MGE ENERGY INC - Quarter Report: 2009 September (Form 10-Q)

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

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$40 million, extends the expiration date from September 30, 2009, to August 27, 2010, and increases the adder used in the calculation of the "Eurodollar Rate" interest rate option. The increased commitment replaces a $20 million commitment on MGE Energy's credit agreement dated as of August 29, 2008, with the lenders named therein and JPMorgan Chase Bank, N.A., as administrative agent, which expired pursuant to its terms on August 28, 2009. As of September 30, 2009, no borrowings were outstanding under this credit facility. As amended, the credit facility carries interest at either (i) a "floating rate," calculated on a daily basis as the highest of a prime rate, a Federal Funds effective rate plus ½% per annum, or a Eurodollar-based rate for a one month interest period plus 1% or (ii) a "Eurodollar Rate," calculated as provided in the credit agreement for the selected interest period, plus 1.5%.

Comprehensive Income - MGE Energy and MGE.

Total comprehensive income represents the change in equity during a period from transactions and other events and circumstances from nonowner sources. MGE Energy's and MGE's total comprehensive income is:

Investments - MGE Energy and MGE.

Investment in ATC.

ATC owns and operates electric transmission facilities primarily in Wisconsin. MGE received an interest in ATC when it, like other Wisconsin electric utilities, contributed its electric transmission facilities to ATC. That interest is presently held by MGE Transco, which is jointly owned by MGE Energy and MGE.

MGE Transco, through MGE, has a seat on the Board of Directors of ATC and has a 20% voting ownership interest in ATC Management, Inc. Due to MGE Transco's ability to exercise significant control over management activities, MGE Transco has accounted for its investment in ATC under the equity method of accounting. For the nine months ended September 30, 2009 and 2008, MGE Transco recorded equity earnings from the investment in ATC of $6.1 million (pretax) and $5.3 million (pretax), respectively. Dividend income received from ATC was $4.7 million and $3.8 million for the nine months ended September 30, 2009 and 2008, respectively. During the nine months ended September 30, 2009 and 2008, MGE Transco made capital contributions of $2.5 million and $2.3 million, respectively.

At September 30, 2009, MGE is the majority owner and MGE Energy, the holding company, is the minority owner of MGE Transco. MGE Energy's proportionate share of the equity and net income of MGE Transco is classified within the MGE financial statements as noncontrolling interest.

ATC's summarized financial data for the three and nine months ended September 30, 2009 and 2008, is as follows:

Other Investments.

MGE Energy and MGE hold available for sale securities in both publicly traded and privately held companies. During the three and nine months ended September 30, 2009, no investments were liquidated. However, during the three and nine months ended September 30, 2008, certain investments were liquidated. As a result of these liquidations, MGE Energy and MGE received $2.3 million and $0.8 million, respectively, in cash proceeds. In addition, MGE Energy recorded a receivable of $1.0 million. MGE Energy and MGE recorded a $2.8 million and $0.5 million pretax gain on the sale of investments, respectively, in the income statement for the three and nine months ended September 30, 2008.

Taxes - MGE Energy and MGE.

Accounting for Uncertainty in Income Taxes.

MGE Energy and MGE account for the difference between the tax benefit amount taken on prior year tax returns, or expected to be taken on a current year tax return, and the tax benefit amount recognized in the financial statements as an unrecognized tax benefit.

For both MGE Energy and MGE, there have been no changes to unrecognized tax benefits existing at December 31, 2008, nor any additions for new tax positions, during the nine months ended September 30, 2009.

Effective Tax Rate.

MGE Energy's effective income tax rates for the three and nine months ended September 30, 2009, are 35.4% and 35.2%, respectively, compared to 36.0% and 35.8% for the same periods in 2008. These decreases are primarily attributable to increases in the federal tax credit for producing electricity from wind energy. Federal law allows a tax credit of 2.1 cents per kilowatt hour of electricity produced and sold from wind energy. The tax credit for 2009 is expected to exceed the credit for 2008 mainly due to the full year generation expected from Top of Iowa III wind farm in 2009. In 2008, wind generation from that wind farm occurred for approximately ten months.

MGE's effective income tax rates for the three and nine months ended September 30, 2009, are 35.2% and 35.0%, respectively, compared to 35.5% and 35.5% for the same periods in 2008. These decreases are similarly due to an increased wind energy tax credit expected for 2009.

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 effect of the combined reporting statute in Wisconsin is not expected to make any significant changes to the effective income tax rate or the tax accrual.

Elm Road - MGE Energy and MGE.

Construction.

On November 4, 2005, MGE Power Elm Road acquired an 8.33% ownership interest in each of two 615 MW coal-fired generating units being constructed in Oak Creek, Wisconsin. MGE Power Elm Road's sole principal asset is that ownership interest in those generating units. Each owner provides its own financing and reflects its respective portion of the facility and costs in its financial statements. The estimated share of capital costs for that ownership interest in both units is approximately $172 million (excluding capitalized interest).

In July 2008, the Elm Road construction contractor, Bechtel, gave notice forecasting that the in-service date of Unit 1 would be delayed by three months from the guaranteed in-service date of September 29, 2009, and that the in-service date of Unit 2 would be one month earlier than the guaranteed in-service date of September 29, 2010. The notice stated that the delays in Unit 1 were caused by severe weather, changes in local labor conditions from those anticipated by the contractor and other factors. On December 23, 2008, we received notice from Elm Road Services, LLC (ERS) that it had received a letter from Bechtel containing Bechtel's formal claim for schedule and cost relief on the construction of the Elm Road units. On November 2, 2009, we received notice from ERS that Bechtel amended its claim to increase its request for cost relief to approximately $32.5 million and for schedule relief by approximately one month for both Unit 1 and Unit 2. Bechtel is constructing the Elm Road units under a turnkey engineering, procurement and construction contract (the "Contract") with ERS, which is the project manager for the Elm Road units.

MGE Power Elm Road has leased the Elm Road units to MGE pursuant to separate facility lease agreements for each unit. These leases were authorized by order of the PSCW in accordance with applicable provisions of Wisconsin law that authorized financing of new generation through facility leases. The PSCW order establishes a cap on the construction costs that may be passed through the lease agreements to MGE and its customers, through rates. Additional costs attributable to force majeure events, as defined in the leases, do not count against this cap, but are subject to PSCW review and determination that the costs were prudently incurred.

As amended, Bechtel's claim asserts two claims for cost and schedule relief:

The first claim is based on the alleged impact of severe weather and specified labor-related matters. It seeks compensation for additional costs of approximately $445.5 million, of which MGE Energy's share would be approximately $37.1 million, if the claim is successful in full. Bechtel has reserved the right to request future additional costs and schedule relief. Bechtel seeks cost and schedule relief for weather-related events, which it contends are force majeure events and changed local conditions under the Contract, consisting of extreme winds from September 2006 through April 2007, snowstorms from December 2007 through April 2008, rain storms in June 2008, and adverse weather conditions during the 2008-2009 winter. It also seeks cost and schedule relief based upon alleged changes in labor conditions, which it contends consisted of a significant shortage in the availability of craft labor, significant increases in competing projects, overtime and per diems allegedly necessary to attract labor, and alleged restrictions that the project labor agreement placed on Bechtel's ability to attract and retain craft labor.

The second claim is based upon the alleged effects of ERS-directed changes and ERS-caused delays prior to the issuance of the full notice to proceed (FNTP) in July 2005. It seeks compensation for additional costs of approximately $72 million, of which MGE Energy's share would be approximately $6 million, if the claim is successful in full. These changes and delays are alleged to consist of a delay in issuing certain limited notices to proceed, a delay in issuing the FNTP until the final resolution of litigation brought by opposition groups that challenged the Certificate of Public Convenience and Necessity for the Elm Road units, the imposition of additional limits to third party cancellation charges that allegedly restricted Bechtel's ability to issue purchase orders, a reduction of the pre-FNTP monthly payments below the amounts required by the Contract, and a request by ERS to perform design studies and issue design changes during the pre-FNTP period.

Although ERS continues to analyze the claims and its responses to them, it has stated its belief that both claims are without merit. It has also stated its view that the only circumstances and events for which the Elm Road units' owners currently retain price adjustment risk under the contract are force majeure, wage escalation in excess of 4% annually as measured by published wage bulletins, delays caused by ERS, changes in scope or performance requested by ERS, and unforeseen sub-surface ground conditions. ERS has stated that it

currently believes Bechtel was fully compensated for any and all impacts of the delayed start as indicated in certain change orders entered into between ERS and Bechtel prior to the start of construction of the Elm Road units. Furthermore, ERS has stated that it does not believe that the contract provides for relief based upon the cumulative impact of change orders.

ERS invoked the dispute resolution process provided for in the contract in order to address the claims made by Bechtel under the contract. ERS and Bechtel agreed to combine these issues and Bechtel's claims into one mediation. Mediation was unsuccessful and therefore, both parties submitted the matter to binding arbitration pursuant to the contract. The arbitration is expected to be concluded in 2010 or early 2011. We are unable to predict the results of these claims or their effect on the costs recoverable under the existing facility leases, in the event that the outcome of the claims should cause total construction costs of the Elm Road units to exceed the amounts authorized in the PSCW order.

Bechtel continues to target an in-service date for Elm Road Unit 1 three months beyond the guaranteed date of September 29, 2009, and an in-service date for Elm Road Unit 2 one month earlier than the guaranteed date of September 29, 2010. However, in its amended claim Bechtel requests schedule relief that would result in approximately seven months of relief from liquidated damages beyond the guaranteed in-service date for Unit 1 and approximately four months of relief from liquidated damages beyond the guaranteed in-service date for Unit 2. ERS has informed us that although Bechtel has fallen slightly behind these dates, Bechtel has recovery plans in place and believes these target dates are achievable. However, the final few months of start-up and commissioning could present unforeseen challenges that may delay the in-service date for Elm Road Unit 1 beyond December 29, 2009.

At September 30, 2009, $161.1 million (excluding capitalized interest) related to this project is reflected in the construction work in progress balance on MGE Energy's and MGE's consolidated balance sheets. MGE Power Elm Road calculates capitalized interest on the Elm Road project. At September 30, 2009, MGE Power Elm Road recorded a total of $13.4 million in capitalized interest related to the Elm Road project which is reflected in the construction work in progress balance on MGE Energy's and MGE's consolidated balance sheets.

Consolidation.

In connection with this project, MGE Energy and its subsidiaries entered into various agreements, including facility lease agreements between MGE Power Elm Road (a nonregulated subsidiary of MGE Energy) and MGE with respect to each of the generating units. The financial terms of the facility leases include a capital structure of 55% equity and 45% long-term debt, return on equity of 12.7%, a lease term of 30 years, and a 5% lease payment reduction in the first five years.

Based on the nature and terms of the leasing agreements and the relationship they establish, MGE absorbs a majority of the expected losses, residual value, or both, associated with the ownership of MGE Power Elm Road. MGE also is the party most closely associated with MGE Power Elm Road. As a result, MGE is the primary beneficiary and MGE Power Elm Road is a VIE under applicable accounting requirements. Accordingly, MGE Power Elm Road has been consolidated in the financial statements of MGE.

MGE Energy's share of the equity and net income (through its wholly owned subsidiary MGE Power) of MGE Power Elm Road is classified within the MGE financial statements as noncontrolling interest.

Nonregulated Revenues.

MGE has approval from the PSCW to defer the recovery of the payments made to MGE Power Elm Road for carrying costs during construction of the generating units, management fees, and community impact mitigation costs. MGE estimates that the total carrying costs on the Elm Road project will be approximately $58.4 million. This estimate is subject to change based on changes in interest rates, timing of capital expenditures, and the total project cost.

MGE began collecting the carrying costs in rates in 2006. These amounts are being collected over multiple years. Of these costs, MGE estimates that $17.9 million relates to the capitalized interest and the debt portion of the facility. These costs will be recognized over the period in which the generating units will be depreciated. The remaining $40.5 million is estimated to represent the equity portion and is being recognized over the period allowed for recovery in rates.

During 2009, MGE will recover $11.1 million in electric rates for its investment in MGE Power Elm Road. Of this amount, $9.5 million relates to carrying costs and $1.6 million relates to management fees, community impact mitigation costs, and other related costs. For the nine months ended September 30, 2009, $7.1 million related to the carrying costs were recovered in rates. Of this amount, $1.0 million relates to the debt portion of the facility and was deferred on the consolidated financial statements of MGE Energy and MGE. The remaining $6.1 million represents the equity portion and was recognized as nonregulated revenues in the consolidated financial statements of MGE Energy and MGE.

Pension and Postretirement Plans - MGE Energy and MGE.

MGE maintains qualified and nonqualified pension plans, health care, and life insurance benefits. Additionally, MGE has deferred contribution 401(k) benefit plans.

The following table presents the components of MGE Energy's and MGE's net periodic benefit costs recognized for the three and nine months ended September 30, 2009 and 2008. A portion of the net periodic benefit cost is capitalized within the consolidated balance sheets. For the three and nine months ended September 30, 2009, $2.0 million and $5.8 million, respectively, of the net periodic benefit cost has been deferred on the consolidated balance sheet as a result of PSCW approval.

During the nine months ended September 30, 2009 and 2008, MGE recorded $0.7 million and $0.4 million, respectively, in compensation expense as a result of this plan. No forfeitures or cash settlements occurred during the nine months ended September 30, 2009. A forfeiture, but no cash settlements, occurred during the nine months ended September 30, 2008. At September 30, 2009, $0.1 million of these awards were vested.

Commitments and Contingencies.

Environmental - MGE Energy and MGE.

Solid Waste

MGE is listed as a potentially responsible party for the Lenz Oil site in Lemont, Illinois, which is a site on the national priorities Superfund list. This site 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 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. At September 30, 2009, MGE accrued a $0.1 million gross liability for this matter. The expected range of loss for this item is estimated to be between $0.1 million and $0.2 million.

Water Quality

MGE is subject to various water quality regulations issued by the WDNR. These regulations limit chemical and thermal discharges from MGE's plants and activities into Wisconsin waters. These regulations also limit water intake from new and existing power plants. EPA's proposed regulations regarding water intake from existing power plants continue to evolve and MGE is monitoring these regulations to determine the effect on our facilities.

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 Elm Road to be impacted by these rules.

Energy Efficiency and Renewables

Effective March 31, 2006, Wisconsin adopted the Energy Efficiency and Renewables Act that focuses on three areas: increasing the use of renewable energy in Wisconsin, promoting the development of renewable energy technologies, and strengthening the state's energy efficiency programs. This legislation requires that by 2015, 10% of the state's electricity be generated from renewable resources. MGE expects the cost to comply with the Act and its accompanying regulations will be recoverable through current and future 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 (SO ₂), 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, but not limited to, the Clean Air Interstate Rule (CAIR), new source performance standards (NSPS), Clean Air Visibility Rule (CAVR), the protection of visibility by application of best available retrofit technologies (BART), and Wisconsin's mercury rules under NR 446, are expected to result in significant additional operating and capital expenditures at Columbia, Elm Road, and Blount.

On September 16, 2009, the EPA announced that it is reconsidering the March 12, 2008, ozone standard. As part of this reconsideration EPA intends to review both the primary (set for protection of public health) and secondary (set for protection of public welfare and environment) ozone standards. The EPA intends to propose any revisions to the standard by December 2009. At this time, without a proposed standard from the EPA, we are unable to determine whether or not the counties of Dane, Columbia and/or Milwaukee, (where our generation facilities are located) will be in attainment with the potential revised standard (i.e., have ambient air quality that is at or below the attainment level selected by the EPA). A nonattainment designation

for ozone 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).

The 2006 standard for fine particulate emissions under 2.5 microns and monitoring data has resulted in EPA previously announcing its preliminary intent to designate Dane, Columbia, and Milwaukee counties (among others) as nonattainment for fine particulate under the 2006 standard. A nonattainment designation could result in increased expenditures at our generation facilities. On October 8, 2009, EPA announced its final PM2.5 attainment designations for Wisconsin using the 2006 through 2008 data and only Milwaukee, Racine and Waukesha Counties were designated as nonattainment. (See the Federal National Ambient Air Quality Standards subsection within the Environmental Matters section in Part I, Item 1 of our 2008 Annual Report on Form 10-K for additional details.) Earlier this year the PM2.5 standards were remanded to the EPA by the D.C. Circuit Court. Because this is a remand, the current primary hourly and annual standards will remain in place as the EPA evaluates and potentially revises 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.

On July 15, 2009, the EPA published proposed revisions to the primary Nitrogen Dioxide (NO ₂) NAAQS. Under the proposed revisions the EPA would expect states to submit initial recommendations for nonattainment areas by January 2011 using 2008-2010 data. The EPA would make final attainment and nonattainment designations by January 2012. It is unclear at this time how MGE's power plants would be affected by this proposed revision.

On February 9, 2009, the Justice Department, on behalf of the EPA, asked the Supreme Court to dismiss EPA's request (petition for certiorari) that the Court review the D.C. Circuit Court's vacatur of the Clean Air Mercury Rule (CAMR). This withdrawal paves the way for the EPA to develop Maximum Achievable Control Technology (MACT) standards for electric utilities. It is unclear at this time how quickly 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.

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 as applied to Wisconsin; however, the Court stayed that portion of the challenge concerning Wisconsin's alleged impacts on downwind, eight-hour ozone nonattainment areas. EPA has also stayed that portion of the rule concerning Wisconsin's alleged impacts on downwind eight-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.

Columbia

In April 2009, the Columbia owners filed a Certificate of Authority with the PSCW requesting authorization of 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. The PSCW is permitting MGE to defer pre-certification and pre-construction costs related to compliance with environmental regulations at Columbia. Additionally, MGE is entitled to a carrying cost on the related pre-construction costs at a 100% AFUDC rate. As of September 30, 2009, MGE had incurred $0.6 million (excluding carrying costs) in deferred pre-certification and pre-construction expenditures at Columbia related to this environmental initiative.

As of September 30, 2009, Columbia entered into various contractual commitments with vendors for a small portion of the aforementioned expenditures as well as other Columbia environmental projects. MGE is indirectly a party to these agreements as a result of its joint ownership of Columbia and is also contractually obligated, under the applicable ownership and operating agreements, with respect to any commitments made. MGE has a 22% ownership interest in Columbia. MGE's share of these commitments is estimated to be $0.4 million for the remainder of 2009. These costs are expected to be capitalized and included in the consolidated balance sheets of MGE Energy and MGE.

Citizen groups submitted certain public comments or petitions to the WDNR and U.S. EPA objecting to the 2008 renewal of the Title V air operating permit for Columbia. In September 2008, WPL, the plant operator and permit holder, received a Title V air permit renewal for Columbia from WDNR, which contained certain permit changes and responded to the citizen comments. In December 2008, a citizen group submitted a notice of intent to sue the EPA for failure to respond to its petition encouraging EPA to challenge the Columbia permit. In October 2009, the EPA issued an order which denied parts of the petition, granted other parts and sent the Title V permit back to the WDNR for further review based on the EPA Order. The WDNR has 90 days from receipt of the EPA Order to address the objection indentified by EPA and take action on the permit. MGE is unable to predict what actions the WDNR or EPA may take on the renewal of Columbia's existing operating 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. 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.

Chattel Paper Agreement and Other Guarantees - MGE Energy and MGE.

MGE makes available to qualifying customers a financing program for purchasing and installing energy-related equipment that will provide more efficient use of utility service at the customer's property. MGE is party to a chattel paper purchase agreement with a financial institution under which it can sell or finance an undivided interest with recourse, in up to $10.0 million of the financing program receivables, until August 31, 2010. At September 30, 2009, MGE has outstanding a $3.7 million interest in these receivables. MGE retains the servicing responsibility for these receivables.

MGE accounts for servicing rights under the amortization method. Initial determination of the servicing asset fair value is based on the present value of the estimated future cash flows. The discount rate is based on the PSCW authorized weighted cost of capital.

MGE would be required to perform under its guarantee if a customer defaulted on its loan. The energy-related equipment installed at the customer sites is used to secure the customer loans. The loan balances outstanding at September 30, 2009, approximate the fair value of the energy-related equipment acting as collateral. The length of the MGE guarantee to the financial institution varies from one to ten years depending on the term of the customer loan. Principal payments for the next five years on the loans are $0.2 million for the remainder of 2009, $0.9 million in 2010, $0.6 million in 2011, $0.4 million in 2012, and $0.4 million in 2013.

Other Legal Matters - MGE Energy and MGE.

MGE is involved in various other legal matters that are being defended and handled in the normal course of business. MGE maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. As of September 30, 2009, MGE has a total of $1.5 million accrued in the financial statements for such matters. The ultimate outcome of such matters is uncertain and may have an adverse effect on MGE Energy's and MGE's results of operations, financial position, and cash flows.

Natural Gas Supply Contracts - MGE Energy and MGE.

MGE has natural gas supply commitments which include market-based pricing. Total natural gas supply commitments are estimated to be $19.7 million for the remainder of 2009, $23.9 million for 2010, and $0.7 million for 2011. Management expects to recover these costs in future customer rates.

Wind Development Rights - MGE Energy.

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. A payment of $0.8 million was made related to these agreements in 2009. Future payments related to these agreements are estimated to be $1.2 million in 2010, $0.8 million in 2011, $3.2 million in 2012, $0.4 million in 2013, $0.1 million in 2014, $1.7 million in 2015, and $0.4 million in 2016. 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.

deferred gain or loss is recognized in earnings in the delivery month applicable to the instrument. Gains and losses related to hedges qualifying for regulatory treatment are recoverable in gas rates through the PGA or in electric rates as a component of the fuel rules mechanism.

As of September 30, 2009, the gross notional volume of open derivatives is as follows:

MGE Energy and MGE offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. At September 30, 2009, MGE Energy and MGE had $1.8 million in cash collateral that was netted against the net derivative positions with counterparties.

During 2009, MGE purchased and sold exchange-traded and over-the-counter options, swaps, and future contracts. These arrangements are primarily entered into to help stabilize the price risk associated with gas or power purchases. These transactions are employed by both MGE's gas and electric segments. Additionally, as a result of the firm transmission agreements that MGE holds on transmission paths in the MISO and PJM markets, MGE holds FTRs. An FTR is a financial instrument that entitles the holder to a stream of revenues or charges based on the differences in hourly day-ahead energy prices between two points on the transmission grid. The fair values of these instruments are reflected as a regulatory asset/liability depending on whether they are in a net loss/gain position. Depending on the nature of the instrument, the gain or loss associated with these transactions will be reflected as cost of gas sold, fuel for electric generation, or purchased power expense in the delivery month applicable to the instrument. At September 30, 2009, the cost basis of these financial instruments exceeded their fair value by $2.8 million.

During 2009, MGE has also entered into futures and basis swaps to take advantage of physical and financial arbitrage opportunities between supply basins and pricing spreads between future months' gas supply. Under the incentive mechanism within the PGA clause, MGE shareholders have the ability to receive a set percentage of the benefits or loss from these deals if certain thresholds are achieved. The portion related to the shareholders is reflected in other comprehensive income and the portion related to customers is reflected as a regulatory asset/liability depending on whether they are in a net loss/gain position. At September 30, 2009, the cost basis of these financial instruments exceeded their fair value by less than $0.1 million.

MGE has also entered into a ten-year purchased power agreement which provides MGE with firm capacity and energy during a base term from June 1, 2012, through May 31, 2022. The agreement also allows MGE the option to purchase power during a period of time preceding that base term as well as an option to extend the contract after the base term. The agreement is a derivative contract and is recognized at its fair value on the balance sheet. However, the derivative qualifies for regulatory deferral and is recognized with a corresponding regulatory asset or liability depending on whether the fair value is in a loss or gain position. The fair value of the contract at September 30, 2009, reflects a loss position of $12.6 million. The actual fuel cost will be recognized in purchased power expense in the month of purchase.

The following table summarizes the fair value of the derivative instruments on the balance sheet at September 30, 2009. All derivative instruments in this table are presented on a gross basis and are calculated prior to the netting of instruments with the same counterparty under a master netting agreement as well as the netting of cash collateral. For financial statement purposes, MGE Energy and MGE have netted instruments with the same counterparty under a master netting agreement as well as the netting of cash collateral.

The following table summarizes the unrealized and realized losses related to the derivative instruments on the balance sheet at September 30, 2009, and the income statement for the three and nine months ended September 30, 2009 (a).

MGE's commodity derivative contracts, FTRs, and ten-year PPA are subject to regulatory deferral. These derivatives are marked to fair value and are offset with a corresponding regulatory asset or liability. Realized gains and losses are deferred on the balance sheet and are recognized in earnings in the delivery month applicable to the instrument. As a result of the above described treatment, there are no unrealized gains or losses that flow through earnings.

The ten-year PPA has a provision that may require MGE to post collateral if MGE's debt rating falls below investment grade (i.e., below BBB-) once MGE begins purchasing energy under the contract in 2012. The amount of collateral that it may be required to post varies from $20.0 million to $40.0 million, depending on MGE's nominated capacity amount. Certain counterparties extend MGE a credit limit. If MGE exceeds these limits, the counterparties may require collateral to be posted. At September 30, 2009, certain counterparties are in a net liability of $1.3 million.

On September 26, 2007, MGE entered into a non-exchange traded HDD collar. This agreement extended from January 2008 until March 2008 and had a premium of $0.2 million. Actual heating degree days during the aforementioned period were 3,971 which exceeded the ceiling; therefore, MGE recorded a $1.5 million expense (includes the $0.2 million premium) on the collar in the first quarter of 2008.

Nonperformance of counterparties to the non-exchange traded derivatives could expose MGE to credit loss. However, MGE enters into transactions only with companies that meet or exceed strict credit guidelines, and it monitors these counterparties on an ongoing basis to mitigate nonperformance risk in its portfolio. As of September 30, 2009, no counterparties have defaulted.

Regional Transmission Organizations - MGE Energy and MGE.

On April 1, 2005, the MISO implemented its bid-based energy market. MISO is a FERC approved RTO that is required to provide real-time energy services and a market based mechanism for transmission congestion management. MGE is a participant in this market. On April 1, 2005, MGE began offering substantially all of its generation on the MISO market and purchasing 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, however 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, on May 1, 2004, MGE became 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 50 MW, that is affected by this market.

MGE reports on a net basis transactions on the MISO and PJM markets in which it buys and sells power within the same hour to meet electric energy delivery requirements. This treatment resulted in $16.1 million and $50.1 million reduction to sales for resale and purchased power expense for the three months ended September 30, 2009 and 2008, respectively and a $51.5 million and $134.9 million reduction to sales for resale and purchased power expense for the nine months ended September 30, 2009 and 2008, respectively.

Rate Matters - MGE Energy and MGE.

Rate proceedings.

In April 2009, MGE filed an application with the PSCW requesting a 4.5% increase to electric rates and a 2.3% increase to gas rates for 2010. The proposed increases cover costs for MGE's share of the new Elm Road generating station, transmission reliability enhancements, as well as infrastructure additions to its gas delivery system.

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, while gas rates remain unchanged from 2008. The decrease in retail electric rates is driven by a decrease in fuel and purchased power costs, decrease in Elm Road costs 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. Pursuant to the provisions of this rate order, the fuel rules bandwidth effective January 1, 2009, will be plus or minus 2%. See below for further description of fuel rules.

On December 14, 2007, the PSCW authorized MGE to increase 2008 electric rates by 4.8% or $16.2 million and increase gas distribution rates by 2.8% or $7.8 million. The electric increase covered 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. In addition to funding the statewide energy programs, the natural gas rate increase covered costs for area gas construction projects needed to accommodate customer growth. Authorized return on common stock equity was set at 10.8% based on 57.4% utility common equity.

Fuel rules.

Actual electric fuel costs are subject to reconciliation to the amount approved by the PSCW in MGE's rate order covering the applicable period. Known as "fuel rules," the process can produce a fuel surcharge for MGE or require MGE to make a refund in the form of a credit, to the extent that the actual fuel costs are outside a range higher or lower than the level authorized by the PSCW in that rate order.

Under fuel rules, MGE can apply for a fuel surcharge if its actual electric fuel costs exceed 102% of the electric fuel costs allowed in its latest rate order. Conversely, MGE can be required to provide a fuel credit to its customers if actual electric fuel costs are less than 98% of the electric fuel costs allowed in that order.

In April 2009, MGE filed an application with the PSCW requesting a proposed 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. MGE estimates this credit would reduce electric revenues by $4.6 million for 2009. This credit is based upon newly computed annual average fuel costs for 2009, using actual fuel costs for January, February and March and revised forecasts for April through December 2009. In May 2009, the PSCW approved the interim order authorizing MGE to implement the proposed credit, subject to refund with interest at 10.8% effective May 9, 2009, until the final PSCW order. For the three and nine months ended September 30, 2009, this interim credit resulted in a $1.7 million and $3.7 million reduction to electric revenues, respectively. During the nine months ended September 30, 2009, $2.5 million had been credited to electric customers. At September 30, 2009, a short-term regulatory liability of $1.2 million related to this interim order is included in the consolidated balance sheets of MGE Energy and MGE.

As a result of lower-than-expected fuel and purchased power costs in 2008, a fuel refund was approved by the PSCW. To account for this refund, MGE recorded a $5.5 million reduction to other electric revenues in the twelve months ended December 31, 2008. In March 2009, the PSCW completed their audit of the 2008 electric fuel costs and issued a final order, which applied this refund to customers' accounts in March 2009.

Fair Value of Financial Instruments - MGE Energy and MGE.

At September 30, 2009, and December 31, 2008, the carrying amount of cash, cash equivalents, and outstanding commercial paper approximates fair market value due to the short maturity of those investments and obligations. The estimated fair market value of MGE's long-term debt is based on quoted market prices at September 30, 2009, and December 31, 2008. The estimated fair market value of MGE Energy's and MGE's financial instruments are as follows:

*The restricted cash amounts for September 30, 2009, and December 31, 2008, are shown net of $3.3 million and $10.5 million, respectively, of cash collateral that was netted against net derivatives positions as well as other liabilities with counterparties.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability including assumptions about risk. The standard also establishes a three level fair value hierarchy based upon the observability of the assumptions used and requires the use of observable market data when available. The levels are: