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 2008 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 heading:
"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 20 of our 2008 Form 10-K. The risks and uncertainties described in this Form 10-Q and our 2008 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.

OVERVIEW

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to 143,000 retail customers and wholesale electric service to 16 municipalities. SWL&P provides regulated electric service, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate business. This segment also includes Emerging Technology Investments ($6.2 million at March 31, 2009), a small amount of non-rate base generation, approximately 7,000 acres of land for sale in Minnesota, and earnings on cash and short-term investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of March 31, 2009, unless otherwise indicated. All subsidiaries are wholly owned unless otherwise specifically indicated. References in this report to "we," "us" and "our" are to ALLETE and its subsidiaries, collectively.

Financial Overview

(See Note 2. Business Segments for financial results by segment.)

The following net income discussion summarizes a comparison of the quarter ended March 31, 2009 to the quarter ended March 31, 2008.

Net income for 2009 was $16.9 million, or $0.55 per diluted share compared to $23.6 million, or $0.82 per diluted share for 2008. Earnings per diluted share decreased approximately $0.04 compared to 2008 as a result of additional shares of common stock outstanding in 2009. (See Note 11. Earnings Per Share.) Net income for 2009 was down $6.7 million from 2008.

Regulated Operations contributed income of $17.7 million in 2009 ($20.1 million in 2008). The decrease in earnings is primarily due to rate refunds related to 2008 as a result of an April 3, 2009 MPUC hearing, and higher depreciation and interest expense. The decrease was partially offset by:

· the August 1, 2008 interim rate increase, net of 2009 estimated rate refunds for retail customers in Minnesota; and

· FERC approved wholesale rate increases for our municipal customers on March 1, 2008 and February 1, 2009.

In addition, lower sales to our large power customers were mostly offset by higher sales to Other Power Suppliers.

Investments and Other reflected a net loss of $0.8 million in 2009 ($3.5 million net income in 2008).

The decrease in 2009 is primarily due to the sale of certain available-for-sale securities in the first quarter of 2008, and a net loss at ALLETE Properties of $1.1 million in the quarter ended Mach 31, 2009 ($0.5 million net loss in the quarter ended March 31, 2008), which continues to experience difficult real estate market conditions in Florida.

COMPARISON OF THE QUARTERS ENDED MARCH 31, 2009 AND 2008

(See Note 2 - Business Segments for financial results by segment.)

Regulated Operations

Operating revenue decreased $12.2 million, or 6 percent, from 2008 due to lower fuel and purchased power recoveries, lower retail and municipal kilowatt-hour sales, and estimated prior year retail rate refunds related to our 2008 retail rate case anticipated to be paid to our customers. These decreases were partially offset by higher sales to Other Power Suppliers and higher rates.

Lower fuel and purchased power recoveries along with a decrease in retail and municipal kilowatt-hour sales combined for a total revenue reduction of $25.4 million. Fuel and purchased power recoveries decreased due to a $13.5 million reduction in fuel and purchased power expense. (See Fuel and Purchased Power Expense discussion below.) Total kilowatt-hour sales to retail and municipal customers decreased 17.6 percent from 2008 primarily due to idled production lines and plant closures at some of our taconite customers.

Estimated prior year retail rate refunds based on an April 3, 2009 MPUC hearing total $5.3 million.

The decrease in kilowatt-hour sales to retail and municipal customers has been more than offset by revenue from electric sales to Other Power Suppliers which increased $15.0 million in 2009. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.

Higher rates resulting from the August 1, 2008 interim rate increase for retail customers in Minnesota increased revenue by $4.8 million, net of estimated refunds, and the FERC approved wholesale rate increases for our municipal customers on March 1, 2008 and February 1, 2009 increased revenue by $2.2 million.

COMPARISON OF THE QUARTERS ENDED MARCH 31, 2009 AND 2008 (Continued)
Regulated Operations (Continued)

Kilowatt-hours Sold                                          Quantity    %
Quarter Ended March 31,                          2009  2008  Variance Variance
Millions

Regulated Utility
     Retail and Municipals
          Residential                              375   363       12    3.3 %
          Commercial                               379   382      (3)  (0.8) %
          Industrial                             1,323 1,823    (500) (27.4) %
          Municipals                               265   273      (8)  (2.9) %
               Total Retail and Municipals       2,342 2,841    (499) (17.6) %
     Other Power Suppliers                         916   404      512  126.7 %
Total Regulated Utility Kilowatt-hours Sold      3,258 3,245       13    0.4 %

Revenue from electric sales to taconite customers accounted for 19 percent of consolidated operating revenue during the first three months of 2009 (26 percent in 2008). The decrease in revenue to our taconite customers was offset by revenue from electric sales to Other Power Suppliers which accounted for 17 percent of consolidated operating revenue during the first three months of 2009 (9 percent in 2008). Revenue from electric sales to paper and pulp mills accounted for 8 percent of consolidated operating revenue during the first three months of 2009 (9 percent in 2008). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue during the first three months of 2009 (7 percent in 2008).

Operating expenses decreased $10.6 million, or 7 percent, from 2008.

Fuel and Purchased Power Expense decreased $13.5 million, or 16 percent, from 2008 primarily due to a decrease in purchased power expense reflecting lower market prices for energy.

Operating and Maintenance Expense increased $0.3 million from 2008 reflecting higher labor and benefits and rate case expenses, which were mostly offset by lower natural gas purchases due to a decline in the price and quantity of natural gas.

Depreciation Expense increased $2.6 million, or 23 percent, from 2008 reflecting higher property, plant, and equipment balances placed in service and higher annual depreciation rates for distribution and transmission.

Interest expense increased $1.5 million, or 26 percent, from 2008 primarily due to higher long-term debt balances from increased construction activity and $0.3 million related to estimated rate refunds.

Investments and Other

Operating revenue decreased $1.6 million, or 8 percent, from 2008 primarily due
to a decrease in revenue at ALLETE Properties reflecting continued weak real
estate market conditions in Florida and the loss of rental income related to the
retail shopping center in Winter Haven, Florida which was sold in the second
quarter of 2008.

ALLETE Properties                     2009            2008
Revenue and Sales Activity       Quantity Amount Quantity Amount
Dollars in Millions

Revenue from Land Sales
Acres (a)                              19   $2.2        2   $1.3
Contract Sales Price (b)                     2.2             1.3
Deferred Revenue                           (0.6)               -
Revenue from Land Sales                      1.6             1.3
Other Revenue                                0.2             1.4
 Total ALLETE Properties Revenue            $1.8            $2.7

(a) Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest.

(b) Reflects total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-completion method.

Investments and Other (Continued)

Operating expenses decreased $3.0 million, or 14 percent, from 2008 reflecting a decrease in the cost of real estate sold and decreased selling expenses.

Interest expense increased $1.2 million from 2008 primarily due to higher long term debt balances.

Other income decreased $7.6 million from 2008 primarily due to the absence of a $6.8 million gain realized from the sale of certain available-for-sale securities in the first quarter of 2008.

Income Taxes - Consolidated

For the quarter ended March 31, 2009, the effective tax rate was 39.0 percent (36.6 percent for the quarter ended March 31, 2008). The effective tax rate in both years deviated from the statutory rate (approximately 41 percent) primarily due to deductions for Medicare health subsidies, AFUDC-Equity, depletion, investment tax credits, and wind production tax credits.

CRITICAL ACCOUNTING ESTIMATES

Certain accounting measurements under applicable 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 of our 2008 Form 10-K.

OUTLOOK

ALLETE is committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. Minnesota Power's industrial customers are facing weak conditions in the markets for their products, and have and may continue to reduce the amount of energy they use. We will work to sell this released energy in the wholesale markets, and believe that our ability to produce energy at low cost will be a competitive advantage. Our focus will be to maintain the competitively-priced production of energy, while meeting environmental requirements. Minnesota Power will also focus on maintaining competitive retail rates, as we believe this is important to the success of our customers.

Our strategy going forward is to focus on growth opportunities within our core business as we expect to continue making significant investments to comply with renewable and environmental requirements, maintain our existing low-cost generation fleet, and strengthen and enhance the regional transmission grid. We will also look for additional transmission and renewable energy opportunities which take advantage of our geographical location between sources of renewable energy and growing energy markets. Earnings from our ATC investment are expected to grow as we anticipate making additional investments to fund our pro-rata share of ATC's capital expansion program. We expect to invest $5 to $7 million in ATC throughout 2009.

Regulated Operations. Minnesota Power expects significant rate base growth over the next several years as it continues its program to comply with renewable energy requirements and environmental mandates. In addition, significant investment will be made in our existing low-cost generation fleet to provide for continued future operations. We anticipate our capital investments will be recovered through a combination of current cost recovery riders and anticipated increased base electric rates.

Rate Cases. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, the FERC or the PSCW.

OUTLOOK (Continued)
Regulated Operations (Continued)

Minnesota Power's wholesale customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a wholesale customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts with all of our wholesale customers with the exception of one small customer whose contract is now in the cancellation period. The new contracts transition each customer to formula-based rates, which means rates can be adjusted annually based on changes in costs. The new agreements with the private utilities in Wisconsin are subject to PSCW approval. In February 2009, the FERC approved our municipal contracts, including the formula-based rate provision. A 9.5 percent rate increase for our municipal customers was implemented on February 1, 2009 under the formula-based rate provision. Incremental revenue from this rate increase is expected to be approximately $7 million on an annualized basis.

On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC seeking an average rate increase of 8.5 percent for retail customers. The retail rate filing sought a return on equity of 11.15 percent, and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. On an annualized basis, the requested rate increase would have generated approximately $40 million in additional revenue. Interim rates went into effect on August 1, 2008, and resulted in an increase for retail customers of approximately $36 million, or 7.5 percent, on an annualized basis, subject to refund pending the final rate order.

On April 3, 2009, the MPUC deliberated and voted on our retail rate filing. Based on this hearing, we estimate that the MPUC will order an overall rate increase of approximately 4.5 percent when a formal written order (Order) is issued on or before May 4, 2009. The MPUC approved a 10.74 percent return on common equity and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. The MPUC also approved the stipulation and settlement agreement that affirmed the Company's continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The approved agreement eliminates the possibility that approximately $19 million of fuel and purchased power costs incurred in 2008 would not be recovered via the fuel adjustment clause. Once the Order has been issued, any party may request reconsideration to the MPUC. After reconsideration, any party may appeal to the Minnesota Court of Appeals. We will continue collecting interim rates from our customers until the new rates go into effect, which will be after the reconsideration period has expired and after all compliance filings are completed and accepted. Reconsideration of the order or modifications during compliance could affect the final rate increase estimate.

As of March 31, 2009, we recorded an $8.9 million liability, including interest, for refunds anticipated to be paid to our customers as a result of the MPUC hearing on our retail rate filing. Current year rate refunds totaling $3.3 million have been netted against operating revenue on our consolidated statement of income and prior year rate refunds totaling $5.3 million are stated separately. Interest expense of $0.3 million was also recorded on our consolidated statement of income related to rate refunds. Refunds will commence once final rates are effective.

SWL&P's current retail rates are based on a December 2008, PSCW retail rate order that became effective January 1, 2009, and allows for an 11.1 percent return on common equity. The new rates reflect a 3.5 percent average increase in retail utility rates for SWL&P customers (a 13.4 percent increase in water rates, a 4.7 percent increase in electric rates, and a 0.6 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3 million in additional revenue.

Industrial Customers. Electric power is one of several key inputs in the mining, paper production, and pipeline industries. Approximately 41 percent of our Regulated Utility kilowatt-hour sales were made to our industrial customers in the quarter ended March 31, 2009, which includes the taconite, paper and pulp, and pipeline industries.

OUTLOOK (Continued)
Regulated Operations (Continued)

Strong worldwide steel demand, driven largely by extensive infrastructure development in China, resulted in very robust world iron ore demand and steel pricing for nearly a six year period which lasted through the summer of 2008. Between 2004 and 2008, annual taconite production averaged just over 40 million tons per year from taconite mines in Northeastern Minnesota. Beginning in the fall of 2008, worldwide steel makers began to dramatically cut steel production in response to reduced demand driven largely by the world credit situation. During the fourth quarter of 2008, United States raw steel production was running at less than 50 percent of capacity and at levels not seen since the early 1980s. Currently, domestic raw steel production is at approximately 45 percent of capacity reflecting poor demand in automobiles, durable goods, structural, and other steel products. In late 2008, Minnesota taconite producers began to feel the impacts of decreased steel demand. As a result, reduced taconite production levels are occurring in 2009. Consequently, 2009 demand nominations for power from our taconite customers are expected to be lower by approximately 40 percent from 2008 levels. We continue to remarket available power to Other Power Suppliers in an effort to mitigate the earnings impact of these lower industrial sales. These 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 various durations. To date in 2009, we have successfully mitigated approximately 85 percent of the expected annual earnings impact. These contracts expire at various times during 2009 and 2010, and have pricing levels similar to the rates charged to our large power customers. If our taconite customers continue to nominate reduced demand we will have additional power to sell in 2009. We are unable to predict pricing levels on any such sales at this time.

Renewable Generation Sources. In February 2007, Minnesota enacted a law requiring Minnesota Power to generate or procure 25 percent of its energy from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016, 20 percent by 2020, and 25 percent by 2025. The law allows the MPUC to modify or delay a standard obligation if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developing and making renewable supply additions as part of its generation planning strategy prior to the enactment of this law and this activity continues. Minnesota Power believes it will meet the requirements of this legislation.

The areas in which we operate have strong wind, water and biomass resources, and provide us with opportunities to develop a number of renewable forms of generation. Our electric service area in northeastern Minnesota is situated for delivery of renewable energy that is generated here and in adjoining regions. We intend to secure the most cost competitive and geographically advantageous renewable energy resources available. We believe that the demand for these resources is likely to grow, and the costs of the resources to generate renewable energy will continue to escalate. While we intend to maintain our disciplined approach to developing generation assets, we also believe that by acting sooner rather than later we can deliver lower cost power to our customers and maintain or improve our cost competitiveness among regional utilities. We will continue to work cooperatively with our customers, our regulators and the communities we serve to develop generation options that reflect the needs of our customers as well as the environment. We believe that our location and our proactive leadership in developing renewable generation provide us with a competitive advantage. For more than a century, we have been Minnesota's leading producer of renewable hydroelectric energy.

We are executing our renewable energy and environmental compliance strategy. Taconite Ridge Wind I, a $50 million, 25-MW wind facility located in northeastern Minnesota became operational in 2008. In 2006 and 2007, we entered into two long-term purchase power agreements for a total of 98 MWs of wind energy constructed in North Dakota (Oliver Wind I and II); 366,945 megawatt-hours were purchased under these agreements in 2008.

OUTLOOK (Continued)
Regulated Operations (Continued)

North Dakota Wind Project. In March 2009, we filed a petition with the MPUC for current cost recovery of investments and expenditures related to the Bison I Wind Project (Bison I) and associated transmission upgrades. With MPUC approval, Bison I will become the first portion of several hundred MWs of the North Dakota Wind Project, which upon completion is expected to complete the 2025 renewable energy supply requirements for our retail load. Bison I will be located southwest of Center, North Dakota and comprised of 33 wind turbines with a nameplate capacity of 75 MWs. As part of the North Dakota Wind Project, we announced plans to purchase an existing 250 kV DC transmission line to transport this wind energy to our customers while gradually reducing the supply of energy currently delivered to our system on this same transmission line from Square Butte's coal-fired Milton R. Young Unit 2. In September 2008, we signed an agreement to purchase the transmission line from Square Butte for approximately $80 million. The transaction is subject to regulatory approvals and is anticipated to close in 2009.

Integrated Resource Plan. On October 31, 2007, Minnesota Power filed its Integrated Resource Plan (IRP), a comprehensive estimate of future capacity needs within the Minnesota Power service territory. In October 2008, the MPUC issued an order approving our request to re-file the IRP by October 1, 2009 in order to incorporate the North Dakota Wind Project and otherwise update our load forecasting and modeling in the IRP.

CapX 2020. Minnesota Power is a participant in the CapX 2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX 2020 includes the state's largest transmission owners, including electric cooperatives, municipals and investor-owned utilities, and has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region's transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

The CapX 2020 participants filed a request for a Certificate of Need for three 345 kV lines and associated system interconnections with the MPUC in August 2007. The MPUC determined that it will issue a Certificates of Need for these 345 kV lines in a hearing held April 16, 2009. The MPUC must now determine routes for the new lines in subsequent proceedings. Portions of the 345 kV lines will also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. A fourth line, a 230 kV line in north central Minnesota, is also among the CapX 2020 projects. A request for a Certificate of Need for this line was filed in March 2008, and a Route Permit application was filed in June 2008. The MPUC decision on need and routing are expected in 2010.

Minnesota Power may invest in two of the lines, a 250-mile 345 kV line between Fargo, North Dakota and Monticello, Minnesota, and a 70-mile 230 kV line between Bemidji and Grand Rapids, Minnesota. Our total investment in these two lines is expected to be approximately $80 million. Upon receipt of the required Certificates of Need, we intend to include these costs in an annual filing with the MPUC for current cost recovery of the expenditures related to our investment in the lines under a Minnesota Power transmission cost recovery tariff rider mechanism authorized by Minnesota legislation. Construction of the lines is targeted to begin in 2010 and last approximately three to four years.

Boswell Unit 3 Emission Reduction Plan. We are making emission reduction investments at our Boswell Unit 3 generating unit. The investments in pollution control equipment will reduce particulates, SO2, NOX, and mercury emissions to meet future federal and state requirements. The MPUC has authorized a cash return on construction work in progress during the construction phase in lieu of AFUDC and allows for a return on investment and current cost recovery of incremental operations and maintenance expenses once the new equipment is installed and the unit is placed back in service in late 2009. We began cost recovery on January 1, 2008. In September 2008, we filed a petition with the MPUC to approve the Boswell Unit 3 billing factor adjustment for 2009. Pending approval, customers will continue to be billed under the 2008 billing factor previously approved by the MPUC.

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