~~ALLETE Second Quarter 2009 Form 10-Q~~

NOTE 5. FAIR VALUE

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. ~~We classify fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the~~These inputs, which are used to measure fair ~~value.~~value, are prioritized through the fair value 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). The three levels of the fair value hierarchy ~~defined by SFAS 157~~ are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes primarily mutual fund investments held to fund employee benefits.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. This category includes deferred compensation, fixed income securities, and derivative ~~instruments.~~instruments consisting of cash flow hedges.

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes ARS consisting of guaranteed student loans and derivative instruments consisting of FTRs.

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 ~~June~~September 30, 2009 and December 31, 2008. 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, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

ALLETE Third Quarter 2009 Form 10-Q

NOTE 5. FAIR VALUE (Continued)

	Fair Value as of September 30, 2009
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities	$16.2	–	–	$16.2
Corporate Debt Securities	–	$7.3	–	7.3
Derivatives	–	–	$1.1	1.1
Debt Securities Issued by States of the United States (ARS)	–	–	14.3	14.3
Money Market Funds	4.9	–	–	4.9
Total Fair Value of Assets	$21.1	$7.3	$15.4	$43.8

Liabilities:
Deferred Compensation	–	$14.8	–	$14.8
Total Fair Value of Liabilities	–	$14.8	–	$14.8

Total Net Fair Value of Assets (Liabilities)	$21.1	$(7.5)	$15.4	$29.0

	Fair Value as of June 30, 2009				Fair Value as of December 31, 2008
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities	$13.9	–		$13.9	$13.5	–		$13.5
Corporate Debt Securities	–	$6.7	–	6.7	–	$3.3	–	3.3
Derivatives	0.1	0.4	$1.8	2.3
Debt Securities Issued by States of the United States (ARS)	–	–	14.3		–	–	$15.2	15.2
Money Market Funds	4.2	–		4.2	10.6	–		10.6
Total Fair Value of Assets	$18.2	$7.1	$16.1	$41.4	$24.1	$3.3	$15.2	$42.6

Liabilities:
Deferred Compensation	–	$14.4	–	$14.4	–	$13.5	–	$13.5
Total Fair Value of Liabilities	–	$14.4	–	$14.4	–	$13.5	–	$13.5

Total Net Fair Value of Assets (Liabilities)	$18.2	$(7.3)	$16.1	$27.0	$24.1	$(10.2)	$15.2	$29.1

Recurring Fair Value Measures	Derivatives		Debt Securities Issued by the States of the United States (ARS)
Activity in Level 3	2009	2008	2009	2008
Millions
Balance as of December 31, 2008 and December 31, 2007, respectively	–	–	$15.2	–
Purchases, Sales, Issuances and Settlements, Net	$1.1	–	(0.9)	$(5.9)
Level 3 Transfers In	–	–	–	25.2
Balance as of September 30,	$1.1	–	$14.3	$19.3

The fair value for each of the items below was based on quoted market prices for the same or similar instruments.

Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2008	$598.7	$561.6
September 30, 2009	$640.4	$629.2

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

~~NOTE 5. FAIR VALUE (Continued)~~

Fair Value as of December 31, 2008
Recurring Fair Value Measures
    Level 1
    Level 2
    Level 3
    Total
Millions
Assets:
Equity Securities $13.5 – – $13.5
Corporate Debt Securities – $3.3 – 3.3
Debt Securities Issued by States of the United States (ARS) – – $15.2 15.2
Money Market Funds 10.6 – – 10.6
Total Fair Value of Assets $24.1 $3.3 $15.2 $42.6

Liabilities:
Deferred Compensation – $13.5 – $13.5
Total Fair Value of Liabilities – $13.5 – $13.5
Total Net Fair Value of Assets (Liabilities) $24.1 $(10.2) $15.2 $29.1

Recurring Fair Value Measures Derivatives Auction Rate Securities
Activity in Level 3
    2009
    2008
    2009
    2008
Millions
Balance as of December 31, 2008 and December 31, 2007, respectively – – $15.2 –
Purchases, Sales, Issuances and Settlements, Net $1.8 – (0.9) $(5.9)
Level 3 Transfers In – – – 25.2
Balance as of June 30, $1.8 – $14.3 $19.3

~~The fair value for the items below were based on quoted market prices for the same or similar instruments.~~

Financial Instruments Carrying Amount Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2008 $598.7 $561.6
June 30, 2009 $640.2 $609.4

NOTE 6. REGULATORY MATTERS

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

2008 Rate Case. On May 2, 2008, Minnesota Power filed a retail rate increase request with the MPUC. On May 4, 2009, the MPUC issued its order (May Order) on the rate filing, and on June 25, 2009, the MPUC reconsidered the May Order. The reconsideration order was issued on August 10, 2009, resulting in an authorized rate increase of $20.4 million (slightly below the $21.1 million outcome in the May Order). The May Order allowing a 10.74 percent return on common equity and a capital structure consisting of 54.79 percent equity and 45.21 percent debt remains unchanged.

The reconsideration order reduced Minnesota Power’s interim rates, which were in effect between August 2008 and October 31, 2009, by $6.3 million annually to approximately $15 million. This increased Minnesota Power’s refunding obligation for 2008 and 2009.

As of September 30, 2009, we recorded a $20.0 million liability, including interest, for refunds anticipated to be paid to our customers as a result of the MPUC decision on our retail rate filing. Current year rate refunds totaling $11.9 million have been recorded on our consolidated statement of income and prior year rate refunds totaling $7.6 million are stated separately. Interest expense of $0.5 million was also recorded on our consolidated statement of income related to rate refunds.

On October 29, 2009, the MPUC approved the implementation of final rates to begin on November 1, 2009. Refunding of interim rates will commence in December 2009 and be completed during the first quarter of 2010.

With the May Order, 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 transition to the former base cost of fuel will occur upon implementation of final rates. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

2010 Rate Case. Minnesota Power has previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of 11.5 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue. We cannot predict the final level of rates that may be approved by the MPUC.

On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC. On May 4, 2009, the MPUC issued its order (May Order) on the rate filing, and on June 25, 2009, the MPUC reconsidered the May Order. While the reconsideration order has not been issued, we expect the MPUC reconsideration to result in an authorized rate increase of $20.4 million (slightly below the $21.1 million outcome in its May Order). The May Order allowing a 10.74 percent return on common equity and a capital structure consisting of 54.79 percent equity and 45.21 percent debt remains unchanged.

~~ALLETE Second Quarter 2009 Form 10-Q~~

~~NOTE 6. REGULATORY MATTERS (Continued)~~

The reconsideration decision reduced Minnesota Power’s interim rates, which are in effect between August 2008 and the date final rates are implemented, by $6.3 million annually to approximately $15 million. This increases Minnesota Power’s refunding obligation for 2008 and 2009. Any party may appeal the final order to the Minnesota Court of Appeals. We will continue collecting interim rates until the new rates go into effect, which will be after the appeal period and all compliance filings are completed and accepted. Appeal of the final order or modifications during compliance could affect the final rate increase.

With the May Order, 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 transition to the former base cost of fuel will occur upon implementation of final rates. Any revenue impact associated with the transition will be identified in the fourth quarter.

As of June 30, 2009, we recorded a $16.4 million liability, including interest, for refunds anticipated to be paid to our customers as a result of the MPUC decision on our retail rate filing. Current year rate refunds totaling $8.3 million have been recorded on our consolidated statement of income and prior year rate refunds totaling $7.6 million are stated separately. Interest expense of $0.5 million was also recorded on our consolidated statement of income related to rate refunds. Refunds will commence when 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 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.

ALLETE Third Quarter 2009 Form 10-Q

~~In addition, lower sales to our large power customers were mostly offset by higher sales to Other Power Suppliers.~~ALLETE Third Quarter 2009 Form 10-Q

ALLETE Third Quarter 2009 Form 10-Q

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

ALLETE Third Quarter 2009 ~~increased revenue by $3.8 million.~~Form 10-Q

COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2009 AND 2008 (Continued)

Kilowatt-hours Sold Quantity %
Six Months Ended June 30, 2009 2008 Variance Variance
Millions
Regulated Utility
Retail and Municipals
Residential 617 602 15 2.5 %
Commercial 709 709 – – %
Industrial 2,197 3,612 (1,415) (39.2) %
Municipals 487 499 (12) (2.4) %
Total Retail and Municipals 4,010 5,422 (1,412) (26.1) %
Other Power Suppliers 2,024 779 1,245 159.8 %
Total Regulated Utility Kilowatt-hours Sold 6,034 6,201 (167) (2.7) %
Regulated Operations (Continued)

Current cost recovery rider revenue increased $5.8 million in 2009 from 2008 primarily due to increased capital expenditures related to our Boswell Unit 3 emission reduction plan.

Kilowatt-hours Sold						Quantity	%
Nine Months Ended September 30,				2009	2008	Variance	Variance
Millions
Regulated Utility
	Retail and Municipals
		Residential		857	854	3	0.4 %
		Commercial		1,061	1,090	(29)	(2.7) %
		Industrial		3,182	5,466	(2,284)	(41.8) %
		Municipals		729	742	(13)	(1.8) %
			Total Retail and Municipals	5,829	8,152	(2,323)	(28.5) %
	Other Power Suppliers			3,075	1,244	1,831	147.2 %
Total Regulated Utility Kilowatt-hours Sold				8,904	9,396	(492)	(5.2) %

Revenue from electric sales to taconite customers accounted for 1615 percent of consolidated operating revenue in 2009 ~~(26~~(27 percent in 2008). The decrease in revenue from our taconite customers was partially offset by revenue from electric sales to Other Power Suppliers, which accounted for 2021 percent of consolidated operating revenue in 2009 (9 percent in 2008). Revenue from electric sales to paper and pulp mills accounted for 9 percent of consolidated operating revenue in 2009 (9 percent in 2008). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2009 (7 percent in 2008).

~~ALLETE Second Quarter 2009 Form 10-Q~~

~~COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2009 AND 2008 (Continued)~~

~~Regulated Operations (Continued)~~

Operating expenses decreased ~~$32.8~~$45.0 million, or 1110 percent, from 2008.

Fuel and Purchased Power Expense decreased ~~$31.7~~$42.9 million, or 2018 percent, from 2008 ~~primarily~~ due to decreased power generation attributable to lower kilowatt-hour sales, as well as a ~~decrease~~reduction in ~~purchased power expense reflecting lower market prices for energy.~~wholesale electricity prices. Minnesota Power’s coal generating fleet produced fewer kilowatt-hours of electricity due to planned outages to implement environmental retrofits and to respond to decreased demand from our taconite customers.

Operating and Maintenance Expense decreased ~~$6.3~~$9.9 million from 2008 primarily due to ~~$5.5~~$6.3 million in lower natural gas costs at SWL&P due to a decline in the price and quantity of natural ~~gas.~~gas purchased. In addition, lower maintenance and material costs at Minnesota Power generating facilities were partially offset by defined benefit pension and postretirement health expenses, which have increased primarily due to a decline in asset values.

Depreciation Expense increased ~~$5.2~~$7.8 million, or 22 percent, from 2008 reflecting higher property, plant, and equipment balances placed in ~~service and higher annual depreciation rates for distribution and transmission.~~service.

Interest expenseincreased ~~$2.5~~$3.4 million, or 2219 percent, from 2008 primarily due to additional long-term debt issued to fund new capital investments and $0.5 million related to estimated retail rate refunds.

Investments and Other

Operating revenue decreased ~~$8.3~~$12.2 million, or 18 percent, from 2008 primarily due to a ~~decrease~~$13.0 million reduction in sales revenue at ALLETE Properties. During the first nine months of 2009, ALLETE Properties ~~reflecting~~sold approximately 19 acres of properties located outside of our three main development projects for $2.2 million; no other sales were made in 2009 due to the continued lack of demand for our properties as a result of poor real estate market conditions in Florida. During the first nine months of 2008, ALLETE Properties sold approximately 52 acres of property located outside of our three main development projects for $4.6 million and recognized $2.6 million of previously deferred revenue under percentage of completion accounting. Revenue at ALLETE Properties in 2008 also included a pre-tax gain of $4.5 million resulting from the sale of ~~the~~a retail shopping center in Winter Haven, ~~Florida in the second quarter of 2008.~~Florida.

ALLETE Third Quarter 2009 Form 10-Q

COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2009 AND 2008 (Continued)

Investments and Other (Continued)

ALLETE Properties	2009		2008		2009		2008
Revenue and Sales Activity	Quantity	Amount	Quantity	Amount	Quantity	Amount	Quantity	Amount
Dollars in Millions
Revenue from Land Sales
Acres (a)	19	$2.2	51	$3.9	19	$2.2	52	$4.6
Contract Sales Price (b)		2.2		3.9		2.2		4.6
Revenue Recognized from Previously Deferred Sales						–		2.6
Deferred Revenue		(0.6)		–		(0.6)		–
Revenue from Land Sales		1.6		3.9		1.6		7.2
Other Revenue (c)		0.2		6.7		0.3		7.7
Total ALLETE Properties Revenue		$1.8		$10.6		$1.9		$14.9

(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.

(c)	Included a $4.5 million pre-tax gain from the sale of a shopping center in Winter Haven, Florida in 2008.

BNI Coal, which operates under a cost-plus contract, recorded additional revenue of $2.9 million as a result of higher expenses. (See Operating Expenses.)

Operating expenses decreased ~~$4.1~~$7.0 million, or 911 percent, from 2008 reflecting decreased expenses at ALLETE Properties due to both lower cost of land sold and reductions in general and administrative expenses. Expenses incurred as a result of a planned maintenance outage at a non-regulated generating facility in the third quarter of 2008 also contributed to the decrease in ~~the cost of real estate sold~~2009. Partially offsetting these decreases was an increase in expense at BNI Coal due to higher permitting costs relating to mining expansion, reclamation bonding, and ~~decreased selling expenses.~~dragline repairs in 2009.

Interest expense increased ~~$2.0~~$2.5 million from 2008 primarily due to ~~additional long-term debt issued~~a decrease in the proportion of ALLETE interest expense assigned to ~~fund new~~Minnesota Power. Interest Expense reflected in our Investments and Other segment consists of ALLETE interest expense not provided for in the regulatory orders for Minnesota Power and SWL&P. We record interest expense for Minnesota Power based on Minnesota Power’s most recently authorized capital ~~investments.~~structure. Effective August 1, 2008, the proportion of interest expense assigned to Minnesota Power decreased to reflect the authorized capital structure inherent in interim rates that commenced on that date. Interest expense was also higher in 2009 as 2008 included a $0.6 million reversal of interest expense previously accrued due to the closing of a tax year.

Other income decreased ~~$8.8~~$11.8 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, increased losses in our Emerging Technology Investments in 2009 of $2.0 million, lower earnings on excess cash in 2009 of $1.6 million, and $1.4 million of interest income related to tax benefits recognized in the third quarter of 2008.

Income Taxes – Consolidated

For the ~~six~~nine months ended ~~June~~September 30, 2009, the effective tax rate was ~~36.4~~33.8 percent ~~(36.6~~(32.3 percent for the ~~six~~nine months ended ~~June~~September 30, 2008). The effective tax rate in each period deviated from the statutory rate (approximately 41 ~~percent) primarily~~percent for 2009) due to deductions for Medicare health subsidies, AFUDC-Equity, investment tax credits, wind production tax credits, and depletion. In addition, the effective rate for 2009 was impacted by lower pre-tax income. The effective rate for 2008 was impacted by the recognition of a non-recurring benefit on a previously uncertain tax position for $1.7 million due to the closing of a tax year and the reversal of a state valuation allowance for $2.4 million due to the completion of an IRS review. We expect the effective tax rate for 2009 to be approximately 34 percent.

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

2930

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. Management’s Discussion and Analysis of Financial Condition and Results of Operations 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~~use; we will work to sell ~~any released~~available energy in the wholesale ~~markets, and believe that our ability to produce energy at low cost will be a competitive advantage.~~markets. 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~~competitively priced 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 investment in ATC 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 approximately $8 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, as well as make significant investments 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.

Rate Case. On May 2, 2008, Minnesota Power filed a retail rate increase request with the MPUC. On May 4, 2009, the MPUC issued its order (May Order) on the rate filing, and on June 25, 2009, the MPUC reconsidered the May Order. ~~While the~~The reconsideration order ~~has not been~~was issued ~~we expect the MPUC reconsideration to result~~on August 10, 2009, resulting in an authorized rate increase of $20.4 million (slightly below the $21.1 million outcome in ~~its~~the May Order). The May Order allowing a 10.74 percent return on common equity and a capital structure consisting of 54.79 percent equity and 45.21 percent debt remains unchanged.

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

3031

OUTLOOK (Continued)

Regulated Operations (Continued)

With the May Order, 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 transition to the former base cost of fuel will occur upon implementation of final rates. Any revenue impact associated with ~~the~~this transition will be identified in a future filing related to the ~~fourth quarter.~~Company’s fuel clause operation.

2010 Rate Case. Minnesota Power has previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of ~~June 30,~~11.5 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue. We cannot predict the final level of rates that may be approved by the MPUC.

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 (less than 2 MW) whose contract is now in the cancellation period. The new contracts transitioned each customer to formula-based rates, which means rates can be adjusted annually based on changes in cost. The new agreements with the private utilities in Wisconsin are subject to PSCW approval. In February 2009, ~~we recorded a $16.4 million liability,~~the FERC approved our municipal contracts, including ~~interest,~~the formula-based rate provision. A 9.5 percent rate increase for ~~refunds anticipated~~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 ~~paid to our customers as a result of the MPUC decision~~approximately $7 million on our retail rate filing. Current year rate refunds totaling $8.3 million have been recorded on our consolidated statement of income and prior year rate refunds totaling $7.6 million are stated separately. Interest expense of $0.5 million was also recorded on our consolidated statement of income related to rate refunds. Refunds will commence when final rates are effective.

Ongoing capital investments necessary to meet state-mandated renewable energy and environmental standards, as well as to maintain our low-cost generation fleet and enhance the regional transmission grid will require continual cost recovery filings with the MPUC. These will take the form of current cost recovery filings and general rate cases. Minnesota Power anticipates filing a general rate case late in 2009.an annualized basis.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, paper production, and pipeline industries. Approximately 3635 percent of our Regulated Utility kilowatt-hour sales were made to our industrial customers through the ~~six~~nine months ended ~~June~~September 30, 2009, which includes the taconite, paper and pulp, and pipeline industries.

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~~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~~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. ~~Currently, domestic raw steel production is at approximately 50 percent of capacity reflecting an increasing 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 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. For 2009, we have successfully mitigated approximately 85 percent of the earnings impact.

Minnesota Power expects an increase in taconite production on Minnesota’s Iron Range in 2010, which would result in increased electricity usage by its industrial customers compared to 2009, but less than previous years’ levels.

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

3132

OUTLOOK (Continued)

Regulated Operations (Continued)

Renewable Generation Sources. In February 2007, Minnesota enacted a law requiring ~~Minnesota Power to generate or procure~~ 25 percent of ~~its~~Minnesota Power’s total retail energy sales in Minnesota come 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, and 20 percent by 2020. 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~~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 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~~. Taconite Ridge Wind I, a $50 million, 25-MW wind facility located in northeastern Minnesota became operational in 2008.

North Dakota Wind Project. On July 7, 2009, the MPUC approved our ~~plan~~ petition ~~to qualify for~~seeking current cost recovery of investments and expenditures related to our Bison I ~~Wind Project (Bison I)~~ and associated transmission upgrades. We anticipate filing a petition with the MPUC in the ~~near future~~fourth quarter to establish ~~cost recovery and~~ customer billing ~~rates.~~rates for the approved cost recovery. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will ~~complete~~fulfill the 2025 renewable energy supply requirement for our retail load. Bison I, ~~will be located near Center, North Dakota and~~which will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 ~~MWs.~~ MWs and located near Center, North Dakota, will be phased into service in 2010 and 2011.

On September 29, 2009 the NDPSC issued a Certificate of Site Compatibility for Energy Conversion System for Bison I that authorized site construction to commence. On October 2, 2009, Minnesota Power filed a route permit application with the NDPSC for the 22 mile 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota.

In September 2008, we signed an agreement to purchase an existing 250 kV DC transmission line for approximately $80 million 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 Unit. The transaction is subject to regulatory ~~approvals~~ and ~~is anticipated to close in 2009.~~board approvals. On May 14, 2009, we filed a petition with the MPUC for approval of the DC transmission line purchase and the restructuring of the power purchase agreement with Square Butte. That petition was reviewed by the MPUC through an evidentiary hearing held on September 17, 2009. The Administrative Law Judge (ALJ) takes the information from the evidentiary hearing and makes a recommendation to the MPUC. The MPUC may accept, reject, or modify the ALJ’s recommendation in making their decision. On October 27, 2009, the ALJ recommended that the MPUC approve this transaction.

Hibbard Energy Center. On September 30, 2009, we purchased boilers and associated systems previously owned by the City of Duluth. This facility was initially built in the late 1940s as a coal burning power plant, and retrofitted to burn wood-based biomass fuel as well as coal. Minnesota Power intends to invest approximately $20 million over the next several years to upgrade the boilers and associated systems to increase biomass energy generation to approximately 200 MWh annually at the plant by approximately 2013. Hibbard’s current generating capacity is approximately 60 MWh annually. This purchase will help us achieve Minnesota’s mandate of providing 25 percent of our retail energy from renewable resources by 2025.

ALLETE Third Quarter 2009 Form 10-Q

OUTLOOK (Continued)

Regulated Operations (Continued)

Integrated Resource Plan. On October ~~31, 2007,~~5, 2009, Minnesota Power filed with the MPUC its 2010 Integrated Resource Plan (IRP), a comprehensive estimate of future capacity needs within Minnesota Power’s service territory. Minnesota Power does not anticipate the need for new base load generation within the Minnesota Power service ~~territory. In October 2008,~~territory over the ~~MPUC issued an order approving~~next 15 years, and plans to meet estimated future customer demand while achieving:

·	Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios;

·	Reductions in the emission of GHGs (primarily carbon dioxide); and

·	Compliance with mandated renewable energy standards.

To achieve these objectives over the coming years, we plan on reshaping our ~~request~~generation portfolio by adding 300 to ~~re-file the IRP by October 1, 2009 in order~~500 megawatts of renewable energy to our generation mix, and exploring options to incorporate ~~the~~peaking or intermediate resources. Our 76 MW Bison I wind project in North Dakota, ~~Wind Project~~expected to be in-service in 2010-2011, is part of this initiative, as is the 25 MW Taconite Ridge wind energy center in northern Minnesota that was placed in service in 2008.

We do not plan to add new coal generation or enter into long-term power purchase agreements from coal-based generation resources without a GHG solution. We project average annual long-term growth of approximately one percent in electric usage over the next 15 years. We will also focus on conservation and ~~otherwise update our load forecasting and modeling~~demand side management to meet the energy savings goals established in ~~the IRP.~~Minnesota legislation.

Climate ~~Change~~Change. . We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals at the Federal level to “cap” the amount of GHG emissions have been made. On June 26, 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. H.R. 2454 is a comprehensive energy bill that also includes a cap and trade program. H.R. 2454 allocates a significant number of allowances to the electric utility sector to mitigate cost impacts on consumers.

On September 30, 2009, the Senate introduced S. 1733, the Senate version of H.R. 2454. This legislation proposes a more stringent near-term greenhouse emissions reduction target in 2020 of 20 percent below 2005 levels, as compared to the 17 percent reduction proposed by H.R. 2454.

Congress may consider proposals other than cap and trade programs to address GHG emissions. We are unable to predict the outcome of H.R. 2454, S. 1733, or other efforts that Congress may make with respect to GHG emissions, and the impact that any GHG emission regulations may have on the Company.

EPA Greenhouse Gas Reporting Rule. On September 22, 2009, the EPA issued the final rule mandating that certain GHG emission sources, including electric generating units, are subject to the EPA’s Acid Rain Program and are required to report emission levels. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule also includes a record retention mandate requiring that written GHG monitoring plans with assignments of responsibility and quality assurance and quality control procedures be in place. The rule is effective January 1, 2010, and all GHG emissions must be reported on an annual basis by March 31 of the following year. Currently, we have the equipment necessary to track our 2010 emissions to comply with this rule.

Title V Greenhouse Gas Tailoring Rule. On October 27, 2009, the EPA issued the proposed Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring rule. This proposed regulation addresses the six primary greenhouse gases and new thresholds for when permits will be required for new facilities and existing facilities which undergo major modifications. The rule would require large industrial facilities, including power plants, emitting greater than 25,000 tons of GHGs annually, to obtain construction and operating permits that demonstrate best practices and technologies are being used at the facility to minimize GHG emissions. Best available control technologies (BACT) for criteria pollutants are already prescribed by the PSD permit program.

For our existing facilities, the proposed rule does not require amending our existing Title V operating permits to include BACT for GHGs. However, modifying or installing units with GHG emissions that trigger the PSD permitting requirements would require amending operating permits to incorporate BACT and energy efficiency measures to minimize GHG emissions.

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

3234

OUTLOOK (Continued)

Regulated Operations (Continued)

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, which includes Minnesota’s largest transmission owners, consists of 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 issued the Certificate of Need for these 345 kV lines in May 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 70-mile, 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 issued the Certificate of Need for the 230 kV line on July 9, 2009. The MPUC decision on ~~routing~~the Route Permit application is expected in 2010.

Minnesota Power ~~may~~intends to 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~~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~~Our November 2, 2009, rate request proposes to ~~approve the Boswell Unit 3 billing factor adjustment for 2009. Pending approval, customers will continue~~move this project from current cost recovery to ~~be billed under the 2008 billing factor previously approved by the MPUC.~~base rates.

Boswell NOX Reduction Plan. In September 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for NOX emission reductions from Boswell Units 1, 2, and 4. ~~If approved by the MPUC, the~~The Boswell NOX Reduction Plan is expected to significantly reduce NOX emissions from these units. In conjunction with the NOX reduction, we plan to ~~install~~make an efficiency improvement to the existing turbine/generator at Boswell Unit 4, adding approximately 60 MWs of total ~~output with no additional emissions. Cost~~output. Our November 2, 2009, rate request seeks recovery for ~~these projects will occur either through a current cost recovery rider or a rate case.~~this project in base rates.

Transmission. In September 2008, in connection with our existing cost recovery rider for transmission expenditures, we filed a petition with the MPUC to approve our 2009 billing factor adjustment for ongoing transmission expenditures. The annual billing factor allows us to charge our retail customers on a current basis for the costs of constructing these facilities plus a return on the capital invested. These expenditures include the Badoura and Tower transmission projects and certain statutorily authorized MISO related transmission facility charges. The Badoura and Tower transmission projects are being developed to address transmission inadequacies in ~~Northeastern~~northeastern Minnesota. Both projects will provide regional transmission benefits through increased voltage support and additional line capacity. The MPUC approved the 2009 billing factor adjustment in June 2009 allowing new rates to go into effect July 1, 2009. Our November 2, 2009, rate request proposes to move completed transmission projects from current cost recovery to base rates.

Power Sales Agreement. On October 29, 2009, Minnesota Power entered into an agreement to sell Basin Electric Power Cooperative 100 MW of capacity and energy for the next ten years. The transaction is scheduled to begin in May 2010, which coincides with the expiration of two power sales contracts on April 30, 2010. (See Item 3. Power Marketing.)

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

3335

OUTLOOK (Continued)

Regulated Operations (Continued)

Investment in ATC. At ~~June~~September 30, 2009, our equity investment was ~~$82.1~~$85.1 million, representing an approximate 8 percent ownership interest. ATC provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of establishing the independent operation and ownership of, and investment in, transmission facilities. ATC rates, effective until 2012, are based on a 12.2 percent return on common equity dedicated to utility plant. ATC has identified ~~$2.7~~$2.5 billion in future projects needed over the next 10 years to improve the adequacy and reliability of the electric transmission ~~system.~~system in its service territory. These investments are expected to be funded through a combination of internal cash, debt and investor contributions. As additional opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro-rata ownership interest in ATC; these future capital investments are voluntary and not a long-term binding commitment. ~~As of July 31,~~On October 30, 2009, we ~~have~~ invested ~~$5.4 million of the approximately $8~~an additional $2.3 million for a total investment of $7.7 million in 2009.

Investments and Other

BNI Coal. BNI Coal anticipates selling approximately 4.5 million tons of coal in 2009 (4.5 million tons were sold in 2008) and has sold approximately ~~2.2~~3.3 million tons through ~~June~~September 30, 2009 ~~(2.2~~(3.4 million tons sold as of ~~June~~September 30, 2008).

ALLETE Properties. ALLETE Properties is our real estate business that has operated in Florida since 1991. Our current strategy is to complete and maintain key entitlements and infrastructure improvements which enhance values without requiring significant additional investment, and position the current property portfolio for a maximization of value and cash flow. Due to continued weak real estate market conditions, we anticipate a net loss of approximately $5 million for 2009.

Our two major development projects include Town Center and Palm Coast Park. A third proposed development project, Ormond Crossings, is in the permitting and planning stage. Development activities involve mainly zoning, permitting, platting, and master infrastructure construction. Development costs are financed through a combination of community development district bonds, bank loans, and internally-generated funds.

Summary of Development Projects			Residential	Non-residential
Land Available-for-Sale	Ownership	Acres (a)	Units (b)	Sq. Ft. (b, c)

Current Development Projects
Town Center	80%	991	2,289	2,228,200
Palm Coast Park	100%	3,436	3,239	3,116,800
Total Current Development Projects		4,427	5,528	5,345,000

Proposed Development Project
Ormond Crossings	100%	5,968	(d)	(d)

Total of Development Projects		10,395	5,528	5,345,000

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

(b)	Estimated and includes non-controlling interest. Density at build out may differ from these estimates.

(c)	Depending on the project, non-residential includes retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional.

(d)

A development order approved by the City of Ormond Beach includes up to 3,700 residential units and 5 million square feet of non-residential space. We estimate the first two phases of Ormond Crossings will include 2,500-3,200 residential units and 2.5 million - 3.5 million square feet of various types of non-residential space. Density of the residential and non-residential components of the project will be determined based upon market and traffic mitigation cost considerations. Approximately 2,000 acres will be devoted to a regionally significant wetlands mitigation bank.

Other Land Available-for-Sale (a)	Total	Mixed Use	Residential	Non-Residential	Agricultural
Acres (b)
Other Land	1,327	353	114	376	484

(a)	Other land available-for-sale includes land located in Palm Coast, Florida not included in development projects and land held by Lehigh Acquisition Corporation and Cape Coral Holdings, Inc.

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

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

3436

OUTLOOK (Continued)

Investments and Other (Continued)

At ~~June~~September 30, 2009, total pending land sales under contract were ~~$8.4~~$5.6 million ($12.4 million at December 31, 2008) and are scheduled to close at various times through 2010. However, given current market conditions it may be difficult to complete these closings by 2010. We continue to have discussions with our buyers under pending contracts. Our objective is to proactively assist our buyers through this current period of weak market ~~conditions, as we believe the long-term prospects for our properties are favorable.~~conditions. Our discussions sometimes result in adjustments to contract terms, and may include extending closing dates, revised pricing or termination. If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. In many cases, contract purchasers incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they have substantially more at risk than the deposit.

~~At June~~Long-term finance receivables as of September 30, 2009 ~~our finance receivables~~were $13.3 million, which included $7.8 million due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June 2009. The estimated fair value of the collateral relating to these receivables was greater than the $7.8 million amount due at September 30, 2009 and no impairment was ~~recorded.~~recorded on these receivables; however, $0.1 million of impairments was recorded on other receivables.

Although weak real estate market conditions currently exist, we continue to believe the long-term prospects for our properties are favorable. In 2009, we commissioned an independent real estate advisory firm to do a study on the State of Florida, northeast Florida, and our specific major land developments (Town Center, Palm Coast Park, and Ormond Crossings) compared to the major competing developments in the region.

The study projected that northeastern Florida is expected to capture an increased portion of the state’s anticipated population growth, with the most significant growth in St. Johns and Flagler Counties (the location of our major developments). In addition, national demographic trends should have a positive impact on Florida’s long-term outlook. Based on a comparison of our three major developments compared with major competing developments in the region, the study concluded that our properties are well-positioned. Therefore, we believe our properties have long-term value and we have the ability to hold these properties, if needed, until the market improves.

Should current weak market conditions continue for an extended period of time, the impact on our future operations would be the continuation of little to no sales while still incurring operating expenses such as community development district assessments and property taxes. This could result in annual net losses for ALLETE Properties similar to 2009.

Emerging Technology. We have the potential to recognize gains or losses on the sale of investments in our Emerging Technology Investments. We plan to sell investments in our Emerging Technology Investments when publicly traded shares are distributed to us. Some restrictions on sales may apply, including, but not limited to, underwriter lock-up periods that typically extend for 180 days following an initial public offering. We have committed to make up to $0.5 million in additional investments in certain emerging technology holdings. We do not have plans to make any additional investments beyond this commitment.

Income Taxes. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2009. On an ongoing basis, ALLETE has certain tax credits and other tax adjustments that will reduce the statutory rate to the expected effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, wind production tax credits, AFUDC-Equity, domestic manufacturer’s deduction, depletion, Medicare prescription reimbursement, as well as other items. The annual effective rate can also be impacted by such items as changes in income from operations before non-controlling interest and income taxes, state and federal tax law changes that become effective during the year, business combinations and configuration changes, tax planning initiatives and resolution of prior years’ tax matters. We expect our effective tax rate to be approximately 3534 percent for 2009.

ALLETE Third Quarter 2009 Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES

Cash Flow Activities

ALLETE is well-positioned to meet the Company’s immediate cash flow ~~needs, including the payment of future dividends.~~needs. With our cash balance of approximately ~~$72~~$54 million, $160.0 million in lines-of-credit which includes a committed, syndicated, unsecured revolving line of credit of $150.0 million, and a debt-to-capital ratio of 42 percent at ~~June~~September 30, 2009, we project sufficient capital ~~availability through the immediate term. If needed, we have the flexibility to reduce our planned capital expenditure program to meet changing capital market conditions.~~availability.

Operating Activities. Cash from operating activities was ~~$63.7~~$106.3 million for the ~~six~~nine months ended ~~June~~September 30, 2009 ($~~54.7~~101.8 million for the ~~six~~nine months ended ~~June~~September 30, 2008). Cash from operating activities was higher in 2009 primarily due to higher depreciation and deferred tax expense, ~~in 2009 and the exclusion of non-operating asset sales in 2008. These increases were partially~~ offset by lower net income and higher working capital requirements in 2009.

Investing Activities. Cash used for investing activities was ~~$135.0~~$206.5 million for the ~~six~~nine months ended ~~June~~September 30, 2009 ($~~96.6~~180.3 million for the ~~six~~nine months ended ~~June~~September 30, 2008). Cash used for investing activities was lower in 2008 due to the proceeds from the sale of ~~assets (retail~~a retail shopping ~~center)~~center in Winter Haven, Florida and available-for-sale securities.

~~ALLETE Second Quarter 2009 Form 10-Q~~

~~LIQUIDITY AND CAPITAL RESOURCES (Continued)~~

Financing Activities. Cash from financing activities was ~~$41.7~~$52.5 million for the ~~six~~nine months ended ~~June~~September 30, 2009 ($~~117.7~~133.3 million for the ~~six~~nine months ended ~~June~~September 30, 2008). Cash from financing activities was lower in 2009 than 2008 due to less debt issuance which was partially offset by the issuance of ~~1.5~~2.3 million shares of common stock with net proceeds of ~~approximately $27.9 million~~$53.7 million.

Working Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit or the sale of securities or commercial paper. We have ~~0.6~~consolidated bank lines of credit aggregating $160.0 million, the majority of which expire in January 2012. In addition, we have 0.5 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment ~~plan. Additionally, we have 4.2~~plan, and 3.5 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. ~~We have consolidated bank lines of credit aggregating $160.0 million, the majority of which expire in January 2012.~~ The amount and timing of future sales of our securities will depend upon market conditions and our specific needs. ~~We may sell securities to meet capital requirements, to provide for the retirement or early redemption of issues of long-term debt, to reduce short-term debt and for other corporate purposes.~~

Auction Rate Securities. Included in Available-for-Sale Securities, as of ~~June~~September 30, 2009, are $14.3 million ($15.2 million at December 31, 2008) of three auction rate municipal bonds with stated maturity dates ranging between 1514 and 27 years. One of these ARS bonds was called during the third quarter at par value of $7.0 million and payment was received on October 6, 2009. These ARS consist of guaranteed student loans insured or reinsured by the federal government. These ARS were historically auctioned every 35 days to set new rates and provided a liquidating event in which investors could either buy or sell securities. Beginning in 2008, the auctions have been unable to sustain themselves due to the overall lack of market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified the ARS as long-term investments and have the ability to hold these securities to maturity, until called by the issuer, or until liquidity returns to this market. In the meantime, these securities will pay a default rate which is above market interest rates.

The Company used a discounted cash flow model to determine the estimated fair value of its investment in the ARS as of June 30, 2009. The assumptions used in preparing the discounted cash flow model include the following: estimated interest rates, estimated discount rates (using yields of comparable traded instruments adjusted for illiquidity and other risk factors), amount of cash flows, and expected holding periods of the ARS. These inputs reflect the Company’s judgments about assumptions that market participants would use in pricing ARS including assumptions about risk. Based upon the results of the discounted cash flow model, the fact that these ARS consist of guaranteed student loans insured or reinsured by the federal government and recent market activity, no other-than-temporary impairment loss has been reported.

Securities. In January 2009, we issued $42.0 million in principal amount of unregistered First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019, and carry a coupon rate of 8.17 percent. We have the option to prepay all or a portion of the Bonds at our discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for this type of transaction. We are using the proceeds from the sale of the Bonds to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

In February 2008, we entered into a Distribution Agreement with KCCI, Inc., with respect to the issuance and sale of up to 2.5 million shares of our common stock. In February 2009, we amended and restated the Distribution Agreement with KCCI, Inc., such that it now provides for the issuance and sale of up to 5.0 million shares of our common stock, without par value. The shares may be offered for sale, from time to time, in accordance with the terms of the ~~agreement.~~agreement pursuant to Registration Statement No. 333-147965. For the ~~six~~nine months ended ~~June~~September 30, 2009, ~~0.8~~1.5 million shares of common stock were issued under this agreement resulting in net proceeds of ~~$21.5~~$44.2 million.

In March 2009, we contributed 463,000 shares of ALLETE common stock, with an aggregate value of $12.0 million, to our pension plan. On May 19, 2009, we registered the 463,000 shares of ALLETE common stock with the SEC pursuant to ~~Rule 424(b)(7).~~

Registration Statement No. 333-147965.

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

3638

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Year to date we have issued 0.3 million shares of common stock through Invest Direct, Employee Stock Purchase Plan and Retirement Savings and Stock Ownership Plan resulting in net proceeds of $9.5 million. These shares of common stock were registered under the following Registration Statement Nos. 333-150681, 333-105225, and 333-124455, respectively.

Pension and Other Postretirement Benefit Plans. The funded status of the defined pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations under the plans. The funded status may change over time due to several factors, including contribution levels, assumed discount rates and actual and assumed rates of return on plan assets. During 2008, the unfunded status of ALLETE’s defined pension and postretirement benefit plans increased significantly, to $255 million at December 31, 2008, primarily due to a decline in the value of plan assets.

Management considers various factors when making funding decisions such as regulatory changes, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the pension plans. Estimated pension contributions for years 2010 through 2014 are approximately $25 million per year, and are based on estimates and assumptions that are subject to change. Funding for the other postretirement benefit plans is impacted by utility regulatory requirements. Estimated postretirement contributions for years 2010 through 2014 are approximately $11 million per year, and are based on estimates and assumptions that are subject to change. Based on the estimated contributions for the defined pension and other postretirement benefit plans and the sources of cash as described above, we do not anticipate these obligations to have a material impact on our financial condition or liquidity.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. The most restrictive covenant requires ALLETE to maintain a ratio of its Funded Debt to Total Capital (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00 measured quarterly. As of ~~June~~September 30, 2009 our ratio was approximately 0.40 to 1.00. Failure to meet this covenant ~~could~~would give rise to an event of default, if not ~~corrected~~cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of ~~June~~September 30, 2009, ALLETE was in compliance with its financial covenants.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements are summarized in our 2008 Form 10-K, with additional disclosure discussed in Note 14. Commitments, Guarantees and Contingencies of this Form 10-Q.

Capital Requirements

For the ~~six~~nine months ended ~~June~~September 30, 2009, capital expenditures totaled ~~$122.5~~$186.7 million ($~~144.3~~211.1 million at ~~June~~September 30, 2008). The expenditures were primarily made in the Regulated Operations segment. Internally generated funds and ~~additional~~ long-term debt and equity issuances were the primary sources of funding.

ENVIRONMENTAL MATTERS AND OTHER

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Due to restrictive environmental requirements through legislation and/or rulemaking in the future, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. We are unable to predict the outcome of the matters discussed in Note 14. Commitments, Guarantees and Contingencies of this Form 10-Q.

NEW ACCOUNTING STANDARDS

New accounting standards are discussed in Note 1. Operations and Significant Accounting Policies of this Form 10-Q.

ALLETE Third Quarter 2009 Form 10-Q

~~ALLETE Second Quarter 2009 Form 10-Q~~

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As of ~~June~~September 30, 2009, evaluations were performed, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Controls. While we continue to enhance our internal control over financial reporting, there has been no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

None.

ALLETE Third Quarter 2009 Form 10-Q

PART II. OTHER INFORMATION (Continued)

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~None.~~In January 2009, we issued $42.0 million in principal amount of unregistered First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019, and carry a coupon rate of 8.17 percent. We have the option to prepay all or a portion of the Bonds at our discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for this type of transaction. We are using the proceeds from the sale of the Bonds to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

~~ITEM~~ ~~4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~

~~(a) We held our Annual Meeting of Shareholders on May 12, 2009.~~

~~(b) Included in (c) below.~~

~~(c)~~

The election of directors, the ratification of the appointment of PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm for 2009, and the amendment of Article III and the deletion of Article V of ALLETE’s Amended and Restated Articles of Incorporation were voted on at the 2009 Annual Meeting of Shareholders.

~~ALLETE Second Quarter 2009 Form 10-Q~~

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ~~(Continued)~~

~~The results were as follows:~~

Votes For
Withheld

Directors

Kathleen A. Brekken 26,944,114 359,750
Heidi J. Eddins 26,991,269 312,594
Sidney W. Emery, Jr. 26,953,869 349,994
James J. Hoolihan 26,833,220 470,644
Madeleine W. Ludlow 26,972,791 331,072
George L. Mayer 26,897,929 405,934
Douglas C. Neve 27,018,456 285,407
Jack I. Rajala 20,938,156 6,365,708
Leonard C. Rodman 26,895,550 408,313
Donald J. Shippar 26,803,979 499,884
Bruce W. Stender 26,824,142 479,721

            Votes For
                Votes
                Against
        Abstentions
        Broker
        Nonvotes
Independent Registered
Public Accounting Firm

PricewaterhouseCoopers LLP 27,010,433 558,949 151,120 –

            Votes For
                Votes
                Against
        Abstentions
        Broker
        Nonvotes
ALLETE’s Amended and Restated Articles of Incorporation

Amend Article III 22,092,287 5,374,224 253,990 –
Delete Article V 25,628,952 1,711,893 379,657 –

~~(d) Not applicable.~~None.

ITEM 5. OTHER INFORMATION

Reference is made to our 2008 Form 10-K for background information on the following updates.

Ref. Page 12 – Regulated Operations, Minnesota Public Utilities Commission – First Paragraph

On May 2, 2008, Minnesota Power filed a retail rate increase request with the MPUC. On May 4, 2009, the MPUC issued its order (May Order) on the rate filing, and on June 25, 2009, the MPUC reconsidered the May Order. ~~While the~~The reconsideration order ~~has not been~~was issued ~~we expect the MPUC reconsideration to result~~on August 10, 2009, resulting in an authorized rate increase of $20.4 million (slightly below the $21.1 million outcome in ~~its~~the May Order). The May Order allowing a 10.74 percent return on common equity and a capital structure consisting of 54.79 percent equity and 45.21 percent debt remains unchanged.

The reconsideration ~~decision~~order reduced Minnesota Power’s interim rates, which ~~are~~were in effect between August 2008 and ~~the date final rates are implemented,~~October 31, 2009, by $6.3 million annually to approximately $15 million. This ~~increases~~increased Minnesota Power’s refunding obligation for 2008 and 2009. ~~Any party may appeal~~

On October 29, 2009, the MPUC approved the implementation of final ~~order~~rates to ~~the Minnesota Court~~begin on November 1, 2009. Refunding of ~~Appeals. We will continue collecting~~ interim rates ~~until~~will commence in December 2009 and be completed during the ~~new rates go into effect, which will be after the appeal period and all compliance filings are completed and accepted. Appeal~~first quarter of ~~the final order or modifications during compliance could affect the final rate increase.~~

~~ALLETE Second Quarter 2009 Form 10-Q~~

~~ITEM 5. OTHER INFORMATION (Continued)~~2010.

With the May Order, 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 transition to the former base cost of fuel will occur upon implementation of final rates. Any revenue impact associated with ~~the~~this transition will be identified in a future filing related to the ~~fourth quarter.~~Company’s fuel clause operation.

ALLETE Third Quarter 2009 Form 10-Q

PART II. OTHER INFORMATION (Continued)

ITEM 5. OTHER INFORMATION (Continued)

AsRef. Page 12 – Regulatory Matters – Sixth Paragraph

Integrated Resource Plan. On October 5, 2009, Minnesota Power filed with the MPUC its 2010 Integrated Resource Plan (IRP), a comprehensive estimate of ~~June 30, 2009,~~future capacity needs within Minnesota Power’s service territory. Minnesota Power does not anticipate the need for new base load generation within the Minnesota Power service territory over the next 15 years, and plans to meet estimated future customer demand while achieving:

·	Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios;

·	Reductions in the emission of GHGs (primarily carbon dioxide); and

·	Compliance with mandated renewable energy standards.

To achieve these objectives over the coming years, we ~~recorded a $16.4 million liability, including interest, for refunds anticipated~~plan on reshaping our generation portfolio by adding 300 to 500 megawatts of renewable energy to our generation mix, and exploring options to incorporate peaking or intermediate resources. Our 76 MW Bison I wind project in North Dakota, expected to be ~~paid~~in-service in 2010-2011, is part of this initiative, as is the 25 MW Taconite Ridge wind energy center in northern Minnesota that was placed in service in 2008.

We do not plan to ~~our customers as~~add new coal generation or enter into long-term power purchase agreements from coal-based generation resources without a ~~result~~GHG solution. We project average annual long-term growth of approximately one percent in electric usage over the ~~MPUC decision~~next 15 years. We will also focus on ~~our retail rate filing. Current year rate refunds totaling $8.3 million have been recorded on our consolidated statement of income~~conservation and ~~prior year rate refunds totaling $7.6 million are stated separately. Interest expense of $0.5 million was also recorded on our consolidated statement of income related~~demand side management to ~~rate refunds. Refunds will commence when final rates are effective.~~meet the energy savings goals established in Minnesota legislation.

Ref. Page 18 – Employees – Second Paragraph

Minnesota Power, SWL&P and IBEW Local 31 continue to work under contract extensions of the agreements which expired on January 31, 2009. On April 10, 2009, IBEW Local 31 requested binding arbitration in accordance with the provisions of the contracts. The contracts also provide Minnesota Power and SWL&P with the protections of no strike clauses. ~~Arbitrations are scheduled~~The sole matter in dispute that would add cost to the agreement is wage adjustments; although the parties have not reached an agreement on this issue, the economic gap between the parties would not be considered material. The Company is also seeking changes to existing benefit plans. Arbitration hearings took place October 5, 2009, with final ~~resolutions anticipated~~resolution expected in ~~November~~December 2009. We remain optimistic that we will achieve a fair and equitable result in both agreements.

~~Ref. Page 20 – Executive Officers of the Registrant~~

~~Executive Officer~~	~~Initial Effective Date~~
~~Donald J. Shippar, Age 60~~
~~Chairman and Chief Executive Officer~~	~~May 12, 2009~~
~~Chairman, President and Chief Executive Officer~~	~~January 1, 2006~~
~~President and Chief Executive Officer~~	~~January 21, 2004~~
~~Executive Vice President – ALLETE and President – Minnesota Power~~	~~May 13, 2003~~
~~President and Chief Operating officer – Minnesota Power~~	~~January 1, 2002~~

~~Alan R. Hodnik, Age 50~~
~~President – ALLETE~~	~~May 12, 2009~~
~~Chief Operating Officer – Minnesota Power~~	~~May 8, 2007~~
~~Senior Vice President – Minnesota Power Operations~~	~~September 22, 2006~~
~~Vice President – Minnesota Power Generation~~	~~May 1, 2005~~

~~ALLETE Second Quarter 2009 Form 10-Q~~

ITEM 6. EXHIBITS

Exhibit

Number

331(a)

~~Amendment to the Articles of Incorporation, dated as of May 12, 2009~~

~~10(a)~~

~~ALLETE Amended and Restated Non-Employee Director Compensation Deferral Plan II, effective May 1, 2009.~~

~~10(b)~~

~~Amendment to the ALLETE Director Stock Plan, effective May 1, 2009.~~

~~31(a)~~

Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b)

Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Section 1350 Certification of Periodic Report by the Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

~~ALLETE News Release dated August 5, 2009, announcing 2009 second quarter earnings.~~ (This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.)

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

4243

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		ALLETE, INC.




~~August 5,~~November 3, 2009		/s/ Mark A. Schober
		Mark A. Schober
		Senior Vice President and Chief Financial Officer





~~August 5,~~November 3, 2009		/s/ Steven Q. DeVinck
		Steven Q. DeVinck
		Controller

ALLETE ~~Second~~Third Quarter 2009 Form 10-Q

4344

Minnesota		41-0418150
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

Large Accelerated Filer T	Accelerated Filer £
Non-Accelerated Filer £	Smaller Reporting Company £

			Page

Definitions			3

Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995			5

Part I.	Financial Information

	Item 1.	Financial Statements (Unaudited)

	Consolidated Balance Sheet -
		~~June~~September 30, 2009 and December 31, 2008	6

	Consolidated Statement of Income -
		Quarter and ~~Six~~Nine Months Ended ~~June~~September 30, 2009 and 2008	7

	Consolidated Statement of Cash Flows -
		~~Six~~Nine Months Ended ~~June~~September 30, 2009 and 2008	8

	Notes to Consolidated Financial Statements		9

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37 40

	Item 4.	Controls and Procedures	39 41

Part II.	Other Information

	Item 1.	Legal Proceedings	39 41

	Item 1A.	Risk Factors	39 41

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39 42

	Item 3.	Defaults Upon Senior Securities	39 42

	Item 4.	Submission of Matters to a Vote of Security Holders	39 42

	Item 5.	Other Information	40 42

	Item 6.	Exhibits	42 43

Signatures			43 44

Abbreviation or Acronym	Term
AFUDC	Allowance for Funds Used During Construction – consisting of the cost of both the debt and equity funds used to finance utility plant additions during construction periods
ALLETE	ALLETE, Inc.
ALLETE Properties	ALLETE Properties, LLC and its subsidiaries
~~APB~~	~~Accounting Principles Board~~
~~AREA~~	~~Arrowhead Regional Emission Abatement~~
ARS	Auction Rate Securities
ATC	American Transmission Company LLC
Bison I	Bison I Wind Project
BNI Coal	BNI Coal, Ltd.
BNSF	BNSF Railway Company
Boswell	Boswell Energy Center
Company	ALLETE, Inc. and its subsidiaries
DC	Direct Current
~~EITF~~	~~Emerging Issues Task Force~~
EPA	Environmental Protection Agency
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Form 10-K	ALLETE Annual Report on Form 10-K
Form 10-Q	ALLETE Quarterly Report on Form 10-Q
~~FSP~~	~~FASB Staff Position~~
FTR	Financial Transmission Rights
GAAP	United States Generally Accepted Accounting Principles
GHG	Greenhouse Gases
IBEW Local 31	International Brotherhood of Electrical Workers Local 31
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
kV	Kilovolt(s)
Laskin	Laskin Energy Center
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission
MW / MWh	Megawatt(s) / Megawatt-hour(s)
NDPSC	North Dakota Public Service Commission
Non-residential	Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NOX	Nitrogen Oxide
Note ___	Note ___ to the consolidated financial statements in this Form 10-Q
~~OES~~	~~Minnesota Office of Energy~~
Oliver Wind I	Oliver Wind I Energy Center
Oliver Wind II	Oliver Wind II Energy Center

Definitions (Continued)
Abbreviation or Acronym	Term
Palm Coast Park	Palm Coast Park development project in Florida
Palm Coast Park District	Palm Coast Park Community Development District
PSCW	Public Service Commission of Wisconsin
Rainy River Energy	Rainy River Energy Corporation - Wisconsin
SEC	Securities and Exchange Commission
~~SFAS~~	~~Statement of Financial Accounting Standards No.~~
SO2	Sulfur Dioxide
Square Butte	Square Butte Electric Cooperative
SWL&P	Superior Water, Light and Power Company
Taconite Harbor	Taconite Harbor Energy Center
Town Center	Town Center at Palm Coast development project in Florida
Town Center District	Town Center at Palm Coast Community Development District
WDNR	Wisconsin Department of Natural Resources

·	our ability to successfully implement our strategic objectives;
·	our ability to manage expansion and integrate acquisitions;
·	prevailing governmental policies, regulatory actions, and legislation including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, and various local and county regulators, and city administrators, about allowed rates of return, financings, industry and rate structure, acquisition and disposal of assets and facilities, real estate development, operation and construction of plant facilities, recovery of purchased power, capital investments and other expenses, present or prospective wholesale and retail competition (including but not limited to transmission costs), zoning and permitting of land held for resale and environmental matters;
·	the potential impacts of climate change and future regulation to restrict the emissions of GHG on our Regulated Operations;
·	effects of restructuring initiatives in the electric industry;
·	economic and geographic factors, including political and economic risks;
·	changes in and compliance with laws and regulations;
·	weather conditions;
·	natural disasters and pandemic diseases;
·	war and acts of terrorism;
·	wholesale power market conditions;
·	population growth rates and demographic patterns;
·	effects of competition, including competition for retail and wholesale customers;
·	changes in the real estate market;
·	pricing and transportation of commodities;
·	changes in tax rates or policies or in rates of inflation;
·	project delays or changes in project costs;
·	availability and management of construction materials and skilled construction labor for capital projects;
·	changes in operating expenses, capital and land development expenditures;
·	global and domestic economic conditions affecting us or our customers;
·	our ability to access capital markets and bank financing;
·	changes in interest rates and the performance of the financial markets;
·	our ability to replace a mature workforce and retain qualified, skilled and experienced personnel; and
·	the outcome of legal and administrative proceedings (whether civil or criminal) and settlements that affect the business and profitability of ALLETE.

			June 30,	December 31,			September 30,	December 31,
			2009	2008			2009	2008

Assets	Assets				Assets
Current Assets	Current Assets				Current Assets
	Cash and Cash Equivalents		$72.4	$102.0	Cash and Cash Equivalents		$54.3	$102.0
	Accounts Receivable (Less Allowance of $0.7 at June 30, 2009				Accounts Receivable (Less Allowance of $0.9 at September 30, 2009
		and $0.7 at December 31, 2008)	80.7	76.3		and $0.7 at December 31, 2008)	79.3	76.3
	Inventories		53.6	49.7	Inventories		54.4	49.7
	Prepayments and Other		25.7	24.3	Prepayments and Other		24.5	24.3
		Total Current Assets	232.4	252.3		Total Current Assets	212.5	252.3
Property, Plant and Equipment - Net	Property, Plant and Equipment - Net		1,481.7	1,387.3	Property, Plant and Equipment - Net		1,530.5	1,387.3
Investment in ATC	Investment in ATC		82.1	76.9	Investment in ATC		85.1	76.9
Other Investments	Other Investments		135.6	136.9	Other Investments		138.8	136.9
Other Assets	Other Assets		285.8	281.4	Other Assets		288.2	281.4
Total Assets	Total Assets		$2,217.6	$2,134.8	Total Assets		$2,255.1	$2,134.8

Liabilities and Equity	Liabilities and Equity				Liabilities and Equity
Liabilities	Liabilities				Liabilities
Current Liabilities	Current Liabilities				Current Liabilities
	Accounts Payable		$59.0	$75.7	Accounts Payable		$54.8	$75.7
	Accrued Taxes		15.8	12.9	Accrued Taxes		15.9	12.9
	Accrued Interest		12.0	8.9	Accrued Interest		9.9	8.9
	Long-Term Debt Due Within One Year		13.0	10.4	Long-Term Debt Due Within One Year		12.0	10.4
	Notes Payable		6.0		Notes Payable		5.3	6.0
	Other		40.1	36.8	Other		44.2	36.8
		Total Current Liabilities	145.9	150.7		Total Current Liabilities	142.1	150.7
Long-Term Debt	Long-Term Debt		627.2	588.3	Long-Term Debt		628.4	588.3
Deferred Income Taxes	Deferred Income Taxes		199.3	169.6	Deferred Income Taxes		217.5	169.6
Other Liabilities	Other Liabilities		360.4	389.3	Other Liabilities		352.0	389.3
	Total Liabilities		1,332.8	1,297.9	Total Liabilities		1,340.0	1,297.9

Commitments and Contingencies (Note 14)	Commitments and Contingencies (Note 14)				Commitments and Contingencies (Note 14)

Equity	Equity				Equity
ALLETE’s Equity	ALLETE’s Equity				ALLETE’s Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 34.1 and 32.6
	Shares Outstanding		575.1	534.1	Common Stock Without Par Value, 80.0 Shares Authorized, 34.9 and 32.6
Unearned ESOP Shares			(48.3)	(54.9)
Accumulated Other Comprehensive Loss			(31.6)	(33.0)
Retained Earnings			380.0	380.9
						Shares Outstanding	601.4	534.1
					Unearned ESOP Shares		(46.9)	(54.9)
					Accumulated Other Comprehensive Loss		(30.4)	(33.0)
					Retained Earnings		381.5	380.9
	Total ALLETE’s Equity		875.2	827.1		Total ALLETE’s Equity	905.6	827.1
Non-Controlling Interest in Subsidiaries	Non-Controlling Interest in Subsidiaries		9.6	9.8	Non-Controlling Interest in Subsidiaries		9.5	9.8
	Total Equity		884.8	836.9	Total Equity		915.1	836.9
Total Liabilities and Equity	Total Liabilities and Equity		$2,217.6	$2,134.8	Total Liabilities and Equity		$2,255.1	$2,134.8

			Quarter Ended		Nine Months Ended
			September 30,		September 30,
			2009	2008	2009	2008

Operating Revenue
	Operating Revenue		$178.8	$201.7	$550.7	$604.9
	Prior Year Rate Refunds		–	–	(7.6)	–
		Total Operating Revenue	178.8	201.7	543.1	604.9

Operating Expenses
	Fuel and Purchased Power		69.8	81.0	199.4	242.3
	Operating and Maintenance		67.5	74.0	224.7	241.5
	Depreciation		16.1	13.5	46.8	39.1
		Total Operating Expenses	153.4	168.5	470.9	522.9

Operating Income			25.4	33.2	72.2	82.0

Other Income (Expense)
	Interest Expense		(8.3)	(6.9)	(25.4)	(19.5)
	Equity Earnings in ATC		4.4	4.2	12.9	11.2
	Other		0.8	2.8	3.8	13.9
		Total Other Income (Expense)	(3.1)	0.1	(8.7)	5.6

Income Before Non-Controlling Interest and Income Taxes			22.3	33.3	63.5	87.6
Income Tax Expense			6.5	8.4	21.5	28.3
Net Income			15.8	24.9	42.0	59.3
	Less: Non-Controlling Interest in Subsidiaries		(0.2)	0.2	(0.3)	0.3
Net Income Attributable to ALLETE			$16.0	$24.7	$42.3	$59.0

Average Shares of Common Stock
	Basic		32.8	29.1	31.8	28.9
	Diluted		32.9	29.3	31.9	29.0

Basic and Diluted Earnings Per Share of Common Stock			$0.49	$0.85	$1.33	$2.04

Dividends Per Share of Common Stock			$0.44	$0.43	$1.32	$1.29

			Quarter Ended		Six Months Ended
			June 30,		June 30,
			2009	2008	2009	2008

Operating Revenue
	Operating Revenue		$167.0	$189.8	$371.9	$403.2
	Prior Year Rate Refunds		(2.3)	–	(7.6)	–
		Total Operating Revenue	164.7	189.8	364.3	403.2

Operating Expenses
	Fuel and Purchased Power		56.8	75.0	129.6	161.3
	Operating and Maintenance		76.7	84.4	157.2	167.5
	Depreciation		15.5	12.9	30.7	25.6
		Total Operating Expenses	149.0	172.3	317.5	354.4

Operating Income			15.7	17.5	46.8	48.8

Other Income (Expense)
	Interest Expense		(8.4)	(6.6)	(17.1)	(12.6)
	Equity Earnings in ATC		4.3	3.6	8.5	7.0
	Other		1.9	2.5	3.0	11.1
		Total Other Income (Expense)	(2.2)	(0.5)	(5.6)	5.5

Income Before Non-Controlling Interest and Income Taxes			13.5	17.0	41.2	54.3
Income Tax Expense			4.2	6.2	15.0	19.9
Net Income			9.3	10.8	26.2	34.4
	Less: Non-Controlling Interest in Subsidiaries		(0.1)	0.1	(0.1)	0.1
Net Income Attributable to ALLETE			$9.4	$10.7	$26.3	$34.3

Average Shares of Common Stock
	Basic		31.8	28.8	31.3	28.7
	Diluted		31.8	28.9	31.4	28.8

Basic and Diluted Earnings Per Share of Common Stock			$0.29	$0.37	$0.84	$1.19

Dividends Per Share of Common Stock			$0.44	$0.43	$0.88	$0.86

Other Liabilities
Millions

Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Plans (a)	$211.8	$251.8
Deferred Regulatory Liabilities	46.0	50.0
Asset Retirement Obligation	43.9	39.5
Other	50.3	48.0

Total Other Liabilities	$352.0	$389.3

For the Nine Months Ended September 30,	2009	2008
Millions

Cash Paid During the Period for
Interest – Net of Amounts Capitalized	$23.7	$20.1
Income Taxes	$1.1	$4.9

Noncash Investing and Financing Activities
Change in Accounts Payable for Capital Additions to Property Plant and Equipment	$(16.5)	$(1.1)
ALLETE Common Stock contributed to the Pension Plan	$(12.0)	–

For the Six Months Ended June 30,	2009	2008
Millions

Cash Paid During the Period for
Interest – Net of Amounts Capitalized	$13.6	$11.8
Income Taxes	$0.8	$4.2

Noncash Investing and Financing Activities
Change in Accounts Payable for Capital Additions to Property Plant and Equipment	$(13.2)	$12.0
ALLETE Common Stock contributed to the Pension Plan	$(12.0)	–

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
For the Quarter Ended September 30, 2009
Operating Revenue	$178.8	$160.1	$18.7
Fuel and Purchased Power	69.8	69.8	–
Operating and Maintenance	67.5	50.1	17.4
Depreciation Expense	16.1	15.0	1.1
Operating Income	25.4	25.2	0.2
Interest Expense	(8.3)	(7.0)	(1.3)
Equity Earnings in ATC	4.4	4.4	–
Other Income (Expense)	0.8	1.6	(0.8)
Income (Loss) Before Non-Controlling Interest and Income Taxes	22.3	24.2	(1.9)
Income Tax Expense (Benefit)	6.5	7.6	(1.1)
Net Income (Loss)	15.8	16.6	(0.8)
Less: Non-Controlling Interest in Subsidiaries	(0.2)	–	(0.2)
Net Income (Loss) Attributable to ALLETE	$16.0	$16.6	$(0.6)

ALLETE’s ~~Interest~~Investment in ATC
Millions
Equity Investment Balance as of December 31, 2008	$76.9
Cash Investments	~~3.5~~5.4
Equity in ATC Earnings	~~8.5~~12.9
Distributed ATC Earnings	~~(6.8)~~(10.1)
Equity Investment Balance as of ~~June~~September 30, 2009	$~~82.1~~85.1

	Pension		Postretirement Health and Life		Pension		Postretirement Health and Life
Components of Net Periodic Benefit Expense	2009	2008	2009	2008	2009	2008	2009	2008
Millions

For the Quarter Ended June 30,
For the Quarter Ended September 30,
Service Cost	$1.5	$1.4	$1.1	$1.0	$1.4	$1.5	$1.0
Interest Cost	6.6	6.3	2.5	2.4	6.5	6.3	2.5	2.4
Expected Return on Plan Assets	(8.5)	(8.1)	(2.1)	(1.8)	(8.4)	(8.1)	(2.0)	(1.8)
Amortization of Prior Service Costs	0.2	0.1	–		0.1	0.2	–
Amortization of Net Loss	0.8	0.4	0.6	0.4	0.9	0.4	0.6	0.4
Amortization of Transition Obligation	–	–	0.6		–	–	0.6
Net Periodic Benefit Expense	$0.6	$0.1	$2.7	$2.6	$0.5	$0.3	$2.7	$2.6

Kilowatt-hours Sold						Quantity	%
Quarter Ended June 30,				2009	2008	Variance	Variance
Millions
Regulated Utility
	Retail and Municipals
		Residential		242	239	3	1.3 %
		Commercial		331	327	4	1.2 %
		Industrial		874	1,789	(915)	(51.2) %
		Municipals		222	227	(5)	(2.2) %
			Total Retail and Municipals	1,669	2,582	(913)	(35.4) %
	Other Power Suppliers			1,107	375	732	195.2 %
Total Regulated Utility Kilowatt-hours Sold				2,776	2,957	(181)	(6.1) %

Kilowatt-hours Sold						Quantity	%
Quarter Ended September 30,				2009	2008	Variance	Variance
Millions
Regulated Utility
	Retail and Municipals
		Residential		240	252	(12)	(4.8) %
		Commercial		352	381	(29)	(7.6) %
		Industrial		984	1,854	(870)	(46.9) %
		Municipals		243	243	–	– %
			Total Retail and Municipals	1,819	2,730	(911)	(33.4) %
	Other Power Suppliers			1,051	465	586	126.0 %
Total Regulated Utility Kilowatt-hours Sold				2,870	3,195	(325)	(10.2) %

Kilowatt-hours Sold						Quantity	%
Six Months Ended June 30,				2009	2008	Variance	Variance
Millions
Regulated Utility
	Retail and Municipals
		Residential		617	602	15	2.5 %
		Commercial		709	709	–	– %
		Industrial		2,197	3,612	(1,415)	(39.2) %
		Municipals		487	499	(12)	(2.4) %
			Total Retail and Municipals	4,010	5,422	(1,412)	(26.1) %
	Other Power Suppliers			2,024	779	1,245	159.8 %
Total Regulated Utility Kilowatt-hours Sold				6,034	6,201	(167)	(2.7) %

	Votes For	Withheld
Directors

Kathleen A. Brekken	26,944,114	359,750
Heidi J. Eddins	26,991,269	312,594
Sidney W. Emery, Jr.	26,953,869	349,994
James J. Hoolihan	26,833,220	470,644
Madeleine W. Ludlow	26,972,791	331,072
George L. Mayer	26,897,929	405,934
Douglas C. Neve	27,018,456	285,407
Jack I. Rajala	20,938,156	6,365,708
Leonard C. Rodman	26,895,550	408,313
Donald J. Shippar	26,803,979	499,884
Bruce W. Stender	26,824,142	479,721

	Votes For	Votes Against	Abstentions	Broker Nonvotes
Independent Registered Public Accounting Firm

PricewaterhouseCoopers LLP	27,010,433	558,949	151,120	–