE has announced it will delay the acceptance of spent
nuclear fuel beyond 1998. A fee to offset the costs of the DOE's disposal for
all spent fuel used since April 7, 1983, has been assessed by the DOE at one
mill per net kilowatt-hour of electricity generated and sold by Kewaunee. An
additional one-time fee was paid to the DOE for disposal of spent nuclear fuel
used to generate electricity prior to April 7, 1983. Spent fuel is currently
stored at Kewaunee. The existing capacity of the spent fuel storage facility
will enable storage of the projected quantities of spent fuel through April
2001. The co-owners are evaluating options for the storage of additional
quantities beyond 2001. Several technologies are available. An investment of
approximately $2.5 million in the early 2000s could provide additional storage
sufficient to meet spent fuel storage needs until expiration of the current
operating license in 2013.

The Nuclear Policy Act provides that both the federal government and the
nuclear utilities fund the decontamination and decommissioning of the three
gaseous diffusion plants in the United States. Utility contributions will be
collected through a special assessment based on a utility's percentage of
uranium enrichment services purchased through the date of enactment compared
to total enrichment sales by the DOE. The co-owners of Kewaunee are required
to pay approximately $19.9 million in current dollars over a period of 15
years. At December 31, 1996, the remaining liability was $13.5 million of
which the Company's share was $2.4 million. The payments are subject to
adjustment for inflation.

In 1995, Yankee Atomic Electric Company (Yankee Atomic) received a U.S. Court
of Federal Claims decision that Yankee Atomic was entitled to a refund from
the DOE of $3.0 million paid to the Decontamination and Decommissioning Fund.
The court ruled that by entering into contracts with utilities, the government
agreed to charge certain prices for uranium enrichment services that could not
be legislatively changed after performance and payment were completed. The
Yankee Atomic decision addresses only a refund to Yankee Atomic. Based on the
Yankee Atomic decision, the co-owners have filed a claim against the DOE for a
refund of its payments to the Decontamination and Decommissioning Fund.

Utility customers of the USEC have challenged the pricing of enrichment
services, subsequent to the Energy Policy Act of 1992. The position of the
utilities is that the charges by the USEC are higher than the terms of the
contracts originally entered into with the DOE. The co-owners have filed a
claim that has been denied by the USEC. Subsequently, a complaint was filed in
the U.S. Court of Federal Claims. Action on this complaint by the Claims Court
is expected after the Court of Appeals rules in the Yankee Atomic case. 
<PAGE>
If for any reason Kewaunee was forced to permanently suspend operations,
fuel-related obligations are as follows: (1) there are no financial penalties
associated with present uranium supply, conversion service, and enrichment
agreements, and (2) the fuel fabrication contract contains force majeure and
termination for convenience provisions. The maximum exposure could be as much
as $550,000 as of the end of 1996. Uranium inventories could be sold on the
spot market.

The Low-Level Radioactive Waste Policy Act of 1980 specifies that states may
enter into compacts to provide for regional low-level waste disposal
facilities. Wisconsin is a member of the Midwest Low-Level Radioactive Waste
Compact. The state of Ohio has been selected as the host state for the Midwest
Compact and is proceeding with the preliminary phases of site selection. In
July 1995, the Barnwell, South Carolina, disposal facility again began to
accept low-level radioactive waste materials from outside its region.

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 2 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. Phase II emission
compliance strategies and their costs are currently being evaluated. The
Company has prevailed in legal proceedings in the United States Court of
Appeals for the 7th Circuit against the Environmental Protection Agency (EPA)
to require the EPA to award the Company bonus credits for SO2 emissions under
the Clean Air Act. The Court of Appeals ordered the EPA to review its
disallowance of bonus credits. The Company has prevailed and should receive
additional SO2 credits from the EPA in the near future.

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. 
<PAGE>
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 DNR's water toxic regulations could impose additional discharge
limitations on a number of previously unregulated substances. The Company is
in compliance with applicable standards.

Solid waste

From 1980 to 1984, the Company disposed of a fly-ash sludge at the Refuse
Hideaway Landfill in Middleton, Wisconsin. In October 1992, the EPA placed the
Refuse Hideaway Landfill on the national priorities Superfund list of sites
requiring clean up under the Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA). The scope of liability under CERCLA
is very broad.

Although the Company is listed as a potentially responsible party on the EPA's
roster of generators for the Refuse Hideaway Landfill and received a special
notice letter from the EPA on September 27, 1996, 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.

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. 
<PAGE>
The City of Madison has identified the Company as one of many possible
potential responsible parties 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, 1996, the Company supplied natural gas service to 105,392
customers in the cities of Elroy, Madison, Middleton, Monona, Fitchburg, Lodi,
Verona, and Viroqua; 21 villages; and all or parts of 40 townships. Revenues
received from residential and commercial customers accounted for 58 and
37 percent, respectively, of the total gas revenues for 1996. The gas
operations accounted for 40 percent of the total revenues of the Company.
Revenues from transportation service accounted for 2 percent of the total gas
revenues for 1996. Sales and revenues from best-efforts rate schedules
accounted for 6 and 3 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 1996 to 1997 heating season. In addition,
the Company can curtail gas deliveries to its interruptible customers.
Approximately 9 percent of gas sold in 1996 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. 
<PAGE>
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 1995 and continuing through March 1996) was
much colder than normal, which drove storage inventory levels to low levels.
Demand for natural gas remained high during the summer (April 1996 through
October 1996) as gas was injected into storage to replenish inventories. Gas
prices also remained relatively high. The beginning of the current heating
season (starting November 1996 through March 1997) was colder than normal,
which reduced storage inventories more than was desired. Gas prices escalated
until January 1997. When the weather became warmer than normal, the demand for
natural gas fell as did the price for natural gas. Storage inventories are at
normal levels.

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 2,389 dekatherms of firm transportation
service into Viroqua's NNG gate station and firm transportation service of
1,500 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 694 permanent employees at December 31, 1996.

Information regarding Company executive officers is included under Item 10 of
this report, page III-1, which information is incorporated herein by
reference. 
<PAGE>
Item 2.  Properties

The following table presents the generating capability in service at
December 31, 1996:

                      Commercial                     Net Capability  No. of
 Plants               Operation Date   Fuel            (Megawatt)     Units

 Steam plants

 Columbia             1975 & 1978      Low-sulfur coal    232 (1,2)     2

 Kewaunee             1974             Nuclear             93 (1,3)     1

 Blount (Madison)     1957 & 1961      Coal/gas            98           2
                      1938 & 1942      Gas                 40           2
                      1949             Coal/gas            23           1
                      1964-1968        Gas/oil             35           4

 Combustion turbines  1964-1973        Gas/oil             88           5

 Total                                                    609

1 Base load generation
2 Company's 22 percent share of two 527-mw units located near Portage,
  Wisconsin
3 Company's 17.8 percent share of 525-mw unit located near Kewaunee, Wisconsin

Major electric transmission and distribution lines and substations in service
at December 31, 1996, are as follows:

                                         Miles
 Lines                  Overhead Lines           Underground Lines

 Transmission
 345 kV                     124                          -
 138 kV                      96                          3
 69 kV                       66                         18
 Distribution
 13.8 kV and under        1,025                        734

                        Substation               Installed Capacity (kVA)

                        Transmission (22)               4,132,350
                        Distribution (33)                 361,700

Gas facilities include 1,861 miles of distribution mains and one propane air
plant capable of producing a maximum daily capacity
of 9,000 dekatherms of natural gas equivalent. 

<PAGE>
Item 3.  Legal Proceedings

The Company filed a suit January 3, 1996, in Dane County Circuit Court
charging WPL with violations of Wisconsin laws and rules in attempting to
provide electric service to the new Ho Chunk bingo parlor on the southeast
side of Madison. The Company also filed a complaint against WPL at the PSCW
for illegally duplicating electric facilities in the same area.

The Company claims that WPL intentionally misrepresented the Company's cost
for electric service to the Ho Chunk Nation, falsely advertised its services
to induce the Ho Chunk Nation to enter into a contract with WPL, and
improperly interfered with the Company's legal rights to serve that facility.

A decision from Dane County Circuit Judge Mark Frankel on March 10, 1997,
upheld a previous ruling by the PSCW, stating that the Company, not WPL, had
the right to provide electric service to the bingo parlor. This decision came
in response to WPL's appeal of last summer's PSCW ruling. In July 1996, the
PSCW ruled that WPL's extension of an electric distribution line to the bingo
parlor violated state law and that the Company was the only utility that could
legally serve the site. It also ordered WPL to remove the service extension.

Item 4.  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, 1997, was 18,245. The
Company's transfer agent and registrar is Harris Trust and Savings Bank,
Chicago, Illinois. The high and low sales prices for the common stock on
Nasdaq and the dividends paid per common share for each quarter for the past
two fiscal years are shown below.

                  Common stock price range
                            1996                   Dividends per share
                     High           Low                    1996

 First quarter     $27 1/2        $23 1/8                 $0.317

 Second quarter    $25 3/4        $21 1/2                 $0.317

 Third quarter     $23 3/4        $21 1/2                 $0.320

 Fourth quarter    $22 3/8        $19 5/8                 $0.320


                  Common stock price range
                            1995                  Dividends per share
                    High           Low                    1995

 First quarter     $21 7/8       $20 5/8                 $0.313

 Second quarter    $21 7/8       $20 1/2                 $0.313

 Third quarter     $22 5/8       $20 3/8                 $0.317

 Fourth quarter    $23 3/8       $21 7/8                 $0.317 

<PAGE>
<TABLE>
Item 6. Selected Financial Data
<CAPTION>
(In thousands of dollars, except
per-share amounts)
For the years ended December 31,               1996              1995             1994              1993              1992
<S>                                           <C>              <C>               <C>               <C>              <C>
          Summary of Operations
Operating Revenues:
   Electric                                   $152,747         $153,554          $149,665          $147,201         $142,646
   Gas                                         100,544           95,036            95,307            96,932           85,356
     Total                                     253,291          248,590           244,972           244,133          228,002
Operating expenses                             200,486          191,725           187,469           187,717          172,049
Other general taxes                              8,736            8,709             8,619             8,222            8,107
Income tax items                                12,553           14,285            14,822            13,964           12,784
   Net operating income                         31,516           33,871            34,062            34,230           35,062
Other (loss)/income (including allowance
for funds used during construction)            (14,177)           1,635             2,146             2,118            2,210
   Income before interest expense               17,339           35,506            36,208            36,348           37,272
Interest expense                                10,912           11,536            11,197            11,673           13,465
   Net income                                    6,427           23,970            25,011            24,675           23,807
Preferred dividends                                  -               64               471               489              506
   Earnings on common stock                      6,427          $23,906           $24,540           $24,186          $23,301
Average shares outstanding                      16,080           16,080            16,080            16,055           16,046
   Earnings per share                            $0.40            $1.49             $1.53             $1.51            $1.45
   Dividends paid per share                     $1.273           $1.260            $1.247            $1.227           $1.193
Ratio of earnings to fixed charges*               2.71             4.23              4.49              4.15             3.60

     At December 31,
         Assets
Electric                                      $315,022         $327,053          $323,870          $328,048         $325,510
Gas                                            116,723          119,968           118,210           114,626          106,837
Assets not allocated                            52,424           46,855            45,679            22,690           20,390
   Total                                      $487,759         $465,364          $452,737          $484,169         $493,876

     Capitalization
Common shareholders' equity                   $179,089         $193,137          $189,489          $184,995         $180,367
Redeemable preferred stock                           -                -             5,100             5,400            5,600
Long-term debt                                 128,886          129,048           130,800           120,396          122,363
Short-term debt                                 29,750           20,500            28,600            23,500           17,000
   Total Capitalization                       $353,989         $334,291          $325,330          $337,725         $342,685

* 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

Certain matters that are discussed in the Management's Discussion and Analysis
of Financial Condition and Results of Operations are forward-looking
statements and can generally be identified as such because the content
includes statements like the Company "believes," "anticipates," or "expects."
Such forward-looking statements are subject to certain risks and uncertainties
which could cause actual results to differ materially from those currently
anticipated.

RESULTS OF OPERATIONS

Earnings overview

Earnings from Madison Gas and Electric Company's (the Company) core utility
operations increased to $1.48 per share in 1996, compared to $1.42 in 1995.
Earnings from utility operations were higher despite $0.9 million (after tax)
of additional costs for 1996 related to the extended outage of the Kewaunee
Nuclear Power Plant (Kewaunee). The Company's consolidated earnings per share
were negatively impacted by the following items:
 
- A one-time charge of $10.4 million (after tax) to reflect the current value
  of the Company's investments in its gas marketing subsidiaries;

- A one-time charge of $1.6 million (after tax) resulting from a refund to
  natural gas customers under a sharing mechanism between Great Lakes Energy
  Corp. (GLENCO) and the Company; and

- Operating losses of the Company's gas marketing subsidiaries of
  $5.4 million (after tax).

Consolidated earnings per share of the Company's common stock decreased to
$0.40 in 1996, compared to $1.49 in 1995. The Company earned $1.0 million or
$0.07 per share on its gas marketing subsidiaries in 1995.

The consolidated earnings in 1995 of $1.49 per share were lower than the $1.53
earned in 1994 due to the costs associated with industry restructuring,
various regulatory filings in relation to the proposed utility mergers within
the state, and a lower authorized return on common stock equity, which became
effective in January 1995. 
<PAGE>
Electric sales and revenues

Electric retail sales for 1996 increased slightly from 1995, despite the cold
summer experienced in 1996 compared to 1995. The increase can be attributable
to an increase of 1.2 percent in the number of electric customers. The
electric sales breakdown by customer class is shown in the table below:

                            Electric Sales
                                                                %
 (Megawatt hours)             1996             1995           Change

 Residential                 725,471          735,442          (1.4)

 Commercial                1,381,043        1,347,947           2.5

 Industrial                  289,903          292,649          (0.9)

 Other                       305,962          320,869          (4.6)

   Total Retail            2,702,379        2,696,907           0.2

 Resale - Utilities           26,815           26,344           1.8

   Total Sales             2,729,194        2,723,251           0.2

Electric revenues decreased slightly in 1996 compared to 1995. The Company's
electric margin decreased $3.1 million or 2.6 percent during 1996 compared to
1995. The primary factor for the decrease in the electric margin is the
increase in replacement purchased power costs due to the extended outage at
Kewaunee.

Electric retail sales for 1995 increased 7.1 percent from 1994. This increase
is attributable to the hot and humid weather experienced in the summer of
1995. As a result of the increase in electric sales, electric revenues
increased $3.9 million or 2.6 percent in 1995 compared to 1994. The increase
in electric revenues occurred despite a 3.3 percent reduction to electric
rates effective January 1, 1995. 
<PAGE>
Gas sales and revenues

Total gas therms delivered by the Company increased 3.3 percent in 1996
compared to 1995, largely reflecting the colder weather experienced during the
first quarter of 1996. Gas therms delivered during the first quarter of 1996
increased 12.7 percent over the same 1995 period. The table below shows total
gas deliveries for 1996 by customer class:

                            Therms Delivered
                                                                  %
 (Thousands)                       1996            1995         Change

 Residential                      96,062          89,099         7.8

 Commercial and Industrial        93,723          94,729        (1.1)

   Total Retail System           189,785         183,828         3.2

 Transport                        37,707          36,502         3.3

   Total Gas Deliveries          227,492         220,330         3.3

Gas revenues increased $5.5 million or 5.8 percent in 1996 when compared to
the same period a year ago. This was mainly attributable to the increase in
gas deliveries due to the cold weather experienced in the first quarter as
well as the increase in the number of gas customers of 2.2 percent. The
Company's gas margin (revenues less natural gas purchased) decreased
$3.0 million or 8.1 percent in 1996 compared to 1995. The main reason for the
decreased margin is the Company's return of $2.5 million of revenue to gas
customers under a prior sharing mechanism between GLENCO and the Company (see
Note 5).

Gas delivered to customers in 1995 increased 6.3 percent from 1994. Despite
the increase in gas delivered in 1995, gas revenues remained constant when
compared to 1994. A shift in customers from retail system rates to
transportation rates is the main reason gas revenues did not increase in
proportion to gas deliveries. Gas transport customer revenue is recorded on a
margin basis, whereas retail system customer revenue is recorded on a total
revenue basis. 
<PAGE>
Electric fuel and natural gas costs

Electric fuel costs and purchased power costs increased $2.3 million or
6.4 percent in 1996 compared to 1995. As previously mentioned, the increase is
mainly attributable to the increased purchased power costs associated with
replacing power caused by the extended outage at Kewaunee. Purchased power
costs increased $3.6 million or 45.2 percent for 1996 over 1995. This was
offset somewhat by a $1.3 million or 4.8 percent decrease in fuel used for
electric generation for the same comparable periods. Kewaunee normally
provides over 25 percent of the generation requirements of the Company.
Electric fuel costs and purchased power costs remained constant in 1995
compared to 1994.

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

Natural gas costs decreased $2.2 million or approximately 3.7 percent during
1995 compared to 1994. This was due to a decrease in the cost per therm of
approximately 3.0 percent from the previous year.

Other operating expenses

Operations and maintenance (O&M ) expenses decreased $2.8 million or
3.8 percent during 1996 compared to 1995. Management's continued effort to
control O&M expenses is the primary reason for the decrease. Depreciation
expense increased $0.7 million or 2.8 percent in 1996 compared to 1995.
Depreciation expense related to decommissioning costs contributed $0.4 million
of the increase in total depreciation expense.

Other operations increased $4.7 million or 8.3 percent during 1995 compared to
1994. This is due in part to an increase in industry restructuring costs and
costs associated with participation in proposed utility merger filings.

Other nonoperating expenses

The Company's gas marketing subsidiaries had an after-tax operating loss of
$5.4 million in 1996, compared to $1.0 million in after-tax operating income
in 1995. The main reason for the operating losses this year is due to the
increase in the cost of gas, specifically in the first quarter when the demand
was the highest. In the first quarter of 1996, extremely cold weather caused
natural gas supply prices to rise substantially. Gas marketing companies are
severely impacted by the volatility in natural gas supply prices because they
work on a margin basis (revenues less cost of gas). Therefore, when gas costs
increase, profit margins are reduced.  
<PAGE>
The Company recorded a one-time write down in 1996 of $10.4 million (after
tax) to properly reflect the current value of the Company's investments in its
gas marketing subsidiaries and reorganizing these activities for the future
(see Note 4).

Total interest expense decreased $0.6 million or 5.4 percent in 1996 compared
to 1995. This is mainly due to lower interest rates in 1996 than in 1995.
Also, in November 1995, the Company replaced its 7 %, 2001 Series, First
Mortgage Bonds, with lower cost short-term debt.

Electric and gas operations outlook

The Company anticipates electric and gas sales to each grow at a compound
annual rate of 1.5 percent over the next five-year period ending December 31,
2001. The service territory remains well-insulated against economic downturns.
The Company's service area is one of America's most economically vibrant. The
Company expects to remain at a competitive advantage in a disaggregated
electric utility market because of its low generation costs, competitive
rates, and low percentage of industrial customers. The Company continues to
respond with rates and services to meet the needs of its customers as the gas
industry proceeds toward deregulation.

Joint venture

To strengthen its position in the gas marketing business, the Company's gas
marketing subsidiaries entered into a joint venture with another gas marketing
firm in January 1997. GLENCO and American Energy Management Inc. (AEM), the
Company's two gas marketing subsidiaries, formed a joint venture with National
Gas & Electric L.P. (NG&E) to market gas and energy services to industrial and
commercial customers in the Great Lakes region. The joint venture is called
National Energy Management, L.L.C. and is based in Chicago. NG&E, a unit of
PanCanadian Energy, Inc., is a Houston-based gas marketing company. NG&E has a
proven track record of profitability providing gas to a growing commercial and
industrial customer base.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities

Cash provided by operating activities decreased $2.5 million or 4.9 percent in
1996 compared to a year ago. A portion of the decrease is attributable to an
increase in the Company's net working capital. Accounts receivable increased
$2.3 million or 6.3 percent in 1996 compared to a year ago. Also, stored
natural gas and prepaid taxes combined increased $2.4 million or 19.9 percent
over last year. 
<PAGE>
Capital requirements and investing activities

The Company's liquidity is primarily affected by the requirement of its
ongoing construction program. In 1996, capital expenditures increased
$2.7 million or 14.3 percent, as compared to 1995, mainly due to an increase
in nuclear fuel expenditures. It is anticipated that capital expenditures will
be in the range of $25 to $35 million for the years 1997 through 2001. For the
five-year period ending December 31, 2001, the Company estimates that
internally generated cash will provide, on average, more than 100 percent of
the utility plant and nuclear fuel expenditures.

<TABLE>
Expenditures for construction and nuclear fuel estimated for 1997, actual for
1996, and the average for the three-year period 1993 to 1995 are shown below.

                                Expenditures for Construction and Nuclear Fuel
                                            (Thousands of dollars)
<CAPTION>
For the years ended                                                                         Annual Average
December 31:                      1997 Estimated                     1996                    1993 to 1995
<S>                              <C>         <C>              <C>        <C>              <C>          <C>
     Electric
Production                       $ 6,012      19.5%           $ 1,472      6.8%           $ 2,563       11.1%
Transmission                       3,042       9.9              1,051      4.8              1,040        4.5
Distribution and general           9,146      29.7              9,058     41.3              8,958       38.8
Nuclear fuel                       4,600      14.9              4,304     19.6              2,288        9.9
  Total electric                  22,800      74.0             15,885     72.5             14,849       64.3

     Gas                           5,200      16.9              4,431     20.2              5,877       25.5
Common                             2,800       9.1              1,590      7.3              2,354       10.2
  Total                          $30,800     100.0%           $21,906    100.0%           $23,080      100.0%
</TABLE>

Financing activities and capitalization matters

On June 1, 1996, the Company's 5.45%, 1996 Series, First Mortgage Bonds
matured. The Company was able to satisfy this $7.8 million maturity with
short-term debt.

At December 31, 1996, bank lines of credit available to the Company were
$55 million which included $10 million for GLENCO, a wholly owned subsidiary
of the Company, and AEM, a subsidiary of GLENCO. Credit requirements for
GLENCO and AEM are being transferred to NG&E and the joint venture as part of
the joint venture agreement. The bank lines are generally used to support
commercial paper issued, which represents a primary source of short-term
financing. The Company's dealer-issued commercial paper carries the highest
ratings assigned by Moody's Investors Service and Standard & Poor's
Corporation. 
<PAGE>
The Company's existing bonds are rated AA by Standard & Poor's and Aa2 by
Moody's Investors Service.

The Company anticipates it will be able to meet its construction requirements
and sinking fund debt requirements with internally generated funds over the
next three years.

Kewaunee Nuclear Power Plant

Kewaunee is operated by Wisconsin Public Service Corporation. The Company has
a 17.8 percent ownership interest in Kewaunee, which it owns jointly with two
other utilities. Kewaunee is operating with a license that expires in 2013.

Kewaunee was removed from service on September 21, 1996, for scheduled
refueling and maintenance. Inspection of previously repaired steam generator
tubes disclosed more extensive tube damage than had been anticipated. Repair
of the tubes using laser welding was undertaken. As of December 31, 1996, it
was anticipated that repairs would be completed sometime during the first
quarter of 1997. Welding was completed late in January 1997. Subsequent
testing indicated that the repair of a number of the tubes was not effective.
The return of Kewaunee to service will be delayed indefinitely while
additional repair requirements are being investigated. Nuclear Regulatory
Commission (NRC) approval is needed for these repairs and to restart the
plant.

If for any reason the steam generators cannot be repaired, the Kewaunee owners
would need to decide on alternatives ranging from replacing the existing steam
generators to early plant closure with replacement power options. Replacement
of steam generators must also be approved by the Public Service Commission of
Wisconsin (PSCW) and is estimated to cost $89.0 million (the Company's share
would be 17.8 percent or $15.8 million), excluding additional replacement
purchased power costs associated with an extended shutdown.

Even if the repairs are successful and the plant restarts, the tube repairs
are expected to last only a few years. Therefore, Kewaunee would be retired
prior to the expiration of the operating license in 2013 unless the steam
generators are replaced.

The PSCW approved the accelerated recovery of the current undepreciated
Kewaunee plant balance and the unfunded estimated costs to decommission the
plant through 2002.

If Kewaunee returns to service, it will be shut down at midcycle (within one
year after being returned to service) for tube inspection. If significant
further tube damage is discovered during the midcycle shutdown, the NRC may
not permit Kewaunee to continue to operate without replacement of the steam
generators. Since the earliest date by which the steam generators could be
replaced is sometime in 1999, a midcycle shutdown and subsequent requirement
that the steam generators be replaced before startup could result in an
extended outage. 
<PAGE>
An extended Kewaunee outage subjects the Company to increased purchased power
costs and increased fuel costs and operating and maintenance costs at other
generating units. Since most Kewaunee costs are incurred whether or not the
plant generates electricity, an extended outage of the plant results in
significant incremental costs for replacement electricity. The cost to use
other generating units and to purchase replacement power is expected to cost
on average $38,000 a day or approximately $3.4 million if the plant remains
down through the end of the first quarter of 1997. The Company received an
interim rate order from the PSCW in March 1997. The order provides for a
$0.507 per kilowatt-hour surcharge on customers' bills to cover the continuing
costs that will be incurred by the Company while Kewaunee remains out of
service. The interim electric rate order is scheduled to remain in effect
until either Kewaunee returns to service or the Company receives its final
rate order. The Company anticipates it will have sufficient sources to meet
its customers' energy requirements during the outage.

If Kewaunee is retired early, the Company believes it would be granted
regulatory approval to recover from its customers the net plant carrying
amount and the estimated costs to decommission Kewaunee in excess of the
decommissioning trust assets. At December 31, 1996, the net plant carrying
amount was approximately $21.7 million. The Company's share of the current
estimated costs to decommission Kewaunee, assuming early retirement, exceeds
the fair market value of decommissioning trust assets at December 31, 1996, by
$26.2 million. If Kewaunee is retired early, the Company believes it will be
able to meet its commitments to supply energy to its customers through either
(1) possible investments in new generating units, and/or (2) contracting for
additional purchased power. The Company is considering various options with
respect to Kewaunee including divestiture or early closure of the nuclear
plant. 
<PAGE>
Electric industry trend

During the past several years, the trend in the electric utility industry has
been toward increased competition caused by a changing regulatory environment.
In December 1995, the PSCW outlined its plan for the restructuring of the
electric utility industry in Wisconsin. The PSCW's plan generally followed a
plan proposed by the Company and a broad coalition of customers, public
interest groups, cooperative associations, municipal power entities, organized
labor, and others. Under the proposed PSCW plan, the Company is developing
plans illustrating how it intends to separate generation, transmission,
distribution, and energy services into separate business units. The PSCW would
continue distribution and transmission regulation. To limit the market power
of current transmission owners, the PSCW proposes moving either to appointment
of an independent system operator or to organization of a single statewide
transmission system. Additional proceedings and presentation to the state
legislature on the PSCW's electric utility restructuring proposal are planned
prior to the target implementation date. The targeted date under the PSCW
proposal is the year 2001, at which time consumers will be able to choose
their electricity provider. The Company cannot predict what impact future PSCW
actions may have on its future financial condition, cash flows, or results of
operations. However, the Company believes it is well-positioned to compete in
a deregulated market.

Regulatory and accounting issues

The Company operates under electric and natural gas utility rates that are
approved by the PSCW. These rates are designed to recover the cost of service
and provide a reasonable return to investors. The increasing trend toward
deregulation and increased competition is causing the electric utility
industry to restructure. The restructuring could affect the eligibility of the
Company to continue applying Statement of Financial Accounting Standard (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation." Under
this situation, continued deferral of certain regulatory asset and liability
amounts on the Company's books may no longer be appropriate as allowed under
SFAS 71. The Company is unable to predict whether any adjustments to
regulatory assets and liabilities will occur in the future. The PSCW's
restructuring plan specifically recognizes the need to allow recovery for
commitments made under prior regulatory regimes. 
<PAGE>
The PSCW completed its generic investigation of the natural gas industry and
made a determination as to whether or not traditional regulation should be
replaced with a different approach. Currently, the Company has the ability
through the Purchased Gas Adjustment Clause (PGAC) to recover from its
customers the cost of gas purchased by the Company on behalf of its customers.
The PGAC is often referred to as a one-for-one recovery mechanism. On 
Novewmber 8, 1996, the PSCW issued an order stating that the Company must
file a modified one-for-one recovery mechanism or an incentive mechanism. On
February 7, 1997, the Company filed a modified one-for-one recovery mechanism
and supporting testimony. Approval of a mechanism from the PSCW is expected by
July 1, 1997. The proposed implementation date is November 1, 1997. The
proposed modified one-for-one recovery mechanism provides appropriate price
signals to the Company's customers while minimizing the risk to shareholders.

SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," is effective for fiscal years beginning
on or after December 15, 1995. SFAS 121 requires that long-lived assets be
reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount may not be recoverable. SFAS 121 also amends SFAS 71
to require the write-off of a regulatory asset if it is no longer probable
that future revenues will recover the asset. The adoption of SFAS 121 did not
have an impact on the Company's financial position, cash flows, or results of
operations. However, the Company cannot predict what effect a competitive
marketplace or future regulatory actions will have on the outcome of the
application of SFAS 121.

Mergers

On May 1, 1995, Northern States Power Company and Wisconsin Energy Corporation
announced a proposed merger. If approved, the two companies would form a
holding company called Primergy Corporation (Primergy), creating the tenth
largest utility company in the United States. The merger has been approved by
the shareholders of both companies. Various regulatory agency approval is
required including the Securities and Exchange Commission, NRC, Federal Energy
Regulatory Commission (FERC), and state regulatory agencies.

The Company and a broad coalition of customer groups are opposing approval of
the merger on the grounds that the merger would violate antitrust laws and
principles by increasing the exercise of anticompetitive market power by
Primergy. Studies show Primergy could significantly raise prices for electric
customers in Wisconsin by exercising anticompetitive market power. Hearings on
the proposed merger have been concluded before the FERC and PSCW. The Company
believes that the proposed merger would have a detrimental impact on the
Wisconsin economy and that approval of the merger should be denied or strongly
conditioned to prevent the significant anticompetitive effects. 
<PAGE>
Inflation

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

Environmental issues

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

From 1980 to 1984, the Company disposed of fly-ash sludge at the Refuse
Hideaway Landfill in Middleton, Wisconsin. In October 1992, the Environmental
Protection Agency (EPA) placed the Refuse Hideaway Landfill on the national
priorities Superfund list of sites requiring clean up under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The scope of
liability under CERCLA is very broad.

The Company is listed as a potentially responsible party on the roster of
generators for the Refuse Hideaway Landfill. A group of approximately 45
companies is currently negotiating with EPA on the cleanup of the site. In the
opinion of management and legal counsel, the Company's share of the final
cleanup costs will not result in any materially adverse effects on the
operations, cash flows, or financial position of the Company. Significant
insurance recovery may also be available for the cleanup.

Accounting principles

The Company is required to adopt Statement of Financial Accounting Standard
(SFAS) No. 128, "Earnings Per Share," in 1997. SFAS 128 specifies the
computation, presentation, and disclosure requirements for earnings per share.
The adoption of this statement will result in the presentation by the Company
of earnings per share, as defined by the statement, and is not expected to
have a material impact on the earnings per share reported in the financial
statements. Upon adoption of this statement, all prior-period earnings per
share amounts will be restated to conform to the provisions of SFAS 128. 
<PAGE>
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-19


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
 David C. Mebane
 Chairman, President and
 Chief Executive Officer


 /s/ Joseph T. Krzos
 Joseph T. Krzos
 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, 1996 and 1995, and the related consolidated statements of income
and retained income and cash flows for the years ended December 31, 1996,
1995, and 1994. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Madison Gas and Electric
Company and subsidiaries as of December 31, 1996 and 1995, and the
consolidated results of their operations and their cash flows for the years
ended December 31, 1996, 1995, and 1994, in conformity with generally accepted
accounting principles.



/s/ Coopers & Lybrand L.L.P.
Milwaukee, Wisconsin
February 7, 1997 
<PAGE>
<TABLE>
Consolidated Statements of Income and Retained Income
(Thousands of dollars, except per-share amounts)
<CAPTION>
For the years ended December 31,                                      1996             1995              1994
<S>                                                                 <C>              <C>               <C>
CONSOLIDATED STATEMENTS OF INCOME
Operating Revenues:
   Electric                                                         $152,747         $153,554          $149,665
   Gas (Note 5)                                                      100,544           95,036            95,307
      Total Operating Revenues                                       253,291          248,590           244,972
Operating Expenses:
   Fuel for electric generation                                       26,676           28,017            26,167
   Purchased power                                                    11,687            8,048            10,015
   Natural gas purchased                                              66,021           57,488            59,693
   Other operations                                                   58,178           61,499            56,795
   Maintenance                                                        12,414           11,858            12,416
   Depreciation and amortization                                      25,510           24,815            22,383
   Other general taxes                                                 8,736            8,709             8,619
   Income tax items                                                   12,553           14,285            14,822
      Total Operating Expenses                                       221,775          214,719           210,910
Net Operating Income                                                  31,516           33,871            34,062
   AFUDC - equity funds                                                   40               57               132
   Other income, net                                                   1,517              549             1,535
   Writedown of nonregulated gas subsidiaries, net (Note 4)          (10,400)               -                 -
   Non-utility operating (loss)/income, net                           (5,355)           1,000               404
      Income Before Interest Expense                                  17,318           35,477            36,133
Interest Expense:
   Interest on long-term debt                                          9,815           10,331            10,558
   Other interest (Note 5)                                             1,097            1,205               639
   AFUDC - borrowed funds                                                (21)             (29)              (75)
      Net Interest Expense                                            10,891           11,507            11,122
Net Income                                                             6,427           23,970            25,011
Preferred stock dividends                                                  -               64               471
Earnings on Common Stock                                             $ 6,427         $ 23,906          $ 24,540
Earnings Per Share of Common Stock
 (Average shares outstanding - 16,079,718 for all years)               $0.40            $1.49             $1.53
                                                                            
CONSOLIDATED STATEMENTS OF RETAINED INCOME
Balance - Beginning of Year                                          $64,499          $60,851           $56,357
Add - Net income                                                       6,427           23,970            25,011 
 Deduct - Cash dividends on common stock                             (20,475)         (20,258)          (20,046)
        - Preferred stock dividend                                         -              (64)             (471)
Balance - End of Year                                                $50,451          $64,499           $60,851

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,                                          1996              1995              1994
<S>                                                                     <C>               <C>               <C>
 Operating Activities:
   Net income                                                           $ 6,427           $23,970           $25,011
   Items not affecting cash:
      Depreciation and amortization                                      25,510            24,815            22,383
      Deferred income taxes                                              (7,181)           (2,442)            2,428
      Amortization of nuclear fuel                                        2,098             2,740             2,803
      Amortization of investment tax credits                               (792)             (768)             (783)
      AFUDC - equity funds                                                  (40)              (57)             (132)
      Writedown of nonregulated gas subsidiaries                         15,741                 -                 -
      Other                                                               1,146             1,729               994
        Net Funds Provided from Operations                               42,909            49,987            52,704
   Changes in working capital, excluding cash equivalents, sinking
   funds, maturities, and interim loans:
      Increase in current assets                                         (3,445)          (12,168)          (10,789)
      Increase/(decrease) in current liabilities                          2,458            11,287            (2,127)
   Other noncurrent items, net                                            6,386             1,716             1,171
      Cash Provided by Operating Activities                              48,308            50,822            40,959
 Financing Activities:
   Cash dividends on common and preferred stock                         (20,475)          (20,322)          (20,517)
   Maturities/redemptions of First Mortgage Bonds                        (7,840)          (13,263)                -
   Increase in long-term debt                                                 -            11,000                 -
   Other decreases in First Mortgage Bonds                                 (162)             (199)              (58)
   Decrease in preferred stock                                                -            (5,300)             (200)
   Decrease in bond construction funds, net                                   -             8,090            10,892
   Increase/(decrease) in interim loans                                   9,250            (8,100)            5,100
      Cash Used for Financing Activities                                (19,227)          (28,094)           (4,783)
 Investing Activities:
   Acquisition of nonregulated subsidiary                                     -            (8,036)                -
   Additions to utility plant and nuclear fuel                          (21,906)          (19,162)          (26,429)
   AFUDC - borrowed funds                                                   (21)              (29)              (75)
   Increase in nuclear decommissioning fund                              (4,710)           (4,191)           (2,316)
      Cash Used for Investing Activities                                (26,637)          (31,418)          (28,820)
 Change in Cash and Cash Equivalents                                      2,444            (8,690)            7,356
   Cash and cash equivalents at beginning of period                       2,844            11,534             4,178
   Cash and cash equivalents at end of period                           $ 5,288           $ 2,844           $11,534

  The accompanying notes are an integral part of the above statements. 
/TABLE
<PAGE>
<TABLE>
Consolidated Balance Sheets
(Thousands of dollars)
<CAPTION>
At December 31,                                                                   1996             1995
<S>                                                                             <C>              <C>
     ASSETS
 Utility Plant, at original cost, in service:
   Electric                                                                     $500,690         $489,399
   Gas                                                                           178,312          173,890
      Gross Plant in Service                                                     679,002          663,289
   Less accumulated provision for depreciation                                  (374,315)        (348,254)
      Net Plant in Service                                                       304,687          315,035
   Construction work in progress                                                   7,517            9,061
   Nuclear decommissioning fund                                                   44,617           36,965
   Nuclear fuel, net                                                               8,378            6,172
      Total Utility Plant                                                        365,199          367,233
 Other Property and Investments                                                    7,115           17,176
 Current Assets:
   Cash and cash equivalents                                                       5,288            2,844
   Accounts receivable, less reserves of $1,220 and $1,379, respectively          39,145           36,817
   Unbilled revenue                                                               13,852           13,529
   Materials and supplies, at average cost                                         5,740            5,987
   Fossil fuel, at average cost                                                    1,808            2,986
   Stored natural gas, at average cost                                             7,189            6,203
   Prepaid taxes                                                                   7,258            5,846
   Other prepayments                                                               1,429            1,608
      Total Current Assets                                                        81,709           75,820
 Deferred Charges                                                                 30,146           33,647
        Total Assets                                                            $484,169         $493,876

     CAPITALIZATION AND LIABILITIES
 Capitalization (see statement)                                                 $307,975         $322,185
 Current Liabilities:
   Long-term debt sinking fund requirements                                          200              200
   Maturity of 5.45%, 1996 Series                                                      -            7,840
   Interim loans - commercial paper outstanding                                   29,750           20,500
   Accounts payable                                                               30,094           25,928
   Accrued taxes                                                                      79            1,500
   Accrued interest                                                                2,322            2,359
   Accrued nonregulated Items (Note 4)                                             7,923                -
   Other                                                                           7,653            7,903
      Total Current Liabilities                                                   78,021           66,230
 Other Credits:
   Deferred income taxes                                                          46,972           54,153 
   Regulatory liability - SFAS 109                                                23,914           25,177
   Investment tax credit - deferred                                               11,439           12,231
   Other regulatory liabilities                                                   15,848           13,900
      Total Other Credits                                                         98,173          105,461
 Commitments                                                                           -                -
        Total Capitalization and Liabilities                                    $484,169         $493,876

 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,                                                1996               1995
<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                                             50,451            64,499
      Total Common Shareholders' Equity                       179,089           193,137

 First Mortgage Bonds:
   5.45%, 1996 Series                                               -             7,840
   6 1/2%, 2006 Series:
      Pollution Control Revenue Bonds                           6,875             7,075
   8.50%, 2022 Series                                          40,000            40,000
   6.75%, 2027A Series:
      Industrial Development Revenue Bonds                     28,000            28,000
   6.70%, 2027B Series:
      Industrial Development Revenue Bonds                     19,300            19,300
   7.70%, 2028 Series                                          25,000            25,000
      First Mortgage Bonds Outstanding                        119,175           127,215
   Unamortized discount and premium on bonds, net              (1,089)           (1,127)
   Long-term debt sinking fund requirements                      (200)             (200)
   Maturity of 5.45%, 1996 Series                                   -            (7,840)
      Total First Mortgage Bonds                              117,886           118,048

 Other Long-Term Debt:
   6.01%, due 2000                                             11,000            11,000
        Total Capitalization                                 $307,975          $322,185

 The accompanying notes are an integral part of the above statements. 
</TABLE>
<PAGE>
Notes to Consolidated Financial Statements

December 31, 1996, 1995, and 1994.

1. Summary of Significant Accounting Policies

   a. General

      Madison Gas and Electric Company (the Company) is an investor-owned
      public utility headquartered in Madison, Wisconsin. The Company
      generates, transmits, and distributes electricity to about 122,000
      customers in a 250-square-mile area of Dane County. The Company also
      transports and distributes natural gas to over 105,000 customers in
      1,325 square miles of service territories in seven counties. The Company
      has served the Madison area since 1896.

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

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

   b. Utility Plant

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

      AFUDC represents the approximate cost of debt and equity capital devoted
      to plant under construction. The Company presently capitalizes AFUDC at
      a rate of 10.62 percent on 50 percent of construction work in progress.
      The AFUDC rate approximates the Company's cost of capital. The portion
      of the allowance applicable to borrowed funds is presented in the
      Consolidated Statements of Income as a reduction of interest expense,
      while the portion of the allowance applicable to equity funds is
      presented as other income. Although the allowance does not represent
      current cash income, it is recovered under the ratemaking process over
      the service lives of the related properties. 

      Substantially all of the Company's utility plant is subject to a first
      mortgage lien.
<PAGE>
   c. Nuclear Fuel

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

      The National Energy Policy Act enacted in 1992 contains a provision for
      all utilities that have used federal enrichment facilities to pay a
      special assessment for decontamination and decommissioning for these
      facilities. This special assessment will be based on past enrichment,
      and the Company has accrued and deferred an estimate of $2.4 million for
      the Company's portion of the special assessment. The Company believes
      all costs will be recovered in future rates.

   d. Joint Plant Ownership

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

                               Columbia                     Kewaunee

       (Thousands of
       dollars)           1996          1995           1996           1995

       Utility plant    $85,377       $85,075        $57,929        $57,853

       Accumulated
       depreciation     (46,704)      (44,366)       (36,271)       (34,263)

       Net Plant        $38,673       $40,709        $21,658        $23,590 
<PAGE>
    e. Depreciation

      Provisions at composite straight-line depreciation rates, excluding
      decommissioning costs discussed as follows, approximate the
      following percentages of the cost of depreciable property: electric,
      3.3 percent in 1996 through 1994; gas, 3.4 percent in 1996 and
      3.5 percent in 1995 and 1994. Depreciation rates are approved by the
      Public Service Commission of Wisconsin (PSCW) and are generally based on
      the estimated economic lives of property.

      Nuclear decommissioning costs are accrued over the estimated service
      life of Kewaunee, which is through the year 2013. These costs are
      currently recovered from customers in rates and are deposited in
      external trusts. For 1996, the decommissioning costs recovered in rates
      were $3.1 million.

      Decommissioning costs are recovered through depreciation expense,
      excluding earnings on the trusts. Net earnings on the trusts are
      included in other income. The long-term, after-tax earnings assumption
      on these trusts is 6.2 percent. As of December 31, 1996, the
      decommissioning trusts, totaling $45 million, are shown on the balance
      sheet in the utility plant section and offset by an equal amount under
      accumulated provision for depreciation.

      The Company's share of Kewaunee decommissioning costs is estimated to be
      $70.8 million in current dollars based on a site-specific study
      performed in 1992 using immediate dismantlement as the method of
      decommissioning. Decommissioning costs as studied are assumed to inflate
      at an average rate of 6.1 percent. Physical decommissioning is expected
      to occur during the period 2014 through 2021, with additional
      expenditures being incurred during the period 2022 through 2050 related
      to the storage of spent nuclear fuel at the plant site.

   f. Income Taxes

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

       (Thousands of dollars)       1996            1995            1994

       Income taxes charged to
       operations                  $12,553         $14,285         $14,822

       Income taxes charged to
       other income                 (7,942)            786             612

       Total income taxes          $ 4,611         $15,071         $15,434
<PAGE>
      Total income taxes consist of the following provision (benefit)
      components for the years ended December 31:

       (Thousands of dollars)       1996           1995            1994

       Currently payable
        Federal                   $ 9,317         $14,602        $10,985
        State                       3,267           3,679          2,804

       Net deferred
        Federal                    (7,079)         (2,217)         1,756
        State                        (102)           (225)           672

       Amortized investment tax
       credits                       (792)           (768)          (783)

       Total income taxes         $ 4,611         $15,071        $15,434

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

      The differences between the federal statutory income tax rate and the
      Company's effective rate are as follows:

                                            1996        1995        1994

       Statutory federal income tax rate    35.0%      35.0%      $35.0%

       Amortized investment tax credits     (7.2)      (2.0)       (1.9)

       State income taxes, net of federal
       benefit                               7.3        5.8         5.6

       Valuation allowance                  10.9          -           -

       Other, individually insignificant    (4.2)      (0.2)       (0.5)

       Effective income tax rate            41.8%      38.6%       38.2% 
<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)              1996             1995

       Property-related                    $59,522          $59,767

       Other                                 6,788            8,062
          Gross deferred income tax
           liabilities                      66,310           67,829

       Accrued expenses                     (7,629)          (3,571)

       Other                                (3,311)               -

       Deferred tax regulatory
        account                             (9,598)         (10,105)
          Gross deferred income tax
          assets                           (20,538)         (13,676)
          Less valuation allowance           1,200                -
          Net deferred income tax
          assets                           (19,338)         (13,676)
          Deferred income taxes            $46,972         $ 54,153

      Excess deferred income taxes, resulting chiefly from taxes provided at
      rates higher than current rates, have been recorded as a net regulatory
      liability ($23.9 million and $25.2 million at December 31, 1996 and
      1995, respectively), refundable through future rates.

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

      For tax purposes, these subsidiaries, as of December 31, 1996, had
      approximately $8.8 million of state tax net operating loss carryforwards
      which expire, if unused, in the year 2011. 
<PAGE>
    g. Pension Plans

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

      Effective January 1, 1995, the Company began recovering pension costs in
      customer rates under Statement of Financial Accounting Standard (SFAS)
      No. 87, "Employers' Accounting for Pensions." Prior to this date,
      pension costs were recovered in rates as funded. Of these funded pension
      costs, $0.8 million was charged to operating expenses in 1994. The
      plans' assets are in a master trust with a bank.

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

       (Thousands of dollars)                     1996           1995

       Fair value of plan assets                 $58,010        $50,152

       Actuarial present value of benefits
       rendered to date - Accumulated
       benefits based on compensation to
       date, including vested benefits of
       $40,840 and $44,554, respectively          46,019         45,574

       Additional benefits based on
       estimated future salary levels              9,093          9,943

       Projected benefit obligation              $55,112        $55,517

       Plan assets greater/(less) than
       projected benefit obligation                2,898         (5,365)

       Unrecognized net (gain)/loss               (4,621)         1,586

       Unrecognized prior service cost             1,004          1,130

       Net liability                             $  (719)       $(2,649)
<PAGE>
       Components of net pension costs for the years ended December 31 are:

       (Thousands of dollars)             1996         1995         1994

       Service costs (benefits
       earned during the period)          $1,715       $1,416      $1,462

       Interest costs on projected
       benefit obligation                  4,090        3,724       3,462

       Actual (return)/loss on plan
       assets                             (6,542)     (10,033)        412

       Net amortization and deferral       1,793        6,466      (4,056)

       Regulatory effect based on
       funding                                 -            -        (186)

       Net pension costs                  $1,056       $1,573      $1,094

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

                                           1996         1995        1994

       Expected long-term rate of
       return on plan assets               9.50%        9.50%       9.00%

       Average rate of increase in
       salaries                            5.00%        5.00%       5.00%

       Weighted average discount
       rate                                7.75%        7.25%       8.25%

      In addition to the noted plans, the Company also maintains two
      defined-contribution 401(k) benefit plans for its employees. The
      Company's costs of the 401(k) plan for the years 1996 through 1994 were
      $0.2 million for each year.

   h. Postretirement Benefits Other than Pensions

      The Company provides health care and life insurance benefits for its
      retired employees, and substantially all of the Company's employees may
      become eligible for these benefits upon retirement. These benefits are
      accrued over the period in which employees provide services to the
      Company. 
<PAGE>
      The Company has elected to recognize the cost of its transition
      obligation (the accumulated postretirement benefit obligation as of
      January 1, 1993) by amortizing it on a straight-line basis over 20
      years. The Company's obligation and costs are based on a discount rate
      of 7.75 percent in 1996, 7.25 percent in 1995, and 8.25 percent in 1994.
      The assumed rate of increase in health care costs (health-care-cost
      trend rate) is 11 percent in 1996, decreasing gradually to 5 percent in
      2003 and remaining constant thereafter. Increasing the health-care-cost
      trend rates of future years by one percentage point would increase the
      accumulated postretirement benefit obligation by $2.5 million and would
      increase annual aggregate service and interest costs by $0.3 million.

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

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

       (Thousands of dollars)                   1996             1995

       Accumulated postretirement
       benefit obligation (APBO):

       Retirees                               $(4,192)          $(4,054)

       Fully eligible active plan
       participants                            (1,662)           (1,701)

       Other active plan participants          (8,526)           (7,986)

          Total                               (14,380)          (13,741)

       Plan assets at fair value                3,581             2,666

       APBO in excess of plan assets          (10,799)          (11,075)

       Unrecognized transition
       obligation                               6,945             7,379

       Unrecognized prior service costs         2,000             2,166

       Unrecognized gain                       (1,804)           (1,129)

          Accrued postretirement benefit
          liability                           $(3,658)          $(2,659) 
<PAGE>
      Components of net periodic benefit costs for the years ended December 31
      are as follows:

       (Thousands of dollars)         1996         1995          1994

       Service cost                  $  546        $  429       $  402

       Interest cost on APBO          1,062           989          772

       Actual return on plan
       assets                          (266)         (177)         (91)

       Net amortization and
       deferral                         601           606          427

       Regulatory effect based on
       phase in                         402            95         (115)

       Net periodic benefit cost     $2,345        $1,942       $1,395


   i. Fair Value of Financial Instruments

      At December 31, 1996, the carrying amount of cash and cash equivalents
      approximates fair value. The estimated fair market value of the
      Company's First Mortgage Bonds and other long-term debt, based on quoted
      market prices at December 31, is as follows:

       (Thousands of dollars)                 1996             1995

       Carrying amount (includes sinking
       funds)                               $130,175          $138,215

       Fair market value                    $136,332          $149,469

2. Capitalization Matters

   a. First Mortgage Bonds and Other Long-Term Debt

      The annual sinking fund requirements of the outstanding first mortgage
      bonds is $0.2 million in 1997 through 2001. In June 1996, the
      $7.8 million, 5.45%, 1996 Series, First Mortgage Bonds were retired.

   b. Preferred Stock

      The Company has 1,175,000 shares of $25 par value redeemable preferred
      stock, cumulative, that is authorized but unissued at December 31, 1996.

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

      For short-term borrowings, the Company generally issues commercial paper
      (issued at the prevailing discount rate at the time of issuance) which
      is supported by unused bank lines of credit. Through negotiations with
      several banks, the Company had $55 million in bank lines of credit,
      which included $10 million for Great Lakes Energy Corp. (GLENCO) and
      American Energy Management Inc. (AEM).

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

       (Thousands of dollars)
       December 31:                   1996           1995          1994

       Available lines of credit
       (MGE)                         $45,000       $35,000       $32,000

       Available lines of credit
       (GLENCO)                      $10,000        $5,000             -

       Commercial paper
       outstanding                   $29,750       $20,500       $28,600

       Weighted average interest
       rate                            5.63%         5.86%         6.06%

       During the year:

       Maximum short-term
       borrowings                    $29,750       $28,600       $29,500

       Average short-term
       borrowings                    $13,805       $16,091       $16,549

       Weighted average interest
       rate                            5.53%         6.03%         4.57%

3. Rate Matters

   In September 1996, the Company announced its intention to increase electric
   rates for the test period beginning July 1, 1997, by $7.7 million or
   5.1 percent annually and increase natural gas rates by $3.7 million or
   3.8 percent annually for the same time period. The proposed changes are
   based on a requested return on common equity of 12.0 percent and would
   remain in effect through 1998. The proposed early recovery of the Kewaunee
   investment and accelerated decommissioning collections are the primary
   reasons for the increase in electric rates. Hearings will be held during
   April 1997 with a decision expected by the end of the second quarter of
   1997. 
<PAGE>
   The Company filed an application with the PSCW in December 1996 for interim
   electric rate relief for the first half of 1997. The reason for the interim
   request is a prolonged outage at Kewaunee, increasing maintenance costs and
   replacement power normally supplied by Kewaunee. The Company received an
   interim rate order from the PSCW in March 1997. The order provides for a
   $0.507 per kilowatt-hour surcharge on customers' bills to cover the
   continuing costs that will be incurred by the Company while Kewaunee
   remains out of service. The interim electric rate order is scheduled to
   remain in effect until either Kewaunee returns to service or the Company
   receives its final rate order.

4. Gas Marketing Subsidiaries

   The Company continually evaluates its asset base, including certain
   intangible assets such as goodwill, for events or changes in circumstances
   that indicate the carrying amount of the assets may not be recoverable.
   Throughout 1996, the Company experienced a decline in operating margins and
   continuing operating losses at the Company's gas marketing subsidiaries.
   This prompted the Company to evaluate the assets of the two companies for
   potential impairment. In the Company's evaluation, it found that some of
   the assets would not be recoverable. Thus, in December 1996, the Company
   wrote down its assets in both GLENCO and AEM to properly reflect the
   current value. The write down resulted in an after-tax charge to income of
   $10.4 million.

   GLENCO and AEM, two unregulated gas marketing subsidiaries, formed a joint
   venture, effective January 1, 1997, with National Gas & Electric L.P.
   (NG&E) to market natural gas and energy services to industrial and
   commercial customers in the Great Lakes region. The joint venture is called
   National Energy Management, L.L.C. and is based in Chicago. NG&E, a unit of
   PanCanadian Energy, Inc., is a Houston-based gas marketing company. The
   partnership gives GLENCO and AEM customers additional services to
   strengthen their competitive edge while at the same time joining forces
   with a gas marketing firm with a proven record. NG&E will actively manage
   the joint venture.

5. GLENCO Economic Benefit

   In the fourth quarter of 1996, the Company had a one-time charge resulting
   from a refund to its natural gas customers. Under a sharing mechanism with
   GLENCO, an economic benefit based on GLENCO's net income was to be passed
   back to the Company's natural gas utility customers.

   GLENCO's economic benefit was $2.5 million plus an additional $0.2 million
   in interest, which was added to compensate the natural gas utility
   customers for the time funds were retained, for a total refund of
   $2.7 million. This has an after-tax impact of $1.6 million on net income.
   The refund was properly credited to customers through the Purchased Gas
   Adjustment Clause. 
<PAGE>
 6. Commitments

   Utility plant construction expenditures for 1997, including the Company's
   proportional share of jointly owned electric power production facilities
   and purchases of fuel for Kewaunee, are estimated to be $31 million, and
   substantial commitments have been incurred in connection with such
   expenditures. Significant commitments have also been made for fuel for
   Columbia. 

 7. Segments of Business

   The table below presents information pertaining to the Company's segments
   of business. Information regarding the distribution of net assets between
   electric and gas for the years ended December 31 is set forth on page II-2.

  (Thousands of dollars)              1996          1995          1994

  Electric Operations

  Total revenues                    $152,747      $153,554      $149,665
  Operation and maintenance
   expenses                           90,862        89,994        87,748
  Depreciation and amortization       20,094        19,503        17,337
  Other general taxes                  7,000         6,908         6,907
  Pre-tax Operating Income            34,791        37,149        37,673
  Income taxes                        10,221        11,193        11,717
  Net Operating Income              $ 24,570      $ 25,956      $ 25,956
  Construction and Nuclear Fuel
   Expenditures (electric)          $ 16,855      $ 14,006      $ 16,804

  Gas Operations

  Operating revenues                $100,544      $ 95,036      $ 95,307
  Revenues from sales to electric
   utility                             2,304         3,100         1,671
  Total Revenues                     102,848        98,136        96,978
  Operation and maintenance
   expenses                           86,418        80,017        79,009
  Depreciation and amortization        5,416         5,312         5,046
  Other general taxes                  1,736         1,801         1,712
  Pre-tax Operating Income             9,278        11,006        11,211
  Income taxes                         2,332         3,091         3,105
  Net Operating Income              $  6,946      $  7,915      $  8,106
  Construction expenditures (gas)   $  5,051      $  5,156      $  9,625 
<PAGE>
 8. Supplemental Cash Flow Information

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

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

   (Thousands of dollars)          1996             1995             1994

   Interest paid, net of
   amounts capitalized            $10,932          $11,894          $11,235

   Income taxes paid              $16,041          $18,016          $13,602

9. Regulatory Assets and Liabilities

   Pursuant to SFAS 71, the Company capitalizes, as deferred charges, incurred
   costs that are expected to be recovered in future electric and natural gas
   rates. The Company also records as other credits, obligations to customers
   to refund previously collected revenue or to spend revenue collected from
   customers on future costs. The Company's regulatory assets and liabilities
   consisted of the following as of December 31:

                                    1996                    1995

   (Thousands of dollars)   Assets     Liabilities     Assets   Liabilities

 Demand-side management     $12,284       $     728   $14,169     $     213

 Decommissioning and
 decontamination              2,403           2,403     2,569         2,569

 Unamortized debt expense     5,260               -     5,448             -

 Other postretirement
 benefits                         -           3,481         -         2,516

 Other                       10,199           9,236    11,461         8,602

 Other regulatory
 assets/liabilities         $30,146         $15,848   $33,647       $13,900

 Regulatory liability -
 SFAS 109                         -          23,914         -        25,177

    Total                   $30,146         $39,762   $33,647       $39,077 
<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 24, 1997, with the Securities and Exchange Commission, which is
incorporated herein by reference.

<TABLE>
Executive Officers of the Registrant (elected annually by Directors)
<CAPTION>
                                                                                                 Service Years
                                                                                     Effective   as an Officer
Executive                Title                                                         Date
<S>                      <C>                                                         <C>              <C>
David C. Mebane          Chairman, President and CEO                                 05/09/94         16
Age:  63                 President, CEO and COO                                      01/01/94
                         President and COO                                           10/01/91
Robert E. Domek          Executive Vice President                                    05/01/95          8
Age:  66                 Senior Vice President - Human Resources                     05/03/93
                         Vice President - Human Resources                            12/01/91

Mark C. Williamson       Senior Vice President - Energy Services                     05/01/95          5
Age:  43                 Vice President - Energy Services                            05/03/93
                         Assistant Vice President - Energy Services                  11/01/92
                         Assistant Vice President - Electric Supply                  07/01/92
                         Executive Director - Electric Supply                        12/01/91

Gary J. Wolter           Senior Vice President - Administration and Secretary        05/01/95          6
Age:  42                 Vice President - Administration and Secretary               12/01/91

James C. Boll            Vice President - Law and Corporate Communications           10/20/95          4
Age:  61                 Assistant Vice President - Law and Corporate Comms.         05/03/93
                         Executive Director - Law and Corporate Comms.               01/13/92
                         Director - Public Affairs and Risk Management               06/01/91
                         Director - Risk Management                                  03/05/90
Terry A. Hanson          Vice President and Treasurer                                10/01/96          6
Age:  45                 Treasurer                                                   12/01/91

Lynn K. Hobbie           Vice President - Marketing                                  05/01/96          3
Age:  38                 Assistant Vice President - Marketing                        11/01/94
                         Senior Director - Marketing                                 07/01/93
                         Director - Market Planning and Programs                     11/01/92
                         Manager - Customer Planning and Research                    02/01/92
                         Supervisor - Market Planning and Evaluation                 06/01/90 

Joseph T. Krzos          Vice President - Finance                                    12/01/92         11
Age:  52                 Assistant Vice President - Accounting and Control           12/01/91

Thomas R. Krull          Vice President - Electric Transmission and Distribution     05/01/96          4
Age:  47                 Assistant Vice President - Electric Trans. and Dist.        05/03/93
                         Executive Director -Electric Transmission and Dist.         12/01/91
Richard H. Thies         Vice President - Gas Systems Operation                      07/01/86         11
Age:  55

Deborah L. Burgess       Assistant Vice President - Gas Rates and Supply             11/01/94          3
Age:  37                 Director - Gas Rates and Supply                             04/01/93
                         Manager - Gas Rates and Supply                              03/01/92

Peter J. Waldron         Assistant Vice President - Power Supply Ops. and Eng.       05/01/96          1
Age:  39                 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

Carol A. Wiskowski       Assistant Vice President - Admin. and Assistant Secretary   05/01/92         18
Age:  57
</TABLE>

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 24, 1997, 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, 1996 and 1995, and
     for each of the three years in the period ended December 31, 1996).
     Included in Part II, Item 8, of this report:

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

 b.  Financial statement schedules.

     None.

 2.  All exhibits including those incorporated by reference.

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

      No.   Description of document

     3.(i)  Articles of Incorporation as in effect at May 6, 1996.

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

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

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

             Tenth1            11/01/76       2.03       2-60227
             Fourteenth        04/01/92        4C        0-1125 (1992 10-K)
             Fifteenth         04/01/92        4D        0-1125 (1992 10-K)
             Sixteenth         10/01/92        4E        0-1125 (1992 10-K)
             Seventeenth       02/01/93        4F        0-1125 (1992 10-K)
<PAGE>
     10A    Copy of Joint Power Supply Agreement with Wisconsin Power and
            Light Company and Wisconsin Public Service Corporation dated
            February 2, 1967. (Incorporated by reference to Exhibit 4.09 in
            File No. 2-27308.)

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

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

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

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

     21     Subsidiaries of the Registrant.

     23     Consent of Independent Accountants.

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

 3.   Reports on Form 8-K - The Company filed a Current Report on Form 8-K
      dated December 31, 1996, under Item 5, "Other Events," which contains,
      under Exhibit 99, a press release announcing that its fourth-quarter and
      year-end earnings were negatively impacted by several factors.
<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 24, 1997         /s/ David C. Mebane
                              David C. Mebane
                              Chairman, President and Chief Executive
                              Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 24, 1997.


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


 /s/ Joseph T. Krzos          Vice President - Finance (Principal
 Joseph T. Krzos              Financial Officer and Principal
                              Accounting Officer)


 /s/ Frank C. Vondrasek       Vice Chairman and Director
 Frank C. Vondrasek


 Jean Manchester Biddick      Director


 /s/ Richard E. Blaney        Director
 Richard E. Blaney


 /s/ Regina M. Millner        Director
 Regina M. Millner


 /s/ Frederic E. Mohs         Director
 Frederic E. Mohs


 /s/ Phillip C. Stark         Director
 Phillip C. Stark


  H. Lee Swanson              Director