Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

The following abbreviations or acronyms are used in the text. References in this report to “we,” “us” and “our” are to ALLETE, Inc. and its subsidiaries, collectively.

Statements in this report that are not statements of historical facts may be considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. Any statements that express, or involve discussions as to, future expectations, risks, beliefs, plans, objectives, assumptions, events, uncertainties, financial performance, or growth strategies (often, but not always, through the use of words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “projects,̶ 1;” “will likely result,” “will continue,” “could,” “may,” “potential,” “target,” “outlook” or words of similar meaning) are not statements of historical facts and may be forward-looking.

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, we are hereby filing cautionary statements identifying important factors that could cause our actual results to differ materially from those projected, or expectations suggested, in forward-looking statements made by or on behalf of ALLETE in this Quarterly Report on Form 10-Q, in presentations, on our website, in response to questions or otherwise. These statements are qualified in their entirety by reference to, and are accompanied by, the following important factors, in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements:

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X and do not include all of the information and notes required by GAAP for complete financial statements. Similarly, the December 31, 2009,2010, consolidated balance sheet presented in this Form 10-Q was derived from audited financial statements but does not include all disclosures required by GAAP for complete financial statements.GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Operating results for the period ended September 30, 2010,March 31, 2011, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2010.2011. For further information, refer to the consolidated financial statements and notes included in our 20092010 Form 10-K.

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment. This segment also includes a small amount of non-rate base generation, approximately 7,0005,500 acres of land held-for-saleavailable-for-sale in Minnesota and earnings on cash and short-term investments.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarch y.hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Descriptions of the three levels of the fair value hierarchy are includeddiscussed in Note 8. Fair Value to the consolidated financial statements in our 20092010 Form 10-K.

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010,March 31, 2011, and December 31, 2009.2010. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, whichand may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s policy is to recognize transfers in orand transfers out of Levels 1, 2 or 3 as of the actual date of the event or of the change in circumstances that caused the transfer. For the nine monthsquarters ended September 30,March 31, 2011, and March 31, 2010, and 2009, there were no transfers in or out of Levels 1, 2 or 3.

On September 29,November 2, 2010, Minnesota Power received a written order from the MPUC addressed theapproving a retail rate increase request and approvedof approximately $54 million, a 10.38 percent return on common equity and a 54.29 percent equity ratio. We estimate thatratio, subject to reconsideration. In an order dated January 20, 2011, the MPUC will order an overall retail electric rate increase of approximately $54 million when it issues its written orderdenied all reconsideration requests. Compliance filings were submitted in March 2011. Comments on the Company’s proposed rate request, whichimplementation were received from the Minnesota Office of the Attorney General and the Office of Energy Security, and final action by the MPUC is expected by November 2, 2010. Oncein the written order has been issued, any party may request reconsideration by the MPUC. Any party who seeks reconsideration may thereafter appeal to thesecond quarter of 2011. Minnesota Court of Appeals. WePower will continue collectingto collect interim rates from ourits customers until the new rates go into effect, which will be after the reconsideration period has expired, any appeals are addressed, and after all compliance filings are completed and accepted. Reconsideration, or appeal, of the written order, or mod ifications during the compliance period, could affect the final rate increase estimate. A final order, after reconsideration, is expected no later than the first quarter of 2011. Final rates are expectedcurrently estimated to be near the amount collected under interim rates, therefore, wein June or July 2011. We expect little or no interim rate refunds towill be issued.

Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATC provides transmission service under rates regulated by theare FERC thatapproved and are set in accordance with the FERC’s policy of encouraging the independent operation and ownership of, and investment in, transmission facilities.based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of September 30, 2010,March 31, 2011, our equity investment balance in ATC was $92.0$94.8 million ($88.493.3 million as of December 31, 2009)2010). On OctoberIn the first quarter of 2011, we invested $0.8 million in ATC, and on April 29, 2010,2011, we invested an additional $0.4$0.6 million. We expect to invest an additional $0.6 million in ATC for a total investment of $1.6 million2011 in 2010.ATC.

For the nine monthsquarter ended September 30, 2010,March 31, 2011, the effective tax rate was 39.618.1 percent (33.8(46.6 percent for the nine monthsquarter ended September 30, 2009)March 31, 2010). Excluding additionalthe non-recurring tax expenseitems recorded in the first quarters of 2011 and 2010, as a result ofdescribed above, the Patient Protectioneffective tax rates were 31.8 percent and Affordable Care Act, the 201037.2 percent, respectively. The effective tax rate was 35.7 percent. The 2010 effective tax rate,for both years, excluding the additional tax expense recorded as a result of the Patient Protection and Affordable Care Act,their respective non-recurring items, deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC-Equity, investment tax credits, wind productionrenewable tax credits, and depletion. The 2010 effective tax rate was also favorably impacted by $0.8 million for the completion of a state income tax audit.

We expect that the total amount of unrecognized tax benefits as of September 30, 2010,March 31, 2011, will change by an immaterial amount in the next 12 months.

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provides guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide postretirement health benefits that include prescription drug benefits, which qualify us for the federal subsidy under the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The expected reimbursement for Medicare health subsidies reduced our postretirement medical expense by $1.3 million for 2010 ($2.0 million for 2009).Act. For the nine monthsquarter ended September 30, 2010,March 31, 2011, we have not received any$0.2 million in prescription drug reimbursements.

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the contract, subject to the provisions of the Minnkota powerPower sales agreement discussed on page 22.described below. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. We expect debt service, operating and maintenance, and depreciation expenses for Square Butte to increase in 2011 due to environmental compliance obligations. As of September 30, 2010,March 31, 2011, Square Butte had total debt outstanding of $321.3$369.4 million. Annual debt service for Square Butte is expected to be approximately $39 million in each of the five years, 2011 through 2015, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, our subsidiary, under a long-term contract.

No power will be sold under this agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in 2013. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, and allowwhich, in turn, will enable Minnesota Power additional capacity on the recently acquired DC line to transmit new wind generation.generation on the DC transmission line.

OnIn April 30, 2010, Minnesota Power signed a definitive agreement with Manitoba Hydro subject to MPUC approval, to purchase surplus energy beginning in May 2011 through April 2022. This energy-only transaction primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement with Manitoba Hydro, Minnesota Power will be purchasing at least one million MWh of energy over the contract term. On September 1, 2010, we filed a petition withMarch 11, 2011, the MPUC to approveapproved our PPA with Manitoba Hydro.

Bison I, with1 is a nameplate capacity of approximately 76 MWs, istwo phase, 82 MW wind project in North Dakota. All permitting has been received and the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will help fulfill the Minnesota 2025 renewable energy supply requirement for our retail load. In 2009, the NDPSC authorized site construction for Bison I and on March 10, 2010, approvedphase was completed in 2010. Phase one included the construction of a 22-mile, 230 kV transmission line that will connect Bison I toand the DC transmission lineinstallation of sixteen 2.3-MW wind turbines, all of which were in-service at the Square Butte Substationend of 2010. Phase two is expected to be completed in Center, North Dakota.late 2011 and consists of the installation of fifteen 3.0-MW wind turbines. Bison 1 is expected to have a total capital cost of approximately $177 million, of which $132.9 million was spent through March 31, 2011. In 2009, the MPUC approved Minnesota Power’s petition seeking current cost recovery eligibility for investments and expenditures related to Bison I1, and associated transmission upgrades. Onin July 21, 2010, the MPUC approved our petition establishing rates effective August 1, 2010. On March 31, 2011, Minnesota Power petitioned the MPUC to update the rates for additional investments and expenditures related to Bison 1.

Bison I, including2 is a 105 MW wind project in North Dakota which, if approved by the associated transmission upgradesMPUC, is expected to the DC Line, will have a total capital cost of approximately $177 million. As of September 30, 2010, total costs incurred were approximately $101 million. The 22-mile, 230 kV transmission line has beenbe completed and 16 wind turbines have been installed and will be phased into service throughby the end of 2010.2012. Total project cost is estimated to be approximately $160 million. Construction would begin upon the receipt of all regulatory and permitting approvals. Request for approval of the project was filed with the MPUC on March 24, 2011. On April 6, 2011, the request for site permit approval was submitted to the NDPSC. We will file for current cost recovery for Bison 2 from the MPUC once the project and related permitting have been approved.

Minnesota Power initially plans to participateis currently participating in three CapX2020 projects: the Fargo to St. Cloud project, the Monticello to St. Cloud project, which together total a 238-mile, 345 kV line from Fargo to Monticello, and the 70-mile, 230 kV line between Bemidji and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015.2015, of which $15.4 million was spent through March 31, 2011. As future CapX2020 project costsprojects are eligible for current cost recovery, the Company has petitioned the MPUCidentified, Minnesota Power may elect to recover those costs underparticipate on a transmission cost recovery tariff rider.project-by-project basis.

In July 2010, the MPUC granted a route permit for the 28-mile, 345 kV transmission line between Monticello and St. Cloud. Construction of the project is expected to be completecompleted in late 2011. The 210-mile, 345 kV transmission line from St. Cloud to Fargo is expected to be completecompleted by 2015. Construction for the Bemidji to Grand Rapids 230 kV line project commenced in January 2011.

Our businesses are subject to regulation of environmental matters by various federal, state, and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act, and various waste management requirements are under consideration by both Congress and the EPA. Most notably, clean energy technologies and the regulation of GHGs have been a focus of these discussions. Minnesota Power’s fossil fueledfuel facilities will likely be subject to regulation under these climate change policies.proposals. Our intention is to reduce our exposure to possible future carbon and GHG legislationthese requirements by reshaping our generation portfolio over time to reduce our reliance on coal.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to future restrictive environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments.

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information become available. Accruals for environmental liabilities are included in the consolidated balance sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.

The resolution could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding. We are unableSince 2006, Minnesota Power has significantly reduced emissions at Laskin and Boswell, and continues to predict the ultimate financial impact or the resolution of these mattersreduce emissions at this time.Boswell.

The EPA took public comments on the proposed rule through October 1, 2010, and plans to finalize the rule in JuneJuly 2011. Emissions reductions are proposed to take effect in 2012, within one year of projected finalization of the rule.

The EPA has not yet determined whether trading of emission allowances between regulated generating units or states may be implemented. Since 2005,2006, we have made substantial investments in pollution control equipment at our Laskin, Taconite Harbor and Boswell generating units which have significantly reduced emissions. These reductions may satisfy Minnesota Power’s obligations with respect to these requirements. We are unable to predict any additional compliance costs we might incur at this time.

Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007 the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was not filed at that time due to the United States Court of Appeals for the District of Columbia Circuit’s remand of CAIR. Subsequently, the MPCA requested that companies with BART eligible units complete and submit a BART emissions control retrofit study, which was completed for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirementrequirements for that unit. In December 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA. A decision by the EPA is expe cted to make a decisionpending on whether to approve the Minnesota SIP by January 2011.SIP. If approved, Minnesota Power will have five years to bring Taconite Harbor Unit 3 into compliance. It is uncertain what controls will ultimately be required at Taconite Harbor Unit 3 in connection with the regional haze rule.

We are unable to predict the nature or timing of any additional NAAQS regulation or compliance costs we might incur at this time.

The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. These physical risks could include, but are not limited to, increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations.

Legal challenges to the EPA’s regulation of GHG emissions, including the Tailoring Rule, have been filed by others and are awaiting judicial determination .determination. Comments to the permitting guidance were also submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.

The following discussion should be read in conjunction with our consolidated financial statements, notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from the 20092010 Form 10-K and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-Q under the headingheading: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” located on page 5 and “Risk Factors” located in Part I, Item 1A, page 2322 of our 20092010 Form 10-K. The risks and un certaintiesuncertainties described in this Form 10-Q and our 20092010 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the concerns set forth are realized.

Certain accounting measurements under GAAP involve management’s judgment about subjective factors and estimates, the effects of which are inherently uncertain. Accounting measurements that we believe are most critical to our reported results of operations and financial condition include: regulatory accounting, valuation of investments, pension and postretirement health and life actuarial assumptions, and taxation. These policies are reviewed with the Audit Committee of our Board of Directors on a regular basis and summarized in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 20092010 Form 10-K.

We believe that, over the long term, windlong-term, less carbon intensive and more sustainable renewable energy sources will play an increasingly important role in our nation’s energy mix. We intend to pursue the establishment of adevelop additional renewable energy business focused initially on developing wind assets in North Dakota and the upper Midwest. We intend to develop wind resources which will be used to meet the renewable supply requirements of our regulated businesses as well as wind resources thatbusinesses. In addition, we intend to establish a non-regulated renewable business to produce and sell renewable energy to others, subject to securing long-term power purchase agreements prior to construction of facilities. The establishment of a non-regulated renewable business will be marketedsubject to others. Weappropriate MPUC approvals.

For wind development, we will capitalize on our existing presence in North Dakota through BNI Coal, our recently acquired DC transmission line and our Bison I. Through BNI Coal we1 and 2 wind projects. We have a long-term business presence and established landowner relationships in North Dakota. See page 36Renewable Energy below for more discussion on the DC line acquisition and our Bison I. For projects to be marketed to others, we intend to secure long-term power purchase agreements prior to construction of the1 and 2 wind generation facilities. Establishment of the business is subject to appropriate MPUC approvals.projects.

We also plan to make investments in upperUpper Midwest transmission opportunities that strengthen or enhance the regional transmission grid, or take advantage of our geographical location between sources of renewable energy and end users. Minnesota Power is participating with other regional utilities in making regional transmission investments as a member of the CapX2020 initiative. In addition, we plan to make additional investments to fund our pro rata share of ATC’s future capital expansion program. Minnesota Power is also participating with other regional utilities in making regional transmission investments as a member ofBoth the CapX2020 initiative. The CapX2020 initiative isand our investment in ATC are discussed in more detail on page 37.under Transmission below.

We are also exploring investing in other energy-centric businesses that will complement an entrance into theour non-regulated renewable energy business, or leverage demand trends related to transmission, environmental control or energy efficiency.

ALLETE intends to sell its Florida land assets at reasonable prices, over time or in bulk transactions, and reinvest the proceeds in its growth initiatives. ALLETE Properties does not intend to acquire additional real estate.

During 2010, the domestic steel industry rebounded from the low levels of production seen in 2009. According to the American Iron and Steel Institute domestic(AISI), an association of North American steel producers, United States raw steel production for the first nine months of 2010, wasoperated at approximately 7170 percent of capacity compared to 49in 2010. AISI projects that U.S. steel production levels will be at about 75 percent of capacity forin 2011 (for the first nine monthsquarter of 2009. As2011 steel production was 74 percent). There has been a result,general historical correlation between U.S. steel production and Minnesota Power is experiencing an increase in kilowatt-hour sales as a result of increasedtaconite production. Based on these projections, 2011 taconite production forlevels in Minnesota are on track to exceed 2010 compared to 2009 (approximately 18production levels (36 million tons in 2009), although production will still be less than previous levels (40 million tons in 2008)tons). We will continue to market available power to Other Power Suppliers, when necessary, in an effort to mitigate the earnings impact of these lower industrial sales. Sales to Other Power SuppliersSupply sales are dependent upon the availability of generation and are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of var iousvarious durations. We can make no assurances that our power marketing efforts will fully offset the reduced earnings resulting from lower demand nominations from our industrial customers.

We areMinnesota Power has taken several steps to begin executing ourits renewable energy strategy. In 2006 and 2007,strategy through key renewable projects that will ensure we entered intomeet the identified state mandate. We have executed two long-term power purchase agreements with NextEra Energy, Inc. for a total of 98 MWs of wind energy in North Dakota (Oliver Wind I and II). Other steps include Taconite Ridge, Wind I, our $50 million, 25-MW wind facility located in northeastern Minnesota, became operational in 2008.our Bison 1 and 2 wind development projects and our Hibbard biomass upgrade project.

Bison I, with1 is a nameplate capacity of approximately 76 MWs, istwo phase, 82 MW wind project in North Dakota. All permitting has been received and the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will help fulfill the Minnesota 2025 renewable energy supply requirement for our retail load. In 2009, the NDPSC authorized site construction for Bison I and on March 10, 2010, approved thephase was completed in 2010. Phase one included construction of a 22-mile, 230 kV transmission line that will connect Bison I toand the DC transmission lineinstallation of sixteen 2.3-MW wind turbines, all of which were in-service at the Square Butte Substationend of 2010. Phase two is expected to be completed in Center, North Dakota.late 2011 and consists of the installation of fifteen 3.0-MW wind turbines. Bison 1 is expected to have a total capital cost of approximately $177 million, of which $132.9 million was spent through March 31, 2011. In 2009, the MPUC approved Minnesota Power’s petition seeking current cost recovery eligibility for investments and expenditures related to Bison I1, and associated transmission upgrades. Onin July 21, 2010, the MPUC approved our petition establishing rates effective August 1, 2010. On March 31, 2011, Minnesota Power petitioned the MPUC to update the rates for additional investments and expenditures related to Bison 1.

To achieve these objectives over the coming years, we plan to reshape our generation portfolio by adding approximately 300 to 500 megawattsMW of renewable energy to our generation mix, and exploring options to incorporate peaking or intermediate resources. The first phase of the Bison I1 wind project in North Dakota was put into service in 2010 and the second phase is expected to be in service in late 2010 and 2011.2011, increasing our renewable generation by a total of 82 MW. The Bison 2 105 MW wind project, if approved by the MPUC, along with the Hibbard Biomass Upgrade Project, will continue our expansion into renewable energy to meet our Integrated Resource Plan goals.

We project average annual long-term growth, excluding prospective additional load from industrial and municipal customers, of approximately one percent in electric usage through 2025. We will also focus on conservation and demand side management to meet the energy savings goals established in Minnesota legislation. The MPUC approved our Integrated Resource Plan at its April 7, 2011 hearing. Minnesota Power is required to file a baseload diversification study within nine months of receiving the final order. Minnesota Power’s next Integrated Resource Plan must be filed with the MPUC no later than July 1, 2013.

Minnesota Power plans to initially participateis currently participating in three CapX2020 projects: the Fargo to St. Cloud project, the Monticello to St. Cloud project, which together total a 238-mile, 345 kV line from Fargo to Monticello, and the 70-mile, 230 kV line between Bemidji and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015. As CapX2020 project costs are eligible for current cost recovery, the Company has petitioned the MPUC to recover project costs under a transmission cost recovery tariff rider.2015, of which $15.4 million was spent through March 31, 2011.

In July 2010, the MPUC granted a route permit for the 28-mile 345 kV transmission line between Monticello and St. Cloud. Construction of the project is expected to be complete in late 2011. The 210-mile 345 kV transmission line from St. Cloud to Fargo is expected to be complete by 2015.