Definitions, Abbreviations, and Acronyms Used in the Text and Notes of this Report

Abbreviations, acronyms, and definitions used in the text and notes of this report are defined below.

Electric operations accounted for approximately 63.3%, 58.8%, and 62.8% of MGE's total 2009, 2008, and 2007 regulated revenues, respectively.

See Item 2. Properties, for a description of MGE's electric utility plant.

MGE is registered with two Regional Entities (RE), The Midwest Reliability Organization (MRO) and Reliability First Corporation (RFC). The essential purposes of the RE are: (1) the development and implementation of regional and NERC reliability standards, and (2) determining compliance with those standards, including enforcement mechanisms.

Transmission

Reliability 2000 legislation enacted in Wisconsin mandated, among other things, the creation of a statewide transmission company to own the investor-owned utilities' transmission assets. Pursuant to these provisions, effective January 1, 2001, MGE transferred all of its electric utility transmission assets to ATC in exchange for an ownership interest in ATC. At December 31, 2009, MGE Transco held a 3.6% ownership interest in ATC.

ATC is owned by the utilities that contributed facilities or capital in accordance with Wisconsin law. ATC's purpose is to provide reliable, economic transmission service to all customers in a fair and equitable manner. ATC plans, constructs, operates, maintains, and expands transmission facilities that it owns to provide adequate and reliable transmission of power. ATC is regulated by FERC for all rate terms and conditions of service and is a transmission-owning member of the MISO.

Regional Transmission Organizations

MGE is a nontransmission owning member of the MISO. MISO is a nonprofit RTO approved by FERC. The MISO is responsible for monitoring the electric transmission system that delivers power from generating plants to wholesale power transmitters. MISO's role is to ensure equal access to the transmission system and to maintain or improve electric system reliability in the Midwest.

MISO maintains a bid-based energy market. MGE offers substantially all of its generation on the MISO market and purchases much of its load requirement from the MISO market in accordance with the MISO Tariff. In January 2009, MISO implemented and MGE began participating in the ancillary services market (ASM). The ASM is an extension of the existing energy market in which MISO assumes the responsibility of maintaining sufficient generation reserves. Previously, MGE was responsible for providing its own reserves. In the ASM, MISO will provide the reserves for MGE's load, and MGE may offer to sell reserves from its generating units. In addition to this market change, MISO took on various Balance Authority functions. In June 2009, MISO implemented and MGE began participating in the voluntary capacity auction. The voluntary capacity auction provides an optional monthly forum for buyers and sellers of aggregate planning resource credits to interact. Load serving entities may participate in the voluntary capacity auction to potentially obtain the necessary aggregate planning resource credits to meet their planning reserve margin requirement. Generator owners may participate to sell any excess aggregate planning resource credits that are not needed.

Additionally, MGE is a member of PJM. PJM is also an RTO. PJM is a neutral and independent party that coordinates and directs the operation of the region's transmission grid, administers a competitive wholesale electricity market, and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion. MGE has one purchase power agreement, for a total of 50 MW, that is affected by this market.

Fuel supply and generation

MGE satisfies its customers' electric demand with internal generation and purchased power. During the years ended December 31, 2009, 2008, and 2007, MGE's electric energy delivery requirements were satisfied by the following sources:

Sources used depend on market prices, generating unit availability, weather, and customer demand.

Coal

MGE and two other utilities jointly own Columbia, a coal-fired generating facility, which accounts for 29% (225 MW) of MGE's net summer rated capacity. Power from this facility is shared in proportion to each owner's ownership interest. MGE has a 22% ownership interest in Columbia. The other owners are WPL (a subsidiary of Alliant), which operates Columbia, and WPSC. The Columbia units burn low-sulfur coal obtained (pursuant to long-term contracts) from the Powder River Basin coal fields located in Wyoming and Montana.

MGE's share of the coal inventory supply for the units increased from approximately 13 days on December 31, 2008, to approximately 47 days on December 31, 2009. The co-owners' current goal is to maintain approximately a 35 day inventory.

MGE also owns the Blount Generating Facility located in Madison, Wisconsin, which is fueled by coal, gas, and other alternative renewable sources. On January 19, 2006, MGE announced a plan, subject to certain conditions, that includes discontinuing coal use at the end of 2011 at Blount. In March 2009, MGE received notification from MISO that in order to meet national electric system reliability standards, MGE will need to keep Blount available at full capacity until MISO declares that the 90 MW are no longer needed for system reliability. To comply with the MISO directive, MGE will delay plans for retiring 90 MW of generation equipment at Blount. The transition from burning coal to burning only natural gas will still occur by the end of 2011. After 2011, the entire plant will be operated exclusively on natural gas.

See discussion below under Nonregulated Operations for MGE's interest in coal-fired generation in Oak Creek, Wisconsin.

Natural gas and oil

MGE owns gas fired combustion turbines. These turbines are primarily located in Madison and Marinette, Wisconsin and have a total of 174 MW of net summer rated capacity.

See discussion above regarding gas-fired generation at Blount Generating Facility and see discussion below under Nonregulated Operations for MGE's interest in a natural gas-fired cogeneration facility on the UW campus.

Renewable generation sources

MGE owns 30 MW or 18 turbines in a wind-powered electric generating facility in Worth County, Iowa. The turbines were placed into service in February 2008. MGE also owns 11 MW or 17 turbines in a wind-powered electric generating facility in Kewaunee County, Wisconsin. The turbines were placed into service in 1999.

Purchased power

MGE enters into short and long-term purchase power commitments to meet a portion of its anticipated electric energy supply needs. The following table identifies purchase power commitments at December 31, 2009 with unaffiliated parties for the next five years.

Wind Development Rights

In June 2009, MGE Energy, through its subsidiary MAGAEL, LLC, entered into agreements to purchase land development rights, including land option agreements, electrical interconnection rights, wind data, engineering plans, licenses, permits, and governmental approvals for two wind development sites. These wind development rights may potentially be used to develop wind farms in three counties in Iowa up to approximately 175 MWs; however, neither MAGAEL nor MGE Energy has any obligation to build any wind generators at these sites.

Gas Utility Operations

MGE transports and distributes natural gas in a service area covering 1,631 square miles in seven south-central Wisconsin counties. The service area includes the city of Madison, Wisconsin.

On December 31, 2009, MGE supplied natural gas service to approximately 142,000 customers in the cities of Elroy, Fitchburg, Lodi, Madison, Middleton, Monona, Prairie du Chien, Verona, and Viroqua; 24 villages; and all or parts of 45 townships. Of the total number of customers, approximately 89% were residential and 11% were commercial or industrial. Gas revenues for 2009, 2008, and 2007 were comprised of the following:

Gas operations accounted for approximately 36.7%, 41.2%, and 37.2% of MGE's total 2009, 2008, and 2007 regulated revenues, respectively.

MGE can curtail gas deliveries to its interruptible customers. Approximately 15% of retail gas deliveries in 2009 and 12% in 2008 were to interruptible customers.

Gas supply

MGE has physical interconnections with ANR and NNG. MGE's primary service territory, which includes Madison and the surrounding area, receives deliveries at one NNG and four ANR gate stations. MGE also receives deliveries at NNG gate stations located in Elroy, Prairie du Chien, Viroqua, and Crawford County. Interconnections with two major pipelines provide competition in interstate pipeline service and a more reliable and economical gas supply mix, which includes gas from Canada and from the mid-continent and Gulf/offshore regions in the United States.

During the winter months, when customer demand is high, MGE is primarily concerned with meeting its obligation to firm customers. MGE meets customer demand by using firm supplies under contracts finalized before the heating season, supplies in storage (injected during the summer), and other firm supplies purchased during the winter period.

By contract, a total of 5,417,288 Dth can be injected into ANR's storage fields in Michigan from April 1 through October 31. These gas supplies are then available for withdrawal during the subsequent heating season, November 1 through March 31. Using storage allows MGE to buy gas supplies during the summer season, when prices are normally lower, and withdraw these supplies during the winter season, when prices are typically higher. Storage also gives MGE more flexibility in meeting daily load fluctuations.

MGE's contracts for firm transportation service include winter maximum daily quantities of:

•

166,150 Dth (including 96,078 Dth of storage withdrawals) on ANR.

•

60,108 Dth on NNG.

Nonregulated Energy Operations

MGE Energy, through its subsidiaries, seeks to develop generation sources that will assist MGE in meeting the electricity needs of its customers. Decisions on the type of energy source and its size, timing, ownership, and financing depend upon a number of factors including the growth of customer demand in MGE's service area and surrounding areas, the effectiveness of customer demand management efforts, the costs and availability of alternative power sources, mandates regarding renewable energy resources, the availability of transmission capacity, issues associated with siting power generation sources, available financing and ownership structures, regulatory treatment and recovery, construction lead times and risks, and other factors. The decisions tend to involve long-time horizons due to the lead time involved in siting and constructing new generation sources and the associated transmission infrastructure.

WCCF

MGE Power West Campus and the UW jointly own undivided interests in a natural gas-fired cogeneration facility on the UW campus. The facility has the capacity to produce 20,000 tons of chilled water, 500,000 pounds per hour of steam, and approximately 150 MW of electricity. The UW owns 45% of the facility, which represents its interest in the chilled-water and steam assets. These assets are used to meet the UW's growing need for air-conditioning and steam-heat capacity. MGE Power West Campus owns 55% of the facility, which represents its interest in the electric generating assets. These assets are used to provide electricity to MGE's customers. The UW's share of the plant and portion of the earnings from the WCCF are not reflected in the consolidated financial statements of MGE Energy or MGE. MGE Power West Campus' share of the cost of this project is reflected in property, plant, and equipment on MGE Energy's and MGE's consolidated balance sheets.

MGE leases the electric generating assets owned by MGE Power West Campus and is responsible for operating the entire facility. The financial terms of the facility lease include a capital structure of 53% equity and 47% long-term debt, return on equity of 12.1%, and a lease term of 30 years. At the end of the lease term in 2035, MGE may, at its option, renew the facility lease for an additional term, purchase the generating facility at fair market value or allow the lease contract to end.

Elm Road

MGE Power Elm Road and two other owners own undivided interests in the coal-fired Elm Road Units in Oak Creek, Wisconsin. Unit 1 entered commercial operation on February 2, 2010, and has the capacity to produce 615 MW of electricity. Unit 2 is under construction, is expected to have a capacity to produce 615 MW of electricity, and is expected to enter commercial operation in August 2010. Wisconsin Energy Corporation owns approximately 83% of the Elm Road Units and is the operator for those units. MGE Power Elm Road owns an 8.33% ownership interest in both units. Both units will be used to provide electricity to MGE's customers.

MGE leases MGE Power Elm Road's ownership interest in the Elm Road Units pursuant to two separate facility leases. The financial terms of each facility lease include a capital structure of 55% equity and 45% long-term debt, return on equity of 12.7%, and a lease term of 30 years. At the end of the respective lease terms, MGE may, at its option, renew the facility lease for an additional term, purchase the leased ownership interest at fair market value or allow the lease to end. The Unit 1 lease commenced with the commercial operation of that unit, and the Unit 2 lease will commence with the commercial operation of that unit.

MGE Power Elm Road's estimated share of capital costs for its ownership interest in the Elm Road Units is approximately $180 million (excluding capitalized interest). These costs have been financed primarily through funds received from MGE Energy, which came from the sale of common stock (via the Stock Plan), short-term debt, and operating cash flows. On February 4, 2010, MGE Power Elm Road issued $50 million of 5.04% senior secured notes due 2040 to reimburse MGE Energy for a portion of its funds. At December 31, 2009, MGE Power Elm Road had incurred $168.3 million (excluding capitalized interest) of costs on the project.

On November 1, 2005, MGE received approval from the PSCW to defer payments made to MGE Power Elm Road for carrying costs during construction of the facility, management fees, and community impact mitigation costs. MGE began collecting the carrying costs in rates in 2006. MGE estimates total carrying costs to be approximately $59.5 million. Of these costs, $17.6 million is estimated to relate to the capitalized interest on the debt portion of the facility. These costs will be recognized over the period in which the facility will be depreciated. The remaining $41.9 million is estimated to represent the equity portion and is being recognized over the period recovered in rates.

See Footnote 21 of Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data of this Form 10-K for more information regarding the Elm Road Units and the settlement of a dispute with the general contractor, Bechtel Power Corporation, regarding construction of the units.

Environmental

MGE is subject to local, state, and federal regulations concerning air quality, water quality, and solid waste disposal. The EPA administers certain federal statutes relating to such matters. The WDNR administers certain state statutes as to such matters and has primary state jurisdiction over air and water quality and solid and hazardous waste matters. These regulations affect the manner in which MGE conducts its operations, the costs of those operations, as well as some capital and operating expenditures. They can also affect the siting, timing, and cost of new projects or other significant actions affecting the environment. MGE is not able to predict the direction of future regulations or if compliance with any such regulations will involve additional expenditures for pollution control equipment, plant modifications, or curtailment of operations. Such actions could reduce capacity or efficiency at existing plants or delay the construction and operation of future generating facilities.

Based upon current available information, compliance with various environmental requirements and initiatives is expected to result in significant additional operating and capital expenditures at Columbia and may affect those expenditures at other MGE generating facilities. In April 2009, the Columbia owners requested authorization from the PSCW for an emissions reduction project as a result of an environmental initiative. The operator's current estimates show that MGE's share of the capital expenditures required to comply with this project will be approximately $140 million. According to the current estimate, this project is expected to result in an increase to Columbia's ongoing operating expenses. MGE expects that the costs pertaining to this project will be fully recoverable through rates.

Air quality

Air quality regulations promulgated by the EPA and WDNR in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 impose restrictions on emission of particulates, sulfur dioxide (SO₂) nitrogen oxides (NO_x) and other pollutants and require permits for operation of emission sources. These permits have been obtained by MGE and must be renewed periodically. Various initiatives, including the Clean Air Interstate Rule (CAIR), maximum achievable control technology (MACT) standards, new source performance standards (NSPS) and the Clean Air Visibility Rule (also known as the Regional Haze Rule), as well as state mercury emissions limits, are expected to result in additional operating and capital expenditure costs for electric generating units.

CAIR

The CAIR requires NO_x and SO₂ emission reductions in two phases and includes a regional cap-and-trade system. The first phase began in 2009 for NO_x and the second phase begins in 2010 for SO₂, and contemplates reductions from 2003 levels of 55% and 40%, respectively, increasing in the second phase (by 2015) to 65% and 70%, respectively from 2003 levels. MGE owns several generation units currently subject to CAIR: Blount Generating Station, Columbia, M34 (West Marinette Combustion Turbine) and Fitchburg Combustion Turbines. In future years, Elm Road will be, and WCCF may be, affected by the CAIR. MGE anticipates that it may need to purchase NO_x and SO₂ allowances and /or install equipment at Columbia to meet CAIR allocations for its generation fleet. The exact cost of the allowances and/or equipment installation is not known at this time.

The long-term design and implementation of the CAIR, however, is uncertain at this time. On December 23, 2008, the D.C. Circuit Court remanded the CAIR to the EPA. The court's remand to the EPA did not include a deadline. The CAIR remains in effect until modified by the EPA. Based on this remand it is likely that the current cap-and-trade system will be modified.

Wisconsin State Mercury Rule

Wisconsin has revised its state mercury rule (NR 446, effective December 1, 2008). The revised NR 446 requires large coal-fired electric generating units (larger than 150 MW) to reduce mercury emissions by 90% beginning in 2015, or choose a multi-pollutant reduction approach, which allows a stepped approach to mercury reduction while reducing NO_X and SO₂ emissions at prescribed rates. Smaller coal-fired electric generating units (between 25 – 150 MW in size) will need to apply Best Available Control Technology (BACT) to achieve mercury reductions.

Effective January 1, 2010, Wisconsin NR 446 also requires a 40% fleet-wide mercury reduction (as compared to an average of 2002, 2003, and 2004 baseline mercury emissions) for major Wisconsin utilities. Because the majority owner and operator of Columbia and the majority owner and operator at Elm Road are defined as major utilities under this rule, Columbia's and Elm Road's mercury emissions in 2010-2014 will be subject to this 40% fleet-wide reduction. Elm Road's majority owner has installed highly efficient mercury-reduction equipment on its units. Columbia's majority owner plans to meet this fleet-wide reduction in a number of ways, including utilizing mercury reduction equipment previously installed on one of Columbia's units. We do not anticipate any changes in dispatch at Columbia or Elm Road as a result of this fleet-wide reduction requirement. However any dispatch changes, if they were to become necessary to meet this requirement, could negatively affect our operating costs.

MACT Standards for Electric Utilities

On February 9, 2009, the Justice Department, on behalf of the EPA, asked the Supreme Court to dismiss EPA's petition for review of the D.C. Circuit Court's vacatur of the Clean Air Mercury Rule (CAMR). This withdrawal paves the way for the EPA to develop MACT standards for electric utilities (for mercury as well as other Hazardous Air Pollutants (HAPs)).

As part of the EPA's process for developing MACT standards for electric utilities, the EPA has sent out an Information Collection Request (ICR) to hundreds of utilities across the United States that have coal and oil-burning electric generating units. The EPA has indicated that they will use the information collected from this ICR to assist in the development of electric generating unit MACT standards. Under this ICR, Blount and Columbia received letters requesting information on pollution control equipment. Elm Road is required to perform testing in addition to responding to the information requests.

It is unclear at this time when electric generating unit MACT standards will be created for electric utilities and how they will affect MGE's operations. The implementation of the MACT standards may affect our facilities that burn coal and oil. However, we are uncertain of the exact cost or operational impact until the final MACT standards are known.

Boiler MACT

The EPA developed a MACT standard for industrial, commercial and institutional boilers (Boiler MACT) that was later vacated. The EPA has been under court-order to develop a new MACT standard to replace the one that had been vacated. The EPA has interpreted that this vacatur requires that case-by-case MACT under Section 112(j) of the Clean Air Act (the "MACT Hammer") be applied in the interim to all boilers that fit the definition of a industrial, commercial or institutional boiler (ICI boilers) regardless of whether or not they were exempt under the vacated rule. The WDNR, following the EPA's interpretation, has required that all facilities with ICI boilers submit initial MACT Hammer applications.

MGE has boilers at Blount and Columbia that are classified as ICI boilers and has sent in all necessary paperwork to the WDNR. Some boilers at Blount and Columbia have the potential of being subject to emission standards for HAPs for ICI boilers under either the MACT Hammer provisions, or the revised Boiler MACT. If subject to these rules, it will be necessary to submit permit applications to the WDNR. If any of our boilers are subject to Boiler MACT Hammer, it may require that we test or limit emissions and/or install additional pollution controls. Because of the uncertainty with this rule at this time, we cannot predict when or if we will need additional resources or capital to comply with either version of Boiler MACT.

BART/CAVR

Air modeling indicates that SO₂ and NO_X emission (and to a lesser extent particulate matter, or PM) from Columbia may impair visibility at certain Class I Scenic Areas and may therefore be subject to the Best Available Retrofit Technology (BART) regulations, a subsection of the EPA's Clean Air Visibility Rule (CAVR).

Wisconsin has promulgated a BART implementation rule which clarifies that fossil fuel fired electric plants subject to the CAIR trading programs are not required to conduct a BART analysis for SO₂ or NO_X emissions, and the determination of BART shall be made for PM emissions only. However, a remanded CAIR has left open the potential for revisions to Wisconsin's rule. The WDNR is exploring potential revisions. The revisions have a potential to affect capital and operating expenses, but exact costs cannot be determined at this time.

Wisconsin was required to submit a CAVR State Implementation Plan (SIP) to the EPA by December 2007. The EPA found Wisconsin to be deficient in this submittal in January 2009. Wisconsin has two years from this finding of deficiency to submit a CAVR SIP. If no CAVR SIP is submitted within that two year period, then the EPA must promulgate a Federal Implementation Plan (FIP) for the State of Wisconsin. Without a proposed CAVR implementation rule in place, it is unclear to what extent either a CAVR SIP or FIP will affect MGE generation plants.

National Ambient Air Quality Standards

Nitrogen Oxide Emission Budget

In 1998, the EPA issued a rule that imposed a NO_x emission budget for emission sources in Wisconsin. In 2000, the Court of Appeals for the District of Columbia invalidated a portion of the rule concerning Wisconsin's alleged impacts on downwind, 8-hour ozone nonattainment areas. EPA has also stayed that portion of the rule concerning Wisconsin's alleged impacts on downwind 8-hour ozone nonattainment areas. If that portion of the rule concerning eight-hour ozone nonattainment areas is upheld, the resulting NO_x emission budget for Wisconsin could potentially affect the level of permissible NO_x emissions from Blount, Columbia, and WCCF.

Particulate Matter NAAQS

In 2006, the EPA lowered the acceptable 24-hour National Ambient Air Quality Standard (NAAQS) for fine particulate matter, or PM_2.5 – i.e., a particulate matter air pollutant that is 2.5 microns or smaller in size. States monitor and collect data on PM_2.5 levels and recommend counties/areas within their state for attainment or nonattainment with the NAAQS. The EPA makes the final decision on attainment/nonattainment areas. In mid-December 2008, the EPA designated several areas of the State, including Dane County (where Blount and WCCF are located), a portion of Columbia County (where Columbia is located), and the Milwaukee/Racine area (where Elm Road is located) as nonattainment areas for the 24-hour PM_2.5 standard. The EPA made these initial determinations based on monitoring data for the years 2005-2007 data. On October 8, 2009, EPA announced its final PM_2.5 attainment designations for Wisconsin using the 2006 through 2008 data and only Milwaukee, Racine and Waukesha Counties were designated as nonattainment. The State of Wisconsin will need to develop a SIP by early 2012 for those counties that remain designated as nonattainment. Implementation of the fine particulate NAAQS could affect capital, operational and maintenance expenses at MGE generating facilities.

In February 2009, the PM_2.5 standards were remanded to the EPA by the D.C. Circuit Court. The current primary hourly and annual standards will remain in place as the EPA reviews both the primary and secondary standard as per the D.C. Circuit Court decision. If the standards are made more stringent, more counties where our generation is located could become nonattainment; however, that cannot be known until the standards are finalized.

Ozone NAAQS

On March 12, 2008, the EPA announced a new 8-hour NAAQS for ozone that is more stringent than the current standard (standard lowered from 0.08 to 0.075 parts per million). States (including Wisconsin) must monitor and collect data on ozone levels in order to determine attainment or nonattainment status on a county and/or area basis. Currently available monitoring data for Dane, Columbia and Milwaukee counties (where our generation facilities are located) demonstrates attainment with the March 12, 2008 standard.

On January 6, 2010, EPA published a proposed rule reconsidering the March 12, 2008 8-hour ozone standard. In this proposed rule, EPA states their intent to revise both the primary (set for protection of public health) and secondary (set for protection of public welfare and environment) ozone standards and indicates that they will set an 8-hour ambient ozone standard between 0.060 – 0.070 parts per million (ppm). EPA further indicates that they will set a secondary standard of 7 – 15 ppm-hours measured on a weighted average over a three-month period during the ozone season.

We cannot determine at this time if Dane, Columbia and/or Milwaukee counties, will be in attainment with the potential revised standards (i.e., have ambient air quality that is at or below the attainment level ultimately selected by the EPA), but there is modeling to suggest the potential for nonattainment in any or all of these counties with the range currently under consideration by the EPA. A nonattainment designation for the 8-hour ozone standard in any of these counties has the potential to increase operating and capital expenditures at Columbia (located in Columbia County), Blount and WCCF (located in Dane County) and Elm Road (located in Milwaukee County).

Nitrogen Dioxide NAAQS

On January 22, 2010, the EPA revised its primary Nitrogen Dioxide (NO₂) NAAQS. The current annual primary NO₂ standard remains, while a one-hour 100 parts per billion (ppb) standard has been added that focuses on near-roadway exposures to NO₂. The EPA expects states to submit initial recommendations for nonattainment areas by January 2011 using 2008-2010 data. The EPA plans to make final attainment and nonattainment designations by January 2012. The EPA has not changed the secondary NAAQS for NO₂, but intends to address potential changes as part of a secondary review. It is unclear at this time how MGE's power plants would be affected by this proposed revision.

Sulfur Dioxide NAAQS

On November 16, 2009, the EPA proposed to change the primary Sulfur Dioxide NAAQS from a 140 parts per billion (ppb) standard measured over a twenty-four hour period to an hourly standard. The EPA is proposing a range of 50 – 100 ppb hourly standard. The EPA has also indicated that a secondary NAAQS standard for SO₂ will be proposed in 2010. In addition to the proposed changes to the SO₂ NAAQS, the EPA is also proposing that SO₂ monitoring sites be redesigned so that they monitor areas where short-term concentrations of SO₂ are more likely. The EPA is currently proposing that roughly 345 monitoring locations be created based on high-level SO₂ concentration areas and high population/high SO₂ level areas. Based on the proposed rule, we anticipate that roadside monitors would be placed in Dane and Milwaukee counties, but the actual placement has not been determined. It is unclear at this time how MGE's power plants would be affected by this proposed revision.

Columbia Air Operating Permit

In September 2008, the Wisconsin DNR issued a Title V renewal operating permit to WPL (the operator and permit holder) for Columbia. A citizen group petitioned EPA to object to the issuance of the permit renewal. In October 2009, the EPA issued an order granting in part and denying in part the petition and sent the operating permit back to the Wisconsin DNR for further review based on the EPA order. The EPA order gave WDNR 90 days to address the objections and take action on the September 2008 operating permit. The Wisconsin DNR has been working with the EPA and has been in contact with WPL related to this matter. To date, no changes have been made to the previously issued permit for Columbia. MGE is unable to predict what actions the WDNR or EPA may take on the permit.

In October 2009, the Sierra Club provided notice of its intent to file a civil lawsuit against the owners and operator of Columbia for alleged violations of the Clean Air Act. WPL is the plant operator and permit holder, and owns 46.2% of Columbia. Wisconsin Public Service Corporation (WPSC) owns a 31.8% interest, and MGE owns a 22% interest in Columbia. Among other things, this notice alleges the failure to obtain necessary air permits and implement necessary emission controls associated with activities undertaken in approximately 2000 and 2005. If pursued and successful, this lawsuit could result in civil penalties, injunctive relief, as well as increased capital and operating/maintenance expenditures at Columbia. WPL, the operator and permit holder for Columbia, has informed MGE that it is reviewing the allegations and is currently unable to predict the impact of the allegations on Columbia's finances or operations at this time.

In December 2009, the EPA sent a Notice of Violation (NOV) to the owners and operator of Columbia. The NOV alleges that the owners and operator failed to comply with appropriate pre-construction review and permitting requirements of the New Source Review (NSR) program, and as a result violated the PSD program requirements, Title V Operating Permit requirements of the CAA and the SIP. WPL, the plant operator, as well as MGE and WPSC as owners of Columbia, have begun discussions with the EPA regarding the NOV.

If pursued and successful, these actions could result in civil penalties in amounts of up to $37,500 per day (for all joint owners) for each violation and/or injunctive relief to require installation of pollution control technology at Columbia, which would increase future capital and operating expenditures. WPL, the plant permit holder and operator, has also informed MGE that it is in the process of evaluating the allegations and is unable to predict the impact of the allegations on Columbia's finances or operations at this time, but believes that an adverse outcome could be significant. WPL has also informed MGE and WPSC that the current intent is to defend against these actions because WPL believes the projects in question did not violate the CAA. Nevertheless, the owners are exploring settlement options while simultaneously preparing to defend against the allegations. MGE has not recognized any related loss contingency amounts as of December 31, 2009.

Water quality

MGE is subject to water quality regulations issued by the WDNR. These regulations include discharge standards, which require the use of effluent-treatment processes equivalent to categorical "best practicable" or "best available" technologies under compliance schedules established under the Federal Water Pollution Control Act. The WDNR has published categorical regulations for chemical and thermal discharges from electric-steam generating plants. The regulations limit discharges from MGE's plants into Lake Monona and other Wisconsin waters.

Proposed Thermal Discharge Rules in Wisconsin

The WDNR is promulgating revised rules to regulate thermal effluent discharges from point sources in Wisconsin. The current draft rules apply strict standards for thermal discharges into inland lakes, streams, rivers, and the Great Lakes. While dischargers can apply for variances, MGE may incur additional capital expenditures, such as equipment upgrades at Blount and Columbia, if the variances are not granted. Costs at Blount have not been fully determined, however, capital expenditures may include cooling towers, which in past analyses have been shown to be cost prohibitive. Potential costs at Columbia have not been determined at this time. Based on initial reviews of the current revised rules, we do not expect the Elm Road Units to be effected by these rules.

EPA Cooling Water Discharge Rules (Section 316(b))

In 2004, the EPA promulgated final rules under Section 316(b) of the Clean Water Act addressing cooling water intake structures for existing large power plants (Phase II rule). A challenge to this rule was upheld in a January 2007 court decision and significant parts of the rule were remanded to the EPA for further consideration. In July 2007, EPA suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems. The ruling, and EPA's actions in response, which may change the compliance requirements, may at some point affect the timing and costs associated with MGE's WPDES permit for Blount and possibly the WPDES permit for the Elm Road facility. At this time, MGE is unable to determine the timing or amount of that impact.

WPDES permit – Elm Road

On July 31, 2008, the WDNR issued the final modified WPDES permit for the Elm Road Facility with no substantive changes from the previously issued draft permit allowing for a once-through cooling system. The deadline for a legal challenge to the permit has expired without appeal.

On July 31, 2008, the joint owners of the Oak Creek expansion reached an agreement with Clean Wisconsin, Inc. and Sierra Club, the groups opposing the WPDES permit. Under the settlement agreement, these groups agreed to withdraw their opposition to the modified WPDES permit. The joint owners committed to various environmental projects, including projects designed to address greenhouse gas emissions and water quality. MGE's share of those commitments involved a payment of $0.4 million for greenhouse gas reduction efforts. Additional payments of approximately $0.3 million, subject to regulatory approval, will be made annually over 24 years (2011-2034) to address water quality issues in Lake Michigan. In December 2009, the PSCW authorized recovery of the 2011 payment to address water quality issues.

Solid waste

MGE is listed as a potentially responsible party for a site the EPA has placed on the national priorities Superfund list. The Lenz Oil site in Lemont, Illinois, was used for storing and processing waste oil for several years. This site requires clean up under the Comprehensive Environmental Response, Compensation and Liability Act. A group of companies, including MGE, is currently working on cleaning up the site. Management believes that its share of the final cleanup costs for the Lenz Oil site will not result in any materially adverse effects on MGE's operations, cash flows, or financial position. Insurance may cover a portion of the cleanup costs. Management believes that the cleanup costs not covered by insurance will be recovered in current and future rates. As of December 31, 2009, the EPA has agreed on a remedy for the Lenz Oil site. The remedy included a five year $2.2 million implementation plan. The EPA has asked all potentially responsible parties to pay upfront for this five year implementation plan. MGE's portion is less than $0.1 million.

MGE has been reviewing legislative and regulatory initiatives associated with ash storage and disposal, including potential regulations or legislation that may require new or additional monitoring of storage sites, may re-classify ash waste, and may regulate ash storage site structural design. Given the uncertainty surrounding these initiatives, it is not possible to estimate the potential costs associated with the implementation of any of these initiatives at this time.

Global climate change

MGE is a producer of GHG emissions, primarily from the fossil fuel generating facilities it utilizes to meet customers' energy needs, as well as from its natural gas pipeline system and fleet vehicles. Climate change and the regulatory response to it could significantly affect our operations in a number of ways, including increased operating costs and capital expenditures, restrictions on energy supply options, permitting difficulties and emission limits. However, the financial consequences of this compliance cannot be determined until final legislation and/or regulations are passed. MGE management would expect to seek and receive rate recovery of such compliance costs, yet the probability and specific impact of such regulation cannot be reasonably estimated at this time. MGE will continue to monitor proposed climate change legislation and regulation.

MGE is already addressing GHG emissions through voluntary actions. In 2005, MGE announced its Energy 2015 Plan which commits to ensuring a balanced, economic energy supply with reduced environmental emissions. The Plan emphasizes increased renewable energy, energy efficiency and new cleaner generation – three strategies that reduce GHG emissions. Under MGE's Energy 2015 Plan and other actions, our CO₂ emissions are currently projected to decline from 2005 to 2015 even though total system energy is estimated to increase. We are already well under way with implementing our Energy 2015 Plan strategies and are committed to achieving its goals. However, a number of factors, including but not limited to, changes in economic conditions, regulatory actions, customer response, energy supply issues and transmission delays, may require us to update and perhaps refine certain aspects of our Energy 2015 Plan accordingly. The cost of implementing our Energy 2015 Plan is not expected to result in any materially adverse effects on MGE's operations, cash flows, or financial position. Management believes that costs to implement the Energy 2015 Plan will be recoverable through rates.

EPA's Determination of Endangerment from Greenhouse Gases

On April 17, 2009, the EPA published a proposed finding that six greenhouse gases (GHGs) in the atmosphere endanger the public health and welfare of current and future generations. EPA further proposed finding that emission of these substances from new motor vehicles are contributing to this endangerment. On December15, 2009, the EPA finalized the endangerment finding for these six greenhouse gases and determined, through this finding, that these six GHGS, when emitted from new motor vehicles and new motor vehicle engines, contribute to the greenhouse gas air pollution and endangers public health and welfare under CAA Section 202(a). Although EPA states that finalizing these findings will not in and of itself impose requirements on electric generating utilities, this endangerment finding could be the first step toward regulating GHGs from electric generating facilities under the Clean Air Act. At this time we cannot predict the likelihood nor the effect of such regulation on our generating facilities. MGE is already addressing its GHGs through voluntary actions, and MGE will continue to monitor proposed GHG legislation and regulatory developments.

EPA Rule on Greenhouse Gas Reporting

On September 22, 2009, the EPA issued its final mandatory GHG reporting rule. Under the final rule MGE will need to report on GHG emissions from its natural gas distribution system, its electric generating units subject to the EPA's Acid Rain Program and certain of its stationary combustion and electric units during 2010. MGE is collecting the data needed to file the required report on 2010 emissions by March 31, 2011.

EPA's Proposed Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule

On September 30, 2009, the EPA proposed to set a significance level for GHGs under the Prevention of Significant Deterioration (PSD) and Title V programs of the Clean Air Act. These programs apply to electric generating units. In the rule proposal, the EPA explains that setting these significance levels is necessary because the EPA anticipates promulgating regulations that will trigger PSD and Title V applicability requirements for GHGs for electric generating sources (among other sources). Based on the significance levels now proposed by EPA, MGE has several electric generating units and other stationary combustion units that would be covered. The potential affects or cost of these proposed regulations on MGE are uncertain at this time.

Proposed Climate Change Legislation

On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (ACESA). The proposed legislation has several titles that would collectively impact virtually all aspects of the economy, including electric and natural gas utilities.

The proposed legislation includes: (1) a "clean energy" title that, among other things, creates a nationwide combined efficiency and renewable electricity standard that requires 6% efficiency/renewables by 2012 increasing to 20% by 2020 and calls for increased research and development; (2) an "energy efficiency" title that increases energy efficiency across all sectors of the economy, including buildings, appliances, transportation, and industry; (3) a "global warming" title that calls for a cap-and-trade program that would reduce U.S. emissions of GHGs economy-wide by 3% below 2005 levels in 2012, 20% below 2005 levels by 2020 and 83% below 2005 levels by 2050 and provides a methodology for distributing allowances to covered entities; and (4) a "transitioning" title that seeks to promote green jobs during the transition to a clean energy economy.

The U.S. Senate is also considering similar legislation. Any legislation passed by the Senate would need to be reconciled with the House legislation and signed by the President before it would become law.

The State of Wisconsin continues to consider GHG reductions through the implementation of recommendations made by Governor Doyle's Global Warming Task Force (July 2008 report). MGE participated as an active member of the Task Force. The report contained over 50 recommendations. Some specific recommendations of particular relevance to the utility industry include: (i) a significant increase in required energy efficiency efforts and funding; (ii) a State renewable portfolio standard that would require 10% renewables by 2013 and 25% by 2025; (iii) creation of a broad-based multi-sector carbon cap and trade program by 2012 at either the federal or regional level; (iv) investigation and possible adoption of new rate making approaches and innovative rate designs to promote state and utility energy efficiency programs and provide more information to customers; and (v) modification of Wisconsin's current restrictions on nuclear plant construction. Several PSCW proceedings have been commenced as a result of Task Force recommendations. Many of the recommendations made by the Global Warming Task Force have been included in legislation introduced in the Wisconsin Assembly and Senate on January 6, 2010 ("The Clean Energy Jobs Act", Senate Bill 450, Assembly Bill 649).

In addition, Wisconsin signed on to the Midwestern GHG Accord – an accord designed to develop a Midwestern GHG reduction program. While the reduction program has not been fully developed at this time, any actions taken by states within the Accord would require legislative action within that state.

Employees

As of December 31, 2009, MGE had 717 employees. MGE employs 238 employees who are covered by a collective bargaining agreement with Local Union 2304 of the International Brotherhood of Electrical Workers and 96 employees who are covered by a collective bargaining agreement with Local Union No. 39 of the Office and Professional Employees International Union. Both of these collective bargaining agreements expire on April 30, 2012. There are also 5 employees covered by a collective bargaining agreement with Local Union No. 2-111 of the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial, and Service Workers International Union. This collective bargaining agreement expires on October 31, 2012.

Financial Information About Segments

See Footnote 23 of the Notes to Consolidated Financial Statements for financial information relating to MGE Energy's and MGE's business segments.

Executive Officers of the Registrants

We face risk for the recovery of fuel and purchased power costs when they exceed the base rate established in MGE's current rate structure.

MGE burns natural gas in several of its peak electric generation facilities, and in many cases, the cost of purchased power is tied to the cost of natural gas. MGE bears significant regulatory risk for the recovery from customers of such fuel and purchased power costs when they are higher than the base rate established in its current rate structure.

We are subject to environmental laws and regulations that affect our costs and business plans.

Our subsidiaries are subject to environmental laws and regulations that affect the manner in which they conduct business, including capital expenditures, operating costs and potential liabilities. Changes and developments in these laws and regulations may change or limit our business plans, make them more costly to implement, or expose us to liabilities for past or current operations.

Numerous environmental regulations govern many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste; and continue to evolve in response to real or perceived concerns, regulatory initiatives, nongovernmental organizational initiatives and private parties and legal process. The development of these regulations can introduce uncertainty into the planning and implementation process for long-lead time projects, such as generating stations, and can introduce costly delays if previous decisions need to be revisited as a result of judicial mandate or regulatory change. These regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections, and other approvals, and can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These effects can be seen not only with respect to new construction, such as our participation in the Elm Road generating units, but could also require the installation of additional control equipment or the implementation of other compliance measures such as altered operating conditions.

In addition, we may be a responsible party for environmental clean-up at sites identified as containing hazardous materials. It is difficult to predict the costs potentially associated with a site clean-up due to the potential joint and several liability for all potentially responsible parties, the nature of the clean-up required and the availability of recovery from other potentially responsible parties.

We may incur material costs of compliance if federal and/or state legislation is adopted to address climate change.

Various persons, including legislators, regulators, litigants, and private parties, have increasingly expressed concern about the effects of global warming and the effects of greenhouse gases (GHG). These concerns have prompted active discussion on federal and state legislation, as well as regional initiatives, that would regulate or cap such emissions. There have been several proposed versions of legislation pending in the U.S. Congress and in the Wisconsin legislature to address global climate changes, including efforts to reduce and control and/or tax the emission of GHG, such as carbon dioxide, created in the combustion of fossil fuels, including coal, natural gas, and oil. Bills are also considering releases associated with natural gas pipelines and company fleets. These initiatives are sometime paired with efforts to mandate increasing percentages of electricity from renewable forms of energy, such as wind, or to reduce the demand for electricity. Such legislative and regulatory initiatives could have the potential for a significant financial impact on MGE, including the cost to install new emission control equipment, purchase allowances, or do fuel switching. However, the financial consequences of this compliance cannot be determined until final legislation is passed.

Operating Risk

We are affected by weather, which affects customer demand and can affect the operation of our facilities.

The demand for electricity and gas is affected by weather. Very warm and very cold temperatures, especially for prolonged periods, can dramatically increase the demand for electricity for cooling and heating, respectively, as opposed to the softening effect of more moderate temperatures. Our electric revenues are sensitive to the summer cooling season and, to a lesser extent, the winter heating season. Similarly, very cold temperatures can dramatically increase the demand for gas for heating. A significant portion of our gas system demand is driven by heating. Extreme summer conditions or storms may stress electric transmission and distribution systems, resulting in increased maintenance costs and limiting the ability to meet peak customer demand.

We are affected by economic activity within our service area.

Higher levels of development and business activity generally increase the numbers of customers and their use of electricity and gas. Likewise, periods of recessionary economic conditions generally adversely affect our results of operations.

Our ability to manage our purchased power costs is influenced by a number of uncontrollable factors.

We are exposed to additional purchased power costs to the extent that our power needs cannot be fully covered by the supplies available from our existing facilities and contractual arrangements. Those needs, and our costs, could be affected by:

·

Increased demand due to, for example, weather, customer growth, or customer obligations,

·

The inability to transmit our contracted power from its generation source to our customers due to transmission line constraints, outages, or equipment failures,

·

Reductions in the availability of power from our owned or contracted generation sources due to equipment failures, shortages of fuel or environmental limitations on operations, and

·

Failure to perform on the part of any party from which we purchase capacity or energy.

An unexpected change in demand or the availability of generation or transmission facilities can expose us to increased costs of sourcing electricity in the short-term market where pricing may be more volatile.

Our financial performance depends on the equipment and facilities in our distribution system being operational.

Weather conditions, accidents, catastrophic events, and failures of equipment or facilities can disrupt or limit our ability to deliver electricity and gas. Efforts to repair or replace equipment and facilities may not be successful, or we may be unable to make the necessary improvements to our distribution system, causing service interruptions. The resulting interruption of services could result in lost revenues and additional costs.

We face construction risk in connection with the completion of generating units.

We have assumed risks under the agreements related to our ownership interest in two 615 MW coal-fired generating units in Oak Creek, Wisconsin. The first unit has entered commercial operation; however, the second unit is subject to construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include but are not limited to the failure of the general contractor or subcontractors to perform under their contracts; strikes; adverse weather conditions; the inability to obtain necessary permits in a timely manner, legal challenges and appeals to granted permits, changes in applicable laws or regulations; governmental actions; and events in the global economy. In addition, if the units' final construction costs exceed the fixed costs allowed in the PSCW order, this excess will not be recoverable from MGE or its customers unless specifically allowed by the PSCW. Any Oak Creek project costs above the authorized amount, but below a 5% cap, will be subject to a prudence determination made by the PSCW.

Financial Risk

We are exposed to commodity price risk relating to our purchases of natural gas, electricity, coal and oil.

We face commodity price risk exposure with respect to our purchases of natural gas, electricity, coal and oil, SO₂ allowances and risk through our use of derivatives, such as futures, forwards and swaps, to manage that commodity price risk. We could experience increased costs as a result of volatility in the market values of those commodities. We could also experience losses on our derivative contracts as a result of that market value volatility or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these derivative contracts involves our exercise of judgment and use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

We are exposed to interest rate risk.

We are exposed to interest rate risk on our variable rate financing. MGE Energy had $114.5 million of variable-rate debt outstanding at December 31, 2009, including $33.5 million for MGE. Borrowing levels under commercial paper arrangements vary from period to period depending upon capital investments and other factors. Such interest rate risk means that we are exposed to increased financing costs and associated cash payments as a result of changes in the short-term interest rates. Also, interest rates affect discount rates which are a key assumption for our defined benefit pension plans and may impact the amount of expense and timing of contributions to the plan.

Market performance affects our employee benefit plan asset values.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy the future obligations under our pension and postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. A decline in the market value of those assets may increase our current and longer-term funding requirements for these obligations. Changes in the value of trust fund assets may affect the level of required contributions to these trusts to meet benefit obligations. Reduced benefit plan assets could result in increased benefit costs in future years and may increase the amount and accelerate the timing of required future funding contributions.

We are exposed to credit risk primarily through our regulated energy business.

Credit risk is the loss that may result from counterparty nonperformance. We face credit risk primarily through MGE's regulated energy business. Failure of contractual counterparties to perform their obligations under purchase power agreements, commodity supply arrangements or other agreements may result in increased expenses for MGE as a result of being forced to cover the shortfall in the spot or short-term market, where prices may be more volatile.

As a holding company, we are dependent on upstream cash flows from our subsidiaries for the payment of dividends on our common stock.

As a holding company, we have no operations of our own, our ability to pay dividends on our common stock is dependent on the earnings and cash flows of our operating subsidiaries and their ability to pay upstream dividends or to repay funds to us. Prior to funding us, our subsidiaries have financial obligations that must be satisfied, including among others, debt service and obligations to trade creditors, and are subject to contractual and regulatory restrictions on the payment of dividends.

Disruptions in the financial markets may affect our ability to finance at a reasonable cost and in accordance with our planned schedule.

The credit markets have experienced some disruption and uncertainty during the past year. To the extent that such issues affect the ability or willingness of credit providers or investors to participate in the credit markets or particular types of investments, or affect their perception of the risk associated with particular types of investments, our cost of borrowing could be affected.

General economic conditions may affect our operating revenues, our capital costs and our counterparty risks.

Operational

MGE Energy's and MGE's operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged period of reduced economic activity may include lower demand for energy, uncertainty regarding energy prices and the capital and commodity markets, and increased credit risk. A decline in energy consumption may adversely affect our revenues and future growth. Increased credit risk reflects the risk that our retail customers will not pay their bills in a timely manner or at all, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.

Liquidity

Long-term instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital. Although MGE Energy and MGE believe they have sufficient liquidity despite the disruption of capital and credit markets, the costs of such funds may increase.

Dividend Restrictions

Dividend payments by MGE to MGE Energy are subject to restrictions arising under a PSCW rate order and, to a lesser degree, MGE's first mortgage bonds. The PSCW order limits the amount of dividends that MGE may pay MGE Energy when its common equity ratio, calculated in the manner used in the rate proceeding, is less than 55%. Under those circumstances, MGE may not pay dividends in excess of $31.4 million plus dividends on shares issued in excess of the shares issued in the rate proceeding forecast if the proceeds are invested in MGE. MGE's thirteen month rolling average common equity ratio at December 31, 2009, is estimated to be 57.5% as determined under the calculation used in the rate proceeding. MGE paid cash dividends of $19.3 million to MGE Energy in 2009.The rate proceeding calculation includes as indebtedness imputed amounts for MGE's outstanding purchase power capacity payments and other PSCW adjustments, but does not include the indebtedness associated with MGE Power West Campus, which is consolidated into MGE's financial statements and will not include the indebtedness associated with MGE Power Elm Road, which will be consolidated into MGE's financial Statements.

MGE has covenanted with the holders of its first mortgage bonds not to declare or pay any dividend or make any other distribution on or purchase any shares of its common stock unless, after giving effect thereto, the aggregate amount of all such dividends and distributions and all amounts applied to such purchases, after December 31, 1945, shall not exceed the earned surplus (retained earnings) accumulated subsequent to December 31, 1945. As of December 31, 2009, approximately $229.0 million was available for the payment of dividends under this covenant.

Issuer Purchases of Equity Securities

MGE Energy

Issuer Purchases of Equity Securities

* Under the Stock Plan, common stock shares deliverable to plan participants may be either newly issued shares or shares purchased on the open market, as determined from time to time by MGE Energy. In June 2009, MGE Energy switched to using open market purchases to provide shares to meet obligations to participants in the Stock Plan. The shares are purchased on the open market through a securities broker-dealer and then are reissued under the Stock Plan as needed to meet share delivery requirements. The volume and timing of share repurchases in the open market depends upon the level of dividend reinvestment and optional share purchases being made from time to time by plan participants. As a result, there is no specified maximum number of shares to be repurchased and no specified termination date for the repurchases. All shares issued through the Stock Plan, whether newly issued or reissued following open market purchases, are issued and sold pursuant to a registration statement that was filed with the SEC and is currently effective.

MGE

None.

Item 6. Selected Financial Data.

MGE Energy

(In thousands, except per-share amounts)

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

General

MGE Energy is an investor-owned public utility holding company operating through subsidiaries in five business segments:

·

Electric utility operations, conducted through MGE,

·

Gas utility operations, conducted through MGE,

·

Nonregulated energy operations, conducted through MGE Power and its subsidiaries,

·

Transmission investments, representing our equity investment in ATC, and

·

All other, which includes corporate operations and services as well as certain construction services.

Our principal subsidiary is MGE, which generates and distributes electric energy, distributes natural gas, and represents a majority portion of our assets, liabilities, revenues, and expenses. MGE generates and distributes electricity to approximately 138,000 customers in Dane County, Wisconsin, including the city of Madison, and purchases and distributes natural gas to approximately 142,000 customers in the Wisconsin counties of Columbia, Crawford, Dane, Iowa, Juneau, Monroe, and Vernon.

Our nonregulated energy operations own interests in new electric generating capacity that is leased to MGE. The ownership/leasing structure was adopted under applicable state regulatory guidelines for MGE's participation in these generation facilities, consisting principally of a stable return on the equity investment in the new generation facilities over the term of the related leases. The nonregulated energy operations include partial ownership of a cogeneration project on the UW-Madison campus and an undivided 8.33% ownership interest in two 615 MW coal-fired generating units in Oak Creek, Wisconsin, one of which entered commercial operation on February 2, 2010 and the other of which is expected to enter commercial operation in August 2010. MGE operates the cogeneration project, and a third party operates the units in Oak Creek. Due to the nature of MGE's participation in these facilities, the results of our nonregulated operations are also consolidated into MGE's consolidated financial position and results of operations under applicable accounting standards.

Our primary focus today and for the foreseeable future is our core utility customers at MGE as well as creating long-term value for shareholders. MGE continues to face the challenge of providing its customers with reliable power at competitive prices. MGE plans to meet this challenge by investing in more efficient generation projects, including renewable energy sources. In the future, MGE will continue to focus on growing earnings while controlling operating and fuel costs. MGE will continue to maintain safe and efficient operations in addition to providing customer value. We believe it is critical to maintain a strong credit standing consistent with financial strength in MGE as well as the parent company in order to accomplish these goals.

Overview

We earn our revenue and generate cash from operations by providing electric and natural gas utility services, including electric power generation and electric power and gas distribution. The earnings and cash flows from the utility business are sensitive to various external factors, including:

·

Weather, and its impact on customer sales of electricity and gas,

·

Economic conditions, including current business activity and employment and their impact on customer demand,

·

Regulation and regulatory issues,

·

Energy commodity prices,

·

Equity price risk pertaining to pension related assets,

·

Credit market conditions, including interest rates and our debt credit rating,

·

Environmental laws and regulations, including pending environmental rule changes,

·

Construction risk in connection with the remaining Elm Road generating unit,

and other factors listed in "Item 1A. Risk Factors."

For the year ended December 31, 2009, MGE Energy's earnings were $51.0 million or $2.21 per share compared to $52.8 million or $2.38 per share for the same period in the prior year. MGE's earnings for the year ended December 31, 2009, were $35.9 million compared to $37.6 million for the same period in the prior year.

MGE Energy's income was derived from our business segments as follows:

Our net income during 2009 primarily reflects the effects of the following factors:

·

A 3.9% decrease in electric revenue, reflecting lower customer demand primarily as a result of cooler-than-normal weather. According to the National Weather Service, July 2009 was the coolest on record in Madison, where MGE's primary service territory resides. Cooling degree days (a measure for determining the impact of weather during the cooling season) for 2009 decreased by 32% compared to 2008. Reduced economic activity also contributed to the reduced demand for service.

·

Retail gas sales were relatively flat compared to last year. In 2008, the gas utility had expensed a $1.3 million settlement (excludes premium) associated with a weather hedge (heating degree collar) as a result of colder-than-normal weather. The gas utility had no weather hedges during 2009.

·

Higher nonregulated energy revenues primarily attributable to higher carrying costs being recognized for the Elm Road Units. Carrying costs during construction of the nonregulated energy projects, related to the equity portion, are recognized over the period of time the costs are recovered in rates.

·

A $0.6 million increase in earnings from our interest in ATC.

·

A decline in the All Other segment is primarily attributable to gains on sales of investments recognized in the year ended December 31, 2008.

Our net income during 2008 primarily reflects the effects of the following factors:

·

A 3.4% increase in electric revenues, reflecting a 4.8% rate increase approved by the PSCW, effective January 1, 2008, offset by lower demand due to cooler summer weather and lower sales for resale due to decreased sales opportunities.

·

Higher gas revenues, reflecting a 14.8% increase in delivered retail gas volumes due to colder winter weather and a 2.8% rate increase approved by the PSCW, effective January 1, 2008, partially offset by a $1.3 million expense (excludes premium) in 2008 on a settlement of a weather hedge (heating degree day collar) as a result of the colder weather. The weather hedge obligated MGE to pay additional costs if the weather was colder than a prescribed ceiling or would have compensated MGE if weather was warmer than a prescribed floor.

·

Higher nonregulated energy revenues primarily attributable to higher carrying costs, due to the greater capital investment, recognized for the Elm Road Units. Carrying costs during construction of the nonregulated energy projects, related to the equity portion, are recognized over the period of time the costs are recovered in rates.

·

A $0.7 million increase in earnings from our interest in ATC.

·

$2.9 million in earnings due to interdepartmental interest income recognized as a result of capitalized interest on the Elm Road Units and gains on sales of certain investments.

During 2009, the following events occurred:

ATC: MGE Transco contributed $3.6 million for voluntary capital contributions to ATC for the year ended December 31, 2009. An additional voluntary capital contribution of $0.5 million was made in January 2010.

WCCF: The State of Wisconsin did not exercise its option under the WCCF Joint Ownership Agreement to acquire from us a 45 MW interest in WCCF or to enter into a purchase power agreement for 45 MW of capacity. This option expired in the second quarter of 2009.

Elm Road Construction Claim: As described in Footnote 21, in December 2009, the project contractor for the Elm Road Units settled the claims initially made in December 2008. MGE Energy additional project costs decreased from the original claim of $39 million to $5.4 million. In addition, the project contractor will receive 120 days of schedule relief for Unit 1 and 60 days for Unit 2. Therefore, the guaranteed contract date of September 29, 2009, for Unit 1 was extended to January 27, 2010, and the guaranteed contract date of September 29, 2010, for Unit 2 was extended to November 28, 2010.

Wind Development Rights: In June 2009, MGE Energy, through its subsidiary MAGAEL, LLC, entered into agreements to purchase land development rights, including land option agreements, electrical interconnection rights, wind data, engineering plans, licenses, permits, and governmental approvals for two wind development sites. These wind development rights may potentially be used to develop wind farms in three counties in Iowa with a capacity up to approximately 175 MWs; however, neither MAGAEL nor MGE Energy has any obligation to build any wind generators at these sites.

2009 Fuel Credit: In May 2009, the PSCW approved an interim order authorizing MGE to implement an electric fuel credit, subject to refund with interest at 10.8%. In the year ended December 31, 2009, this fuel credit resulted in a $4.1 million reduction to electric revenues.

2008 Fuel Refund: As a result of lower-than-expected fuel and purchased power costs in 2008, a fuel refund was approved by the PSCW. The PSCW completed their audit and issued a final order in March 2009, which applied a $5.7 million (includes interest) refund to customers' accounts.

2010 Rate Filing: In December 2009, the PSCW authorized MGE to increase 2010 rates for retail electric customers by 3.3% and decrease rates for gas customers by 0.74%. The increase in retail electric rates was primarily driven by costs for MGE's share of the Elm Road Units and transmission reliability enhancements.

During 2010, several items may affect us, including:

·

General economic conditions: Economic conditions both inside and outside our service area are expected to continue to affect the level of demand for our utility services and may affect the collection of our accounts receivable and the creditworthiness of counterparties with whom we do business.

·

Credit Agreements: We have in place lines of credit aggregating $195 million for MGE Energy (including MGE) and $75 million for MGE to address our liquidity needs. Of the lines for MGE, $20 million expires in March 2010 and $55 million expires in December 2010. We do not expect any difficulties in replacing these lines of credit. Of the lines for MGE Energy, $40 million expires in August 2010 and $80 million expires in December 2010. MGE Energy's lines of credit have been used to help finance the Elm Road Units. Since a majority of Elm Road has been financed, the levels of credit needed in 2010 are expected to be lower. However, we expect that the borrowing costs will be higher under the replacement facilities than under the lines that expire in December 2010.

·

Elm Road Units: On February 2, 2010, Elm Road Unit 1 entered commercial operation, and Elm Road Unit 2 is expected to enter commercial operation in August 2010. On February 4, 2010, our subsidiary, MGE Power Elm Road, which owns an ownership interest in those Units, issued $50 million of its 5.04% senior secured notes. The proceeds of those notes were used to repay borrowings under our credit facilities. As a result, our outstanding borrowings and our borrowing needs are expected to be lower during 2010.

·

Smart Grid Investment Grant: MGE has been awarded a $5.5 million grant for smart grid technology from the U.S. Department of Energy (DOE) under the federal stimulus program. The DOE grant requires MGE to match 50% bringing the total cost to more than $11 million. The projects are expected to begin in early 2010.

·

Environmental Initiatives: There is proposed legislation, rules and initiatives involving matters related to air emissions, water effluent and greenhouse gases, all of which affect generation plant capital expenditures and operating costs as well as future operational planning. Such legislation could significantly affect the costs of owning and operating fossil-fueled generating plants, such as Columbia and Elm Road, from which we derive approximately 29% of our electricity generating capacity. We would expect to seek recovery on any such costs in rates; however, it is difficult to estimate the amount of such costs due to the uncertainty as to the timing and form of the legislation and regulations, and the scope and time of the recovery of costs in rates.

The following discussion is based on the business segments as discussed in Footnote 23.

Results of Operations

Year Ended December 31, 2009, Versus the Year Ended December 31, 2008

Electric sales and revenues

The following table compares MGE's electric revenues and electric kWh sales by customer class for each of the periods indicated:

Electric operating revenues decreased $13.6 million or 3.9% for the year ended December 31, 2009, due to the following:

·

Volume. During the year ended December 31, 2009, there was a 4% decrease in total retail sales volumes when compared to the same period in the prior year, as a result of cooler-than-normal weather. The demand for electricity is affected by weather conditions. According to the National Weather Service, July 2009 was the coolest on record in Madison, where MGE's primary service territory resides. Cooling degree days for 2009 decreased by 32% compared to 2008. Reduced economic activity also contributed to the reduced demand for service.

·

Rates changes. Rates charged to retail customers for the year ended December 31, 2009, were 2.1% or $7.6 million lower than those charged during the same period in the prior year.

On December 18, 2008, under a limited reopener, the PSCW authorized MGE to decrease 2009 rates for retail electric customers by 0.74% or $2.7 million from 2008. The decrease in retail electric rates is driven by a decrease in fuel and purchased power costs, a decrease in costs associated with the Elm Road Units and a decrease in ATC transmission costs. The PSCW also approved deferred accounting for incremental pension and other postretirement benefit costs above the levels currently included in rates.

As a result of lower than expected fuel and purchased power costs in 2008, a fuel refund was approved by the PSCW. In March 2009, the PSCW completed their audit of 2008 electric fuel costs and issued a final order approving the amount to be refunded to customers. A refund of $5.7 million (includes interest) was applied to customers' accounts in March 2009. See "Other revenues" discussion below for more information on this refund.

In May 2009, the PSCW approved an interim order authorizing MGE to implement a credit of $0.00204 per kWh, due to a decrease in actual electric fuel costs, when compared to those fuel costs projected in MGE's most recent rate order. During the year ended December 31, 2009, $4.1 million had been credited to electric customers. See "Other revenues" discussion below for more information on this interim order.

In 2008, the PSCW approved a $0.00239 per kWh interim fuel surcharge subject to refund, with interest, on MGE's electric rates to cover increased fuel and purchased power expenses. For the year ended December 31, 2008, this interim surcharge resulted in a $5.1 million increase to electric rates. See "Other revenues" below for additional information on this interim fuel surcharge.

·

Sales for resale. Sales for resale represent wholesale sales made to third parties who are not ultimate users of the electricity. These sales may include spot market transactions on the markets operated by MISO or PJM. These sales may also include bilateral sales to other utilities or power marketers. Generating units are dispatched by MISO based on cost considerations as well as reliability of the system. Sales for resale typically occur when MGE has more generation and purchases online than is needed for its own system demand. The excess electricity is then sold to others in the market. For the year ended December 31, 2009, sales for resale decreased $3.2 million when compared to the same period in the prior year, reflecting decreased opportunities for sales.

·

Other revenues. Other electric revenues increased $11.0 million for the year ended December 31, 2009, compared to the same period in the prior year.

As a result of the refund provision in the May 2008 interim fuel surcharge order, MGE recognized an estimated refund to customers totaling $5.5 million during the year ended December 31, 2008, and reflected this reduction in other electric revenues. During the year ended December 31, 2009, MGE recorded $5.5 million in other electric revenues to offset the impact of the 2008 fuel refund.

Also included in other revenues for the year ended December 31, 2009, is a $0.3 million projected refund which was accrued related to the May 2009 interim order.

Other electric revenues reflect the elimination of WCCF and Elm Road carrying costs that were collected in electric rates, which are recognized as nonregulated energy operating revenues in our Nonregulated Energy Operations segment. The amount eliminated was $10.7 million and $11.0 million for the years ended December 31, 2009 and 2008, respectively.

Electric fuel and purchased power

As a result of more favorable prices for purchased power as compared to internal generation, power purchases were increased, and internal generation reduced, causing fuel for electric generation to decrease and purchased power expense to increase.

The expense for fuel for electric generation decreased $17.9 million or 32.6% during the year ended December 31, 2009, compared to the same period in the prior year. This decrease in expense reflects a $12.8 million decrease related to the lower electric generation and a $5.1 million decrease related to fuel cost.

Purchased power expense increased by $10.4 million or 14.0% during the year ended December 31, 2009, compared to the same period in the prior year. This increase in expense reflects an $18.2 million or 27.3% increase in the volume of power purchased offset by a $7.8 million or 10.5% decrease in the per-unit cost of purchased power.

Electric operating and maintenance expenses

Electric operating and maintenance expenses decreased $4.6 million during the year ended December 31, 2009, compared to the same period in 2008. The following changes contributed to the net change:

For the year ended December 31, 2009, production costs and maintenance costs decreased due to lower internal generation, compared to the same period in the prior year. In addition, customer accounts costs decreased due to lower uncollectible accounts expense. Transmission costs increased primarily due to network service fees pertaining to ATC.

Electric depreciation expense

Electric depreciation expense increased $1.4 million for the year ended December 31, 2009, compared to the same period in the prior year as a result of additional electric plant assets.

Gas Utility Operations - MGE Energy and MGE

Gas deliveries and revenues

The following table compares MGE's gas revenues and gas therms delivered by customer class during each of the periods indicated:

Gas revenues decreased $50.3 million or 20.7% for the year ended December 31, 2009. These changes are related to the following factors:

·

Gas costs/rates. The average retail rate per therm for the year ended December 31, 2009, decreased 20.9% compared to the same period in 2008. The primary contributor to this decrease is significantly lower natural gas costs.

·

Transportation and other revenues. Transportation and other revenues decreased a total of $0.7 million primarily due to a decrease in income realized under the GCIM.

Under MGE's GCIM, if actual gas commodity savings and capacity release revenues are above or below a benchmark set by the PSCW, then MGE's gas sales service customers and shareholders share in any increased costs or savings per percentages set by the PSCW. For the year ended December 31, 2009 and 2008, shareholders received the benefit of $1.9 million and $2.4 million, respectively, from capacity release revenues and commodity savings under the GCIM.

Cost of gas sold

For the year ended December 31, 2009, cost of gas sold decreased by $48.5 million, compared to the same period in the prior year. The cost per therm of natural gas decreased 27.6% which resulted in $46.9 million of reduced expense. In addition, a 0.9% decrease in the volume of gas purchased resulted in $1.6 million less expense.

Gas operating and maintenance expenses

Gas operating and maintenance expenses decreased $1.7 million for the year ended December 31, 2009, compared to the same period a year ago. The following changes contributed to the net change.

Customer accounts costs decreased due to lower uncollectible accounts expense.

Gas depreciation expense

Gas depreciation expense increased $0.4 million for the year ended December 31, 2009, compared to the same period in the prior year as a result of additional gas plant assets.

Other Income (deductions), Net

Other income, net for the gas and electric segments increased $1.6 million for the year ended December 31, 2009, compared to the same period in the prior year. In 2008, the gas utility had expensed a $1.5 million settlement (includes premium) associated with a weather hedge (heating degree collar) as a result of colder-than-normal weather. The gas utility had no weather hedges during 2009. In addition, charitable contributions decreased by $1.5 million for the year ended December 31, 2009, compared to the prior year. Offsetting this change is a $0.8 million pretax gain on investments recognized in 2008 and a $0.4 million reduction in AFUDC-equity for the year ended December 31, 2009, compared to the prior year.

Nonregulated Energy Operations - MGE Energy and MGE

Nonregulated energy operating revenues

Operating revenues from nonregulated energy operations increased $1.7 million for the year ended December 31, 2009, when compared to the same period in the prior year. Operating revenues from nonregulated energy operations for both the year ended December 31, 2009 and 2008, include $14.9 million in interdepartmental revenues related to a leasing arrangement between MGE and MGE Power West Campus. Upon consolidation, these interdepartmental revenues are eliminated.

MGE also received approval from the PSCW to collect carrying costs expected to be incurred by MGE Power Elm Road during construction of the Elm Road Units. MGE estimates that the total carrying costs on the Elm Road Units will be approximately $59.5 million. A portion of this amount is being recognized over the period recovered in rates and a portion is being deferred and will be recognized over the period in which the Units are depreciated. See Footnote 21 for additional information regarding these carrying charges. For the year ended December 31, 2009 and 2008, MGE Power Elm Road recognized $8.1 million and $6.4 million, respectively, related to carrying costs on the Elm Road Units.

Nonregulated energy interest expense, net

For the year ended December 31, 2009 and 2008, interest expense, net at the nonregulated energy operations segment was $2.7 million and $2.6 million, respectively. Interest expense at the nonregulated energy segment for both the year ended December 31, 2009 and 2008, includes $2.8 million in interest expense incurred on $50 million of long-term, fixed-rate borrowings at MGE Power West Campus.

Also included in the nonregulated interest expense is interdepartmental interest expense and capitalized interest at MGE Power Elm Road. During the year ended December 31, 2009 and 2008, MGE Power Elm Road was charged $3.4 million and $4.8 million, respectively, in interest expense by Corporate on funds borrowed for the Elm Road Units. This expense is eliminated upon consolidation for MGE Energy only. The interest expense at MGE Power Elm Road is offset by $3.4 million and $4.8 million, respectively, in capitalized interest.

During the year ended December 31, 2009 and 2008, MGE Power Elm Road recorded $0.1 million in interest income on cash advanced to ERS for construction of transmission equipment and work done by ATC related to the Elm Road Units.

Transmission Investment Operations - MGE Energy and MGE

Transmission investment other income

For the year ended December 31, 2009 and 2008, other income at the transmission investment segment was $8.2 million and $7.2 million, respectively. The transmission investment segment holds our interest in ATC, and its income reflects our equity in the earnings of ATC. See Footnote 4.b for additional information concerning ATC and summarized financial information regarding ATC.

All Other - MGE Energy

All other - other income

Other income in the all other segment decreased $2.4 million for the year ended December 31, 2009, compared to the same period in the prior year primarily due to a $2.5 million pretax gain on investments recognized in the prior year.

All other interest income, net

All other interest income, net for the year ended December 31, 2009 and 2008, was $2.8 million. Interest income for the year ended December 31, 2009, represents $3.4 million in interdepartmental interest income from MGE Power Elm Road, partially offset by $0.6 million in interest expense on short-term debt. Interest income for the year ended December 31, 2008, represents $4.8 million in interdepartmental interest income from MGE Power Elm Road, partially offset by $2.0 million in interest expense on short-term debt. The interdepartmental interest income is eliminated upon consolidation.

Consolidated Other General Taxes

MGE Energy's and MGE's other general taxes increased $1.1 million or 6.3% for the year ended December 31, 2009, when compared to the same period in 2008, due to increased Wisconsin license fee tax. The annual license fee tax expense is based on the prior year's adjusted operating revenues. Tax rates have not increased.

Consolidated Income Taxes

MGE Energy's effective income tax rate for the year ended December 31, 2009, is 35.6% compared to 35.5% for the same period in 2008. MGE's effective income tax rate for the year ended December 31, 2009, is 35.4% compared to 35.2% for the same period in the prior year. The effective income tax rate differences for both MGE Energy and MGE for 2009 compared to 2008 are insignificant, as the effective income tax rate components are substantially equivalent.

Under 2009 Wisconsin Act 2, effective for years beginning on or after January 1, 2009, Wisconsin requires corporations to use combined reporting to compute their Wisconsin income for income tax purposes. Formerly, Wisconsin law required each corporation in a combined group to file separate returns. The combined reporting statute in Wisconsin did not have a significant impact on the effective income tax rates of MGE Energy and MGE.

For 2009 tax return purposes, MGE Energy and MGE will change its income tax methods of accounting for repairs based on current Treasury Regulations and case law. The change in income tax methods of accounting involves, among other things, identification of appropriate units of property for repair work and computation of a cumulative one-time tax deduction able to be claimed in 2009. The effect on the 2009 financial statements of the cumulative adjustment is an increase to deferred tax expense and a corresponding decrease in the current tax provision in the amount of about $9.2 million. The tax method change did not have an impact on income before income tax expense in the income statements of MGE Energy and MGE.

Noncontrolling Interest, Net of Tax

The noncontrolling interest, net of tax, reflects the accounting required for MGE Energy's interest in the WCCF and Elm Road Units. MGE Energy owns 100% of MGE Power West Campus and MGE Power Elm Road; however, due to the leasing arrangements for these projects with MGE, the entities are considered VIEs and their results are consolidated with those of MGE, the primary beneficiary of the VIEs. Also included in noncontrolling interest, net of tax, is MGE Energy's interest in MGE Transco.

For the year ended December 31, 2009, MGE Energy (through its wholly owned subsidiary MGE Power) earned $7.6 million and $4.9 million, net of tax, for its interest in MGE Power West Campus and MGE Power Elm Road, respectively. Additionally, MGE Energy earned $1.5 million, net of tax, for its interest in MGE Transco. These amounts are recorded as noncontrolling interest expense, net of tax, on MGE's consolidated statement of income.

For the year ended December 31, 2008, MGE Energy (through its wholly owned subsidiary MGE Power) had earned $7.6 million and $3.9 million, net of tax, for its interest in MGE Power West Campus and MGE Power Elm Road, respectively. Additionally, MGE Energy had earned $0.8 million, net of tax, for its interest in MGE Transco. These amounts are recorded as noncontrolling interest expense, net of tax, on MGE's consolidated statement of income.

Year Ended December 31, 2008, Versus the Year Ended December 31, 2007

Electric Utility Operations - MGE Energy and MGE

Electric sales and revenues

The following table compares MGE's electric revenues and electric kWh sales by customer class for each of the periods indicated:

Electric operating revenues increased $11.5 million or 3.4% for the year ended December 31, 2008, due to the following:

Rates changes. Rates charged to retail customers for the year ended December 31, 2008, were 7.8% or $25.7 million higher than those charged during the same period in the prior year. This increase includes a 4.8% rate increase authorized by the PSCW as well as the surcharge described below.

On December 14, 2007, the PSCW authorized MGE to increase 2008 electric revenue by $16.2 million to cover costs for MGE's new wind energy projects, statewide energy efficiency and renewable energy programs, transmission improvements by ATC, and accelerated costs to discontinue coal use at the Blount Station.

On May 5, 2008, the PSCW approved a $0.00239 per kWh interim fuel surcharge on MGE's electric rates to cover increased fuel and purchased power expenses. During the year ended December 31, 2008, this surcharge resulted in a $5.1 million increase to electric rates. A stipulation between MGE and the intervenors allowed the interim surcharge to remain in effect until the end of the year, but required MGE to review its 2008 monitored fuel costs at year-end and to refund to customers, with interest at 10.8%, any amount by which its actual fuel costs fell short of the monitored fuel costs collected in rates. See "Other revenues" below.

On April 24, 2007, when the PSCW completed their audit of 2006 electric fuel costs and issued a final order on the 2006 fuel credit, $2.4 million (related to 2006 fuel costs and including interest) was applied to customers' accounts.

Electric rates from April 26, 2007 to August 31, 2007, were subject to a $0.00339 per kWh interim fuel surcharge and subject to refund. On August 31, 2007, MGE received a final decision from the PSCW that reduced the fuel surcharge to $0.00242 per kWh effective the date of the order. This fuel surcharge resulted in a $5.6 million increase to electric rates charged to customers during the twelve months ended December 31, 2007.

On December 18, 2008, under a limited reopener, the PSCW authorized MGE to decrease 2009 rates for retail electric customers by 0.74% or $2.7 million from 2008. The decrease in retail electric rates is driven by a decrease in fuel and purchased power costs, decrease in costs associated with the Elm Road Units and a decrease in ATC transmission costs. The PCSW also approved deferred accounting for incremental pension and other postretirement benefit costs above the levels currently included in rates.

Volume. During the year ended December 31, 2008, total retail sales volumes were comparable to the same period in the prior year. Higher usage by other-retail/municipal customers was offset by a decline in residential, commercial and industrial usage.

Sales for resale. Sales for resale represent wholesale sales made to third parties who are not ultimate users of the electricity. These sales may include spot market transactions on the markets operated by MISO or PJM. These sales may also include bilateral sales to other utilities or power marketers. Generating units are dispatched by MISO based on cost considerations as well as reliability of the system. Sales for resale typically occur when MGE has more generation and purchases online than is needed for its own system demand. The excess electricity is then sold to others in the market. For the year ended December 31, 2008, sales for resale decreased $1.8 million when compared to the same period in the prior year. The decrease is primarily due to increased natural gas costs. During 2008, natural gas prices increased fairly rapidly until July before returning to previous levels. Electric prices on the MISO market did not experience the same price movement. MGE's sales for resale into the MISO market were lower as a result of the higher cost of gas fired generation relative to the market prices of electricity.

Other revenues. Other electric revenues decreased $10.6 million for the year ended December 31, 2008, compared to the same period in the prior year.

During the years ended December 31, 2008 and 2007, MGE recovered in electric rates carrying costs and other fees related to WCCF and Elm Road. During the years ended December 31, 2008 and 2007, MGE recorded a $11.0 million and $8.2 million reduction, respectively, to other electric revenues to transfer the revenues from the electric segment to the nonregulated energy operations segment. See discussion of these revenues in the "nonregulated energy operating revenues" section.

As a result of the refund provisions in the interim fuel surcharge order, MGE has recognized an estimated refund to customers totaling $5.5 million (includes interest) during the year ended December 31, 2008 and has reflected this reduction in other electric revenues.

During the year ended December 31, 2007, other electric revenues included a $2.3 million (excludes interest) upward adjustment to offset the impact on overall electric revenues for the 2006 fuel refund provided to customers in April 2007. Note that this refund was accrued in revenues during 2006, and was returned to customers via a reduction in rates in April 2007. See "Rate changes" above for more information on this refund.

Electric fuel and purchased power

The expense for fuel used for electric generation decreased $1.9 million or 3.4% during the year ended December 31, 2008, compared to the same period in the prior year. Lower fuel costs between the two periods resulted in a $1.5 million decrease of this expense and a decline in internal generation resulted in a $0.4 million decrease of this expense.

Purchased power expense decreased by $2.9 million or 3.8% during the year ended December 31, 2008, compared to the same period in the prior year. This decrease in expense reflects a $1.1 million or 1.5% decrease in the per-unit cost of purchased power and a $1.8 million or 2.3% decrease in the volume of power purchased.

Electric operating and maintenance expenses

Electric operating and maintenance expenses increased $14.8 million during the year ended December 31, 2008, compared to the same period in 2007. The following changes contributed to the net change:

As a result of the 2005 Wisconsin Act 141, each Wisconsin utility is required to pay 1.2% of its annual operating revenues to the statewide energy efficiency and renewable resource programs. MGE is allowed to recover these costs in rates through its conservation escrow. For the year ended December 31, 2008, costs associated with funding these programs increased customer service expense by $5.1 million. Transmission costs increased primarily due to network service fees pertaining to ATC.

Electric depreciation expense

Depreciation expense at the electric segment increased by $6.4 million for the year ended December 31, 2008, when compared to the same period in the prior year. This increase is related to higher levels of electric assets, including the Top of Iowa III wind-powered electric generating facility, which was placed in service in the first quarter of 2008. Also contributing to the increase is the accelerated depreciation of certain Blount assets. For additional information on the Blount accelerated depreciation, see Footnote 19.

Gas Utility Operations - MGE Energy and MGE

Gas deliveries and revenues

The following table compares MGE's gas revenues and gas therms delivered by customer class during each of the periods indicated:

Gas revenues increased $44.7 million or 22.6% for the year ended December 31, 2008. These changes are related to the following factors:

Gas costs/rates. The average retail rate per therm for the year ended December 31, 2008, increased 6.2% compared to the same period in 2007. The PSCW authorized a 2.8% increase in MGE's gas distribution rates effective January 1, 2008, to cover increased system demands and funding statewide energy programs. Also contributing to this increase is higher natural gas costs.

Retail gas deliveries. The 14.8% increase in retail gas deliveries for the year ended December 31, 2008, was attributable to cooler than normal weather, reflected in an 11.3% increase in the heating degree days between the periods, and increased use by a large commercial/industrial customer.

Transportation and other revenues. Transportation and other revenues increased a total of $1.9 million primarily due to an increase in income realized under the GCIM.

Under MGE's GCIM, if actual gas commodity savings and capacity release revenues are above or below a benchmark set by the PSCW, then MGE's gas sales service customers and shareholders share in any increased costs or savings per percentages set by the PSCW. For the years ended December 31, 2008 and 2007, shareholders received the benefit of $2.4 million and $0.9 million, respectively, from capacity release revenues and commodity savings under the GCIM.

Cost of Gas Sold

For the year ended December 31, 2008, cost of gas sold increased by $30.7 million, compared to the same period in the prior year. The volume of gas purchased increased 13.4% which resulted in $18.9 million of additional expense. In addition, the cost per therm of natural gas increased 7.4% which resulted in $11.8 million of additional expense.

Gas operating and maintenance expenses

Gas operating and maintenance expenses increased $5.5 million for the year ended December 31, 2008, compared to the same period a year ago. The following changes contributed to the net change:

As a result of the 2005 Wisconsin Act 141, each Wisconsin utility is required to pay 1.2% of its annual operating revenues to the statewide energy efficiency and renewable resource programs. MGE is allowed to recover these costs in rates through its conservation escrow. For the year ended December 31, 2008, costs associated with funding these programs increased customer service expense by $3.6 million.

Gas depreciation expense

Gas depreciation expense increased $0.6 million for the year ended December 31, 2008, compared to the same period in the prior year.

Other Income (Deductions), Net

During the year ended December 31, 2008, the gas and electric segments incurred $1.7 million in other deductions. The other deductions included a $1.5 million expense for a heating degree day collar, $1.8 million in charitable contributions, a $0.3 million loss related to an equity investment and $0.1 million of net miscellaneous expenses. See Footnote 16 for further discussion of the HDD collar. These deductions were partially offset by income of $0.9 million in AFUDC-equity, a $0.3 million gain on the sale of property, and a $0.8 million gain on investments.

For the year ended December 31, 2007, the gas and electric segments recognized a total of $1.9 million in AFUDC-equity, $0.2 million in equity earnings from miscellaneous investments, and a $0.8 million gain on the sale of investments. This income was offset by $0.3 million in premium expense for a HDD collar, $2.1 million in charitable contributions, and $0.4 million in net miscellaneous expenses.

Interest Expense, Net

For the year ended December 31, 2008, total interest expense for the electric and gas segments increased $1.4 million when compared to the same period in the prior year. For the year ended December 31, 2008, there was a $0.5 million decrease in AFUDC-debt (which is an increase to interest expense), a $0.5 million increase in interest expense on long-term debt, and a $0.6 million increase in net miscellaneous interest expense. These increases in interest expense were offset by a $0.2 million decrease in interest expense on short-term debt.

Nonregulated Energy Operations - MGE Energy and MGE

Nonregulated energy operating revenues

Operating revenues from nonregulated energy operations increased $2.3 million for the year ended December 31, 2008, when compared to the same period in the prior year. Operating revenues from nonregulated energy operations for both the years ended December 31, 2008 and 2007 include $14.9 million in interdepartmental revenues related to a leasing arrangement between MGE and MGE Power West Campus, which commenced on April 26, 2005. Upon consolidation, these interdepartmental revenues are eliminated.

MGE also received approval from the PSCW to collect carrying costs expected to be incurred by MGE Power Elm Road during construction of the Elm Road Units. MGE estimates that the total carrying costs on the Elm Road Units will be $61.3 million. A portion of this amount is being recognized over the period recovered in rates and a portion is being deferred and will be recognized over the period in which the Units are depreciated. For the years ended December 31, 2008 and 2007, MGE Power Elm Road recognized $6.4 million and $4.1 million, respectively, related to carrying costs on the Elm Road Units.

Nonregulated energy interest expense, net

For the years ended December 31, 2008 and 2007, interest expense, net at the nonregulated energy operations segment was $2.6 million and $2.5 million, respectively. Interest expense at the nonregulated energy segment for both the years ended December 31, 2008 and 2007, includes $2.8 million in interest expense incurred on $50 million of long-term, fixed-rate borrowings at MGE Power West Campus.

Also included in the nonregulated interest expense is interdepartmental interest expense and capitalized interest at MGE Power Elm Road. During the year ended December 31, 2008 and 2007, MGE Power Elm Road was charged $4.8 million and $3.9 million, respectively, in interest expense by Corporate on funds borrowed for the Elm Road Units. This expense is eliminated upon consolidation for MGE Energy only. The interest expense at MGE Power Elm Road is offset by $4.8 million and $3.9 million, respectively, in capitalized interest. MGE Power Elm Road is capitalizing interest on the Elm Road Units.

During the years ended December 31, 2008 and 2007, MGE Power Elm Road recorded $0.1 million and $0.2 million, respectively, in interest income on cash advanced to Elm Road Services, LLC for construction of transmission equipment and work done by ATC related to the Elm Road project.

Transmission Investment Operations - MGE Energy and MGE

For the years ended December 31, 2008 and 2007, other income at the transmission investment segment was $7.2 million and $6.0 million, respectively. The transmission investment segment holds our interest in ATC, and its income reflects our equity in the earnings of ATC. See Footnote 4.b for additional information concerning ATC and summarized financial information regarding ATC.

All Other - MGE Energy

All other - other income, net

The all other segment recorded $2.5 million in other income for the year ended December 31, 2008, primarily due to gains on sales of certain investments.

All other interest income, net

All other interest income, net for the years ended December 31, 2008 and 2007, was $2.8 million and $2.3 million, respectively. Interest income for the year ended December 31, 2008, represents $4.8 million in interdepartmental interest income from MGE Power Elm Road, partially offset by $2.0 million in interest expense on short-term debt. Interest income for the year ended December 31, 2007, represents $3.9 million in interdepartmental interest income from MGE Power Elm Road and $0.2 million in miscellaneous interest income, partially offset by $1.8 million in interest expense on short-term debt. The interdepartmental interest income is eliminated upon consolidation.

Consolidated Other General Taxes

MGE Energy's and MGE's other general taxes increased $1.0 million or 6.5% in 2008. This increase is primarily attributable to an increase in MGE's license fee tax. The annual license fee tax expense is based on adjusted operating revenues of the prior year.

Consolidated Income Taxes

MGE Energy's effective income tax rate for the year ended December 31, 2008, is 35.5% compared to 36.3% for the same period in 2007. This decrease is primarily attributable to the increased federal wind energy tax credit from the Top of Iowa III wind farm which was placed in service in 2008.

MGE's effective income tax rate for the year ended December 31, 2008, is 35.2% compared to 36.2% for the same period in the prior year. The decrease is also primarily attributable to the increased wind energy tax credit.

Noncontrolling Interest, Net of Tax

For the year ended December 31, 2008, MGE Energy (through its wholly owned subsidiary MGE Power) earned $7.6 million and $3.9 million, net of tax, for its interest in MGE Power West Campus and MGE Power Elm Road, respectively. Additionally, MGE Energy earned $0.8 million, net of tax for its interest in MGE Transco. These amounts are recorded as noncontrolling interest expense, net of tax, on MGE's consolidated statement of income.

For the year ended December 31, 2007, MGE Energy (through its wholly owned subsidiary MGE Power) had earned $7.7 million and $2.6 million, net of tax, for its interest in MGE Power West Campus and MGE Power Elm Road, respectively. Additionally, MGE Energy had earned $0.5 million, net of tax, for its interest in MGE Transco. These amounts are recorded as noncontrolling interest expense, net of tax, on MGE's consolidated statement of income.

Liquidity and Capital Resources

Cash Flows

The following summarizes cash flows for MGE Energy and MGE during the twelve months ended 2009, 2008, and 2007:

Cash Provided by Operating Activities

MGE Energy

MGE Energy's consolidated net cash provided by operating activities is derived mainly from the electric and gas operations of its principal subsidiary, MGE.

2009 vs. 2008

Cash provided by operating activities for the twelve months ended December 31, 2009, was $117.9 million, an increase of $43.2 million when compared to the same period in the prior year primarily due to working capital changes.

Working capital accounts resulted in $12.6 million in cash provided by operating activities for the twelve months ended December 31, 2009, compared to $32.2 million in cash used for operating activities during the same period in the prior year. The increase in cash provided by working capital accounts is primarily attributable to decreased inventory (due to lower natural gas costs), lower accounts receivable (due to lower sales and commodity costs), and reduced collateral postings in the derivative portfolio.

MGE Energy's net income decreased $1.8 million for the twelve months ended December 31, 2009, when compared to the same period in the prior year.

Cash flows related to tax effects increased $9.1 million for the twelve months ended December 31, 2009, compared to the twelve months ended December 31, 2008, primarily due to tax depreciation differences associated with bonus depreciation and the income tax methodology change for accounting of repairs.

Pension contribution resulted in an additional $7.6 million in cash used by operating activities for the twelve months ended December 31, 2009, when compared to the same period in the prior year. These contributions were made to comply with the Employee Retirement Income Security Act (ERISA) and the Pension Protection Act of 2006, and additional contributions were at management's discretion. See Footnote 13 for further discussion of MGE Energy's Pension and Other Postretirement Benefits.

2008 vs. 2007

Cash provided by operating activities for the twelve months ended December 31, 2008, was $74.7 million, a decrease of $1.9 million when compared to the same period in the prior year primarily as a result of changes in working capital.

Working capital accounts resulted in $32.2 million in cash used by operating activities for the twelve months ended December 31, 2008, compared to $9.2 million in cash used by operating activities during the same period in the prior year. Contributing to this change is a higher receivable – margin account balance as a result of additional margin calls associated with MGE Energy's financial and hedging instruments and a higher balance of stored natural gas.

MGE Energy's net income increased $3.9 million for the twelve months ended December 31, 2008, when compared to the same period in the prior year.

Depreciation for the twelve months ended December 31, 2008, was $39.3 million compared to $32.2 million in the same period in the prior year. This increase is primarily attributable to higher levels of assets, including the Top of Iowa III wind-powered electric generating facility, which was placed in service in the first quarter of 2008 as well as accelerated depreciation of certain Blount assets. For additional information on the Blount accelerated depreciation, see Footnote 19. Depreciation expense associated with Top of Iowa III and the Blount accelerated depreciation is being recovered in rates.

Deferred taxes increased $7.8 million for the twelve months ended December 31, 2008 compared to the twelve months ended December 31, 2007, primarily due to bonus tax depreciation as a result of the Economic Stimulus Act of 2008.

During the twelve months ended December 31, 2007, MGE Energy received $2.5 million in cash proceeds as a result of a Congestion Cost and Line Loss Allocation Services Agreement. In 2007, MGE, along with several other load serving entities in Wisconsin and Upper Michigan, signed a five year agreement in which the parties agreed to aggregate and equitably allocate specified costs that have not been perfectly allocated by the MISO Day 2 electricity market. Amounts collected in 2007 related to this agreement were returned to customers in 2008.

During the twelve months ended December 31, 2008 and 2007, MGE Energy made $7.7 million and $6.3 million, respectively, in discretionary contributions to the pension and other postretirement plans.

During the twelve months ended December 31, 2008, MGE Energy's other noncurrent items, net contributed to $6.0 million of operating inflows compared to $1.8 million of operating outflows for the twelve months ended December 31, 2007. Factors contributing to this change include regulatory assets for the conservation costs, debt related costs and Elm Road Units related costs, which are recovered through rates.

MGE

2009 vs. 2008

Cash provided by operating activities for the twelve months ended December 31, 2009, was $121.3 million, an increase of $47.0 million when compared to the same period in the prior year primarily due to working capital changes.

Working capital accounts resulted in $17.8 million in cash provided by operating activities for the twelve months ended December 31, 2009, compared to $33.7 million in cash used for operating activities during the same period in the prior year. The increase in cash provided by working capital accounts is primarily attributable to decreased inventory (due to lower natural gas costs), lower accounts receivable (due to lower sales and commodity costs), and reduced collateral postings in the derivative portfolio.

Net income decreased $1.7 million for the twelve months ended December 31, 2009, when compared to the same period in the prior year.

Cash flows related to tax effects increased $8.1 million for the twelve months ended December 31, 2009, compared to the twelve months ended December 31, 2008, primarily due to tax depreciation differences associated with bonus depreciation and the income tax methodology change for accounting of repairs.

Pension contribution resulted in an additional $7.6 million in cash used by operating activities for the twelve months ended December 31, 2009, when compared to the same period in the prior year. These contributions were made to comply with the Employee Retirement Income Security Act (ERISA) and the Pension Protection Act of 2006, and additional contributions were at management's discretion. See Footnote 13 for further discussion of MGE Energy's Pension and Other Postretirement Benefits.

2008 vs. 2007

Cash provided by operating activities for the twelve months ended December 31, 2008, was $74.3 million, a decrease of $4.2 million when compared to the same period in the prior year primarily as a result of changes in working capital.

Working capital accounts resulted in $33.7 million in cash used by operating activities for the twelve months ended December 31, 2008, compared to $7.6 million in cash used by operating activities during the same period in the prior year. Contributing to this change is a higher receivable – margin account balance as a result of additional margin calls associated with MGE's financial and hedging instruments and a higher balance of stored natural gas.

MGE's net income increased $0.5 million for the twelve months ended December 31, 2008, when compared to the same period in the prior year.

Depreciation for the twelve months ended December 31, 2008, was $39.3 million compared to $32.2 million in the same period in the prior year. This increase is primarily attributable to higher levels of assets, including the Top of Iowa III wind-powered electric generating facility, which was placed in service in the first quarter of 2008 as well as accelerated depreciation of certain Blount assets. For additional information on the Blount accelerated depreciation, see Footnote 19. Depreciation expense associated with Top of Iowa III and the Blount accelerated depreciation is being recovered in rates.

Deferred taxes increased $7.7 million for the twelve months ended December 31, 2008 compared to the twelve months ended December 31, 2007, primarily due to bonus tax depreciation as a result of the Economic Stimulus Act of 2008.

During the twelve months ended December 31, 2007, MGE received $2.5 million in cash proceeds as a result of a Congestion Cost and Line Loss Allocation Services Agreement. In 2007, MGE, along with several other load serving entities in Wisconsin and Upper Michigan, signed a five year agreement in which the parties agreed to aggregate and equitably allocate specified costs that have not been perfectly allocated by the MISO Day 2 electricity market. Amounts collected in 2007 related to this agreement were returned to customers in 2008.

During the twelve months ended December 31, 2008 and 2007, MGE made $7.7 million and $6.3 million, respectively in discretionary contributions to the pension and other postretirement plans.

During the twelve months ended December 31, 2008, MGE's other noncurrent items, net contributed to $6.0 million of operating inflows compared to $2.0 million of operating outflows for the twelve months ended December 31, 2007. Factors contributing to this change include regulatory assets for the conservation costs, debt related costs and Elm Road Units related costs.

Capital Requirements and Investing Activities

MGE Energy

2009 vs. 2008

MGE Energy's cash used for investing activities decreased $24.3 million for the twelve months ended December 31, 2009, when compared to the same period in the prior year.

Capital expenditures for the twelve months ended December 31, 2009, were $77.9 million. This amount represents a $27.8 million decrease from the expenditures made in the same period in the prior year. This decrease is related to lower construction activity of $22.8 million related to the Elm Road Units and a $7.8 million decrease of capital expenditures due to the completion in February 2008 of the Top of Iowa III wind generation project. These decreases were partially offset by an increase of $3.1 million in other utility capital expenditures.

During the twelve months ended December 31, 2009, MGE Energy received cash proceeds from the sale of equity investments of $0.1 million compared to the $3.6 million received for the same period in the prior year.

2008 vs. 2007

MGE Energy's cash used for investing activities decreased $30.5 million for the twelve months ended December 31, 2008, when compared to the same period in the prior year.

Capital expenditures for the twelve months ended December 31, 2008, were $105.8 million. This amount represents a $30.5 million decrease from the expenditures made in the same period in the prior year. This decrease is related to decreased construction activity for the Top of Iowa III wind generation project of $28.5 million and a decrease of $3.1 million for capital expenditures related to the Elm Road Units. These decreases were partially offset by increased construction activity in other utility capital expenditures of $1.2 million.

During the twelve months ended December 31, 2008, MGE Energy made a cash capital contribution of $3.4 million to ATC. During the twelve months ended December 31, 2007, MGE Energy did not make any cash capital contributions to ATC. However, during the twelve months ended December 31, 2007, MGE (through MGE Transco) transferred $1.4 million in certain transmission assets to ATC. In exchange for this transfer, MGE Transco received $0.7 million in cash proceeds and $0.7 million in an additional investment in ATC.

During the twelve months ended December 31, 2008, proceeds from the sale of property were $0.3 million. These proceeds primarily relate to the sale of nonutility property.

During the twelve months ended December 31, 2008, MGE Energy received $3.6 million in cash proceeds from the sale of equity investments compared to $0.9 million received during the twelve months ended December 31, 2007.

MGE

2009 vs. 2008

MGE's cash used for investing activities decreased $28.5 million for the twelve months ended December 31, 2009, when compared to the same period in the prior year.

Capital expenditures for the twelve months ended December 31, 2009, were $77.9 million. This amount represents a $27.8 million decrease from the expenditures made in the same period in the prior year. This decrease is related to lower construction activity of $22.8 million related to the Elm Road Units and a $7.8 million decrease of capital expenditures due to the completion in February 2008 of the Top of Iowa III wind generation project. These decreases were partially offset by an increase of $3.1 million in other utility capital expenditures.

During the twelve months ended December 31, 2009, MGE did not receive cash proceeds from the sale of equity investments compared to the $1.1 million received for the same period in the prior year.

2008 vs. 2007

MGE's cash used for investing activities decreased $27.3 million for the twelve months ended December 31, 2008, when compared to the same period in the prior year.

Capital expenditures for the twelve months ended December 31, 2008, were $105.8 million. This amount represents a $30.5 million decrease from the expenditures made in the same period in the prior year. This decrease is related to decreased construction activity for the Top of Iowa III wind generation project of $28.5 million and a decrease of $3.1 million for capital expenditures related to the Elm Road Units. These decreases were partially offset by increased construction activity for other utility capital expenditures of $1.2 million.

During the twelve months ended December 31, 2008, MGE (through MGE Transco) made a cash capital contribution of $3.4 million to ATC. During the twelve months ended December 31, 2007, MGE did not make any cash capital contributions to ATC. However, during the twelve months ended December 31, 2007, MGE (through MGE Transco) transferred $1.4 million in certain transmission assets to ATC. In exchange for this transfer, MGE Transco received $0.7 million in cash proceeds and $0.7 million in an additional investment in ATC.

During the twelve months ended December 31, 2008, proceeds from the sale of property were $0.3 million. These proceeds primarily relate to the sale of nonutility property.

Capital expenditures

The following table shows MGE Energy's budgeted capital expenditures for 2010 and actual capital expenditures for both 2009 and 2008:

MGE Energy intends to fund any remaining capital commitments for the Elm Road Units with funds generated from normal operations, the issuance of long-term debt, and short-term debt. MGE Energy's and MGE's liquidity is primarily affected by their construction requirements. On February 4, 2010, MGE Power Elm Road issued $50 million of its 5.04% senior secured notes due 2040, the proceeds of which were used to repay short-term debt. MGE Energy's major 2009 capital projects include Elm Road. During 2009, $27.2 million in capital expenditures were incurred for the construction of the Elm Road Units. Included in this amount is $3.4 million of interest capitalized.

As of December 31, 2009, MGE Power Elm Road's remaining capital commitments for the Elm Road Units are estimated to be $12.0 million. Based on current forecasts, capital expenditures for this project are expected to be $11.7 million in 2010 and $0.3 million in 2011. These amounts may change as a result of modifications to the project cost estimate or timing differences. See Footnote 21a for additional information.

MGE Energy used funds received as dividend payments from MGE Power West Campus as well as short and long-term external financing to meet its 2009 capital requirements and cash obligations, including dividend payments. External financing included short-term financing under existing lines of credit and proceeds from equity issued under the Stock Plan.

Financing Activities

MGE Energy

2009 vs. 2008

Cash used for MGE Energy's financing activities was $37.3 million for the twelve months ended December 31, 2009, compared to $29.9 million of cash provided by MGE Energy's financing activities for the twelve months ended December 31, 2008.

MGE Energy received $6.3 million and $31.0 million in cash proceeds as the result of stock issued pursuant to the Stock Plan during the twelve months ended December 31, 2009 and 2008, respectively.

As of June 1, 2009, MGE Energy is purchasing stock in the open market for its Stock Plan rather than issuing new shares. All MGE Energy common stock shares under the Stock Plan are sold pursuant to a registration statement that has been filed with the SEC and is currently effective.

For the twelve months ended December 31, 2009, dividends paid were $33.7 million compared to $31.8 million for same period in the prior year. This increase was a result of higher dividend per share ($1.46 vs. $1.43) and an increase in the number of shares outstanding.

For the twelve months ended December 31, 2009, net short-term debt repayments were $10.0 million compared to net short-term borrowings of $21.0 million for the same period in the prior year. An additional $50.0 million of short-term debt was reclassified as long-term debt for the twelve months ended December 31, 2009.

In the twelve months ended December 31, 2008, MGE Energy repaid $30.0 million of long-term debt and issued $40.0 million of long-term debt.

2008 vs. 2007

Cash provided by MGE Energy's financing activities was $29.9 million for the twelve months ended December 31, 2008, compared to $59.0 million for the twelve months ended December 31, 2007. MGE Energy's major capital expenditures (Top of Iowa III wind project and Elm Road Units) were primarily funded with short-term debt, the issuance of common stock and additional long-term debt.

MGE Energy received $31.0 million and $32.8 million in cash proceeds as the result of stock issued during the twelve months ended December 31, 2008 and 2007, respectively.

For the twelve months ended December 31, 2008, dividends paid were $31.8 million compared to $30.3 million for same period in the prior year. This increase was a result of a higher dividend per share ($1.43 vs. $1.41) and an increase in the number of shares outstanding.

MGE Energy repaid $30.0 million of long-term debt in the twelve months ended December 31, 2008, compared to $15.0 million in the twelve months ended December 31, 2007. MGE Energy issued $40.0 million of long-term debt in the twelve months ended December 31, 2008, compared to $25.0 million in the twelve months ended December, 2007.

For the twelve months ended December 31, 2008, net short-term debt borrowings were $21.0 million compared to $46.5 million for the same period in the prior year.

MGE

2009 vs. 2008

During the twelve months ended December 31, 2009, cash used for MGE's financing activities was $41.8 million compared to $32.0 million of cash provided by MGE's financing activities in the same period in the prior year.

For the twelve months ended December 31, 2009, net short-term debt repayments were $17.5 million compared to $10.0 million for the same period in the prior year.

Dividends paid from MGE to MGE Energy were $19.3 million for the twelve months ended December 31, 2009. No cash dividends were paid from MGE to MGE Energy for the twelve months ended December 31, 2008.

Equity contributions received by noncontrolling interest decreased $34.0 million as a result of MGE Power Elm Road requiring less funding for construction of property, plant and equipment. This decrease is slightly offset by $4.2 million of affiliate financing on the Elm Road Units received in the twelve months ended December 31, 2009.

In the twelve months ended December 31, 2008, MGE repaid $30.0 million of long-term debt and issued $40.0 million of long-term debt.

2008 vs. 2007

During the twelve months ended December 31, 2008, cash provided by MGE's financing activities was $32.0 million compared to of $56.2 million in the same period in the prior year.

No cash dividends were paid from MGE to MGE Energy for the twelve months ended December 31, 2008. For the twelve months ended December 31, 2007, cash dividends made from MGE to MGE Energy were $15.6 million.

MGE repaid $30.0 million of long-term debt in the twelve months ended December 31, 2008, compared to $15.0 million in the twelve months ended December 31, 2007.

MGE issued $40.0 million of long-term debt in the twelve months ended December 31, 2008, compared to $25.0 million in the twelve months ended December 31, 2007.

For the twelve months ended December 31, 2008, net short-term debt repayments were $10.0 million compared to net short-term issuance of $31.5 million for the same period in the prior year.

Dividend Restrictions

Dividend payments by MGE to MGE Energy are subject to restrictions arising under a PSCW rate order and, to a lesser degree, MGE's first mortgage bonds. The PSCW order limits the amount of dividends that MGE may pay MGE Energy when its common equity ratio, calculated in the manner used in the rate proceeding, is less than 55%. Under those circumstances, MGE may not pay dividends in excess of $31.4 million and $26.8 million for 2009 and 2008, respectively, plus dividends on shares issued in excess of the shares issued in the rate proceeding forecast if the proceeds are invested in MGE. MGE's thirteen month rolling average common equity ratio at December 31, 2009 and 2008, is estimated to be 57.5% and 50.4%, respectively, as determined under the calculation used in the rate proceeding. MGE was not restricted from paying cash dividends in 2009. Cash dividends paid to MGE Energy were reduced in 2009 and 2008 in order to build additional common stock equity in MGE. In 2009, $19.3 million cash dividends were paid to MGE Energy. MGE paid no cash dividends to MGE Energy in 2008. The rate proceeding calculation includes as indebtedness imputed amounts for MGE's outstanding purchase power capacity payments and other PSCW adjustments, but does not include the indebtedness associated with MGE Power West Campus, which is consolidated into MGE's financial statements and will not include the indebtedness associated with MGE Power Elm Road, which will be consolidated into MGE's financial statements.

MGE has covenanted with the holders of its first mortgage bonds not to declare or pay any dividend or make any other distribution on or purchase any shares of its common stock unless, after giving effect thereto, the aggregate amount of all such dividends and distributions and all amounts applied to such purchases, after December 31, 1945, shall not exceed the earned surplus (retained earnings) accumulated subsequent to December 31, 1945. As of December 31, 2009, approximately $229.0 million was available for the payment of dividends under this covenant.

Credit Facilities

At December 31, 2009, MGE Energy and MGE had the following aggregate bank commitments and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

Borrowings under each credit agreement may bear interest at a rate that floats daily based upon a prime rate or at a rate fixed for a specified interest period based upon a LIBOR-based index, plus an adder. In the case of the LIBOR-based rates, the adder is based upon the senior unsecured credit rating for MGE and does not exceed 0.075% for the agreements expiring in December 2010, the adder is a flat 1% for the agreement expiring in March 2010, and the adder is a flat 1.5% for the agreement expiring in August 2010. For the agreements expiring in March 2010 and August 2010, the daily floating rate is, in effect, subject to a floor of a LIBOR-based rate plus 1%.

Our current credit agreements expire during 2010. We do not expect any difficulties in renewing or replacing these lines of credit. MGE Energy's lines of credit have been used to help finance the Elm Road Units. Since a majority of Elm Road has been financed, the levels of credit needed in 2010 are expected to be lower. However, we expect that the borrowing costs will be higher under the replacement facilities than under the lines that expire in December 2010.

The agreements require the borrower to maintain a ratio of consolidated debt to consolidated total capitalization not to exceed a maximum of 65%. The ratio calculation excludes assets, liabilities, revenues and expenses included in MGE's financial statements as a result of the consolidation of VIEs, such as MGE Power West Campus and MGE Power Elm Road. At December 31, 2009, the ratio of consolidated debt to consolidated total capitalization for each of MGE Energy and MGE were 43.5% and 39.6%, respectively. See Footnote 10, for additional information regarding the credit facilities.

Capitalization Ratios

MGE Energy's capitalization ratios were as follows:

Credit Ratings

The following table shows MGE's current credit ratings. The ratings presented reflect the current views of these rating agencies and are subject to change. MGE Energy is not rated because it has not issued any debt securities.

On November 12, 2009, Standard and Poor's reaffirmed MGE's corporate credit rating of AA- and indicated that the rating outlook was stable. In its release, S&P noted that MGE's creditworthiness reflects an excellent business risk profile and an intermediate financial profile that will remain under pressure over the next couple of years due to a heavy capital spending cycle, including construction expenditures and expenditures on environmental initiatives associated with its joint ownership interest in the Columbia coal-fired generating station.

On December 18, 2009, Moody's announced that it had placed MGE's unsecured credit rating (Aa3) under review for possible downgrade. Moody's release indicated that the review will assess the specifics of MGE's recent rate case, its implications for MGE's future performance, and future capital spending requirements. Moody's stated its belief that the outcome of the rating review is likely to be limited to no more than a one notch change in MGE's senior unsecured ratings. Moody's expects the secured rating to remain unchanged at Aa2.

A security rating is not a recommendation to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. MGE's access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities' ratings. None of MGE's borrowing is subject to default or prepayment due to downgrading of securities' ratings, although such a down grading could increase fees and interest charges under MGE Energy's and MGE's credit facilities.

Capital and Credit Markets

The uncertainty in the capital and credit markets has adversely affected the United States and global economies during the past year. These events have the potential to create additional risks for businesses, including MGE Energy and MGE, during 2010. MGE Energy and MGE have performed additional analyses to determine the potential impact, if any, of recent market conditions on its financial statements. These analyses and assessments include counterparty creditworthiness, value of our investments, access to liquidity in the capital and credit markets, and exposure to operational risk.

Operational

MGE Energy's and MGE's operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity, uncertainty regarding energy prices and the capital and commodity markets, and increased credit risk. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Increased credit risk reflects the risk that our retail customers will not pay their bills in a timely manner or at all, which may lead to a reduction in liquidity and an eventual increase in bad debt expense. 

Liquidity

The capital markets have recovered from last year's instability and access to capital is not as much of an issue as it was a year ago. MGE Energy and MGE continue to maintain adequate liquidity for its short term needs. MGE Energy's and MGE's liquidity position improved due to the lower natural gas costs. In February 2010, MGE Energy issued $50 million in long term debt and may issue additional long term debt for Elm Road Unit 2 later in 2010. The proceeds from the additional long term debt will be used to pay down MGE Energy's line of credit.

Counterparty creditworthiness

Credit risk also includes the risk that trading counterparties that owe us money or product will breach their obligations. MGE's risk management policy is to limit transactions to a group of high quality counterparties. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

Pension

MGE sponsors defined benefit pension plans and postretirement benefits plans for our employees. The oversight on the investments held in the plans is substantial, and we followed established investment policies and practices. Substantial changes in the value of trust fund assets may affect the level of required contributions to these trusts to meet benefit obligations.

Insurance

MGE Energy has reviewed its exposure to insurance risk and has concluded that there are no material changes related to the cost or availability of liability, property and other forms of insurance. Management continues to monitor closely events and the ratings for insurance companies associated with insurance programs.

Contractual Obligations and Commercial Commitments for MGE Energy and MGE

MGE Energy's and MGE's contractual obligations as of December 31, 2009, representing cash obligations that are considered to be firm commitments, are as follows: