ALLETE INC - Quarter Report: 2010 March (Form 10-Q)

firstquarter_10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

T	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2010

£	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ______________ to ______________

Commission File Number 1-3548

ALLETE, Inc.

(Exact name of registrant as specified in its charter)

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

30 West Superior Street

Duluth, Minnesota 55802-2093

(Address of principal executive offices)

(Zip Code)

(218) 279-5000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. T Yes £ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). £ Yes £ No

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). £ Yes T No

Common Stock, no par value,

35,451,209 shares outstanding

as of March 31, 2010

INDEX

			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 -
		March 31, 2010 and December 31, 2009	6

	Consolidated Statement of Income -
		Quarter Ended March 31, 2010 and 2009	7

	Consolidated Statement of Cash Flows -
		Three Months Ended March 31, 2010 and 2009	8

	Notes to Consolidated Financial Statements		9

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38

	Item 4.	Controls and Procedures	39

Part II.	Other Information

	Item 1.	Legal Proceedings	39

	Item 1A.	Risk Factors	39

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

	Item 3.	Defaults Upon Senior Securities	39

	Item 4.	Reserved	39

	Item 5.	Other Information	39

	Item 6.	Exhibits	40

Signatures			41

ALLETE First Quarter 2010 Form 10-Q

Definitions

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

Abbreviation or Acronym	Term
AC	Alternating Current
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
ARS	Auction Rate Securities
ATC	American Transmission Company LLC
Basin	Basin Electric Power Cooperative
Bison I	Bison I Wind Project
BNI Coal	BNI Coal, Ltd.
Boswell	Boswell Energy Center
Boswell NOX Reduction Plan	Plan to reduce NOX emissions from Boswell Units 1, 2, and 4
CO2	Carbon Dioxide
Company	ALLETE, Inc. and its subsidiaries
DC	Direct Current
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
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
Manitoba Hydro	Manitoba Hydro-Electric Board
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

ALLETE First Quarter 2010 Form 10-Q

Definitions (Continued)
Abbreviation or Acronym	Term
NOX	Nitrogen Oxide
Note ___	Note ___ to the consolidated financial statements in this Form 10-Q
Oliver Wind I	Oliver Wind I Energy Center
Oliver Wind II	Oliver Wind II Energy Center
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
SO2	Sulfur Dioxide
Square Butte	Square Butte Electric Cooperative
SWL&P	Superior Water, Light and Power Company
Taconite Harbor	Taconite Harbor Energy Center
Taconite Ridge	Taconite Ridge 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

ALLETE First Quarter 2010 Form 10-Q

Safe Harbor Statement

Under the Private Securities Litigation Reform Act of 1995

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

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

·	our ability to successfully implement our strategic objectives;
·	prevailing governmental policies, regulatory actions, and legislation including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, the EPA and other various state, 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;
·	our ability to manage expansion and integrate acquisitions;
·	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.

Additional disclosures regarding factors that could cause our results and performance to differ from results or performance anticipated by this report are discussed in Item 1A under the heading “Risk Factors” beginning on page 23 of our 2009 Form 10-K. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can it assess the impact of each of these factors on the businesses of ALLETE or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by us in this Form 10-Q and in our other reports filed with the SEC that attempt to advise interested parties of the factors that may affect our business.

ALLETE First Quarter 2010 Form 10-Q

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLETE

CONSOLIDATED BALANCE SHEET

Millions – Unaudited

	March 31,	December 31,
	2010	2009

Assets
Current Assets
Cash and Cash Equivalents	$32.5	$25.7
Accounts Receivable (Less Allowance of $0.9 at March 31, 2010 and December 31, 2009)	119.0	118.5
Inventories	51.7	57.0
Prepayments and Other	19.4	24.3
Total Current Assets	222.6	225.5
Property, Plant and Equipment - Net	1,649.1	1,622.7
Regulatory Assets	287.9	293.2
Investment in ATC	90.3	88.4
Other Investments	132.6	130.5
Other Assets	33.5	32.8
Total Assets	$2,416.0	$2,393.1

Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable	$36.4	$62.1
Accrued Taxes	25.0	20.6
Accrued Interest	9.7	11.1
Long-Term Debt Due Within One Year	1.6	5.2
Notes Payable	1.7	1.9
Other	34.2	32.2
Total Current Liabilities	108.6	133.1
Long-Term Debt	710.1	695.8
Deferred Income Taxes	266.5	253.1
Regulatory Liabilities	47.2	47.1
Other Liabilities	326.4	325.0
Total Liabilities	1,458.8	1,454.1

Commitments and Contingencies (Note 14)

Equity
ALLETE’s Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 35.5 and 35.2 Shares Outstanding	621.2	613.4
Unearned ESOP Shares	(42.9)	(45.3)
Accumulated Other Comprehensive Loss	(23.6)	(24.0)
Retained Earnings	393.2	385.4
Total ALLETE Equity	947.9	929.5
Non-Controlling Interest in Subsidiaries	9.3	9.5
Total Equity	957.2	939.0
Total Liabilities and Equity	$2,416.0	$2,393.1

The accompanying notes are an integral part of these statements.

ALLETE First Quarter 2010 Form 10-Q

ALLETE

CONSOLIDATED STATEMENT OF INCOME

Millions Except Per Share Amounts – Unaudited

	Quarter Ended
	March 31,
	2010	2009

Operating Revenue
Operating Revenue	$233.6	$204.9
Prior Year Rate Refunds	–	(5.3)
Total Operating Revenue	233.6	199.6

Operating Expenses
Fuel and Purchased Power	79.8	72.8
Operating and Maintenance	87.7	80.5
Depreciation	20.0	15.2
Total Operating Expenses	187.5	168.5

Operating Income	46.1	31.1

Other Income (Expense)
Interest Expense	(8.9)	(8.7)
Equity Earnings in ATC	4.5	4.2
Other	1.0	1.1
Total Other Income (Expense)	(3.4)	(3.4)

Income Before Non-Controlling Interest and Income Taxes	42.7	27.7
Income Tax Expense	19.9	10.8
Net Income	22.8	16.9
Less: Non-Controlling Interest in Subsidiaries	(0.2)	–
Net Income Attributable to ALLETE	$23.0	$16.9

Average Shares of Common Stock
Basic	33.8	30.9
Diluted	33.8	31.0

Basic Earnings Per Share of Common Stock	$0.68	$0.55
Diluted Earnings Per Share of Common Stock	$0.68	$0.55

Dividends Per Share of Common Stock	$0.44	$0.44

The accompanying notes are an integral part of these statements.

ALLETE First Quarter 2010 Form 10-Q

ALLETE

CONSOLIDATED STATEMENT OF CASH FLOWS

Millions – Unaudited

	Quarter Ended
	March 31,
	2010	2009

Operating Activities
Net Income	$22.8	$16.9
Allowance for Funds Used During Construction	(1.2)	(1.3)
(Income) Loss from Equity Investments, Net of Dividends	(0.4)	0.3
Depreciation Expense	20.0	15.2
Amortization of Debt Issuance Costs	0.2	0.2
Deferred Income Tax Expense	11.8	10.5
Stock Compensation Expense	0.5	0.6
Bad Debt Expense	0.2	0.3
Changes in Operating Assets and Liabilities
Accounts Receivable	(0.6)	(0.3)
Inventories	5.4	(0.1)
Prepayments and Other	4.9	4.5
Accounts Payable	(20.0)	(10.0)
Other Current Liabilities	5.0	6.9
Regulatory and Other Assets	5.1	(1.2)
Regulatory and Other Liabilities	3.0	(8.0)
Cash from Operating Activities	56.7	34.5

Investing Activities
Proceeds from Sale of Available-for-sale Securities	0.6	0.9
Payments for Purchase of Available-for-sale Securities	(1.2)	(0.2)
Investment in ATC	(1.2)	(1.9)
Changes to Other Investments	(1.8)	6.2
Additions to Property, Plant and Equipment	(48.1)	(74.6)
Cash for Investing Activities	(51.7)	(69.6)

Financing Activities
Proceeds from Issuance of Common Stock	7.3	2.8
Proceeds from Issuance of Long-Term Debt	80.0	42.9
Reductions of Long-Term Debt	(69.4)	(0.5)
Debt Issuance Costs	(0.7)	(0.5)
Dividends on Common Stock	(15.2)	(13.6)
Changes in Notes Payable	(0.2)	–
Cash from Financing Activities	1.8	31.1

Change in Cash and Cash Equivalents	6.8	(4.0)
Cash and Cash Equivalents at Beginning of Period	25.7	102.0

Cash and Cash Equivalents at End of Period	$32.5	$98.0

The accompanying notes are an integral part of these statements.

ALLETE First Quarter 2010 Form 10-Q

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.

Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.

	March 31,	December 31,
Inventories	2010	2009
Millions
Fuel	$16.8	$23.0
Materials and Supplies	34.9	34.0
Total Inventories	$51.7	$57.0

	March 31,	December 31,
Prepayments and Other Current Assets	2010	2009
Millions
Deferred Fuel Adjustment Clause	$12.7	$15.5
Other	6.7	8.8
Total Prepayments and Other Current Assets	$19.4	$24.3

	March 31,	December 31,
Other Liabilities	2010	2009
Millions
Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Benefit Plans	$230.1	$231.2
Asset Retirement Obligation	48.0	44.6
Other	48.3	49.2
Total Other Liabilities	$326.4	$325.0

Supplemental Statement of Cash Flows Information.

For the Quarter Ended March 31,	2010	2009
Millions
Cash Paid During the Period for
Interest – Net of Amounts Capitalized	$10.0	$7.3
Income Taxes	$1.0	$0.6

Noncash Investing and Financing Activities
Change in Accounts Payable for Capital Additions to Property Plant and Equipment	$(5.7)	$(13.8)
AFUDC – Equity	$1.2	$1.3
ALLETE Common Stock contributed to the Defined Benefit Pension Plan	–	$(12.0)

ALLETE First Quarter 2010 Form 10-Q

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Standards.

Subsequent Events. In February of 2010, the FASB issued amended guidance that eliminates the requirement to disclose the date through which subsequent events have been evaluated. The amended guidance was adopted and effective during the first quarter of 2010, and did not have an impact on our consolidated financial position, results of operations or cash flows.

Derivative Instruments and Hedging Activities. In March of 2010, the FASB issued new guidance on the accounting for credit derivatives that are embedded in beneficial interests in securitized financial assets. This new guidance eliminates the scope exception for embedded credit derivatives and provides new guidance on the evaluation to be performed. This guidance is effective on June 15, 2010. This new guidance will impact ALLETE if we enter into any instruments with embedded credit derivatives. As of March 31, 2010, we did not have any embedded credit derivatives.

Fair Value. In January of 2010, the FASB issued an amendment to the fair value measurement and disclosure standard improving disclosures about fair value measurements. This amended guidance requires separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The amended guidance also requires that in the Level 3 reconciliation, the information about purchases, sales, issuances, and settlements be disclosed separately on a gross basis rather than as one net number. The guidance for the Level 1 and 2 disclosures was adopted on January 1, 2010, and did not have an impact on our consolidated financial position, results of operations or cash flows. The guidance for the activity in Level 3 disclosures is effective January 1, 2011, and will not have an impact on our consolidated financial position, results of operations or cash flows as the amended guidance provides only disclosure requirements.

Variable Interest Entities. In June of 2009, the FASB issued guidance amending the manner in which entities evaluate whether consolidation is required for variable interest entities (VIEs). A company must first perform a qualitative analysis in determining whether it must consolidate a VIE, and if the qualitative analysis is not determinative, must perform a quantitative analysis. The guidance requires continuous evaluation of VIEs for consolidation, rather than upon the occurrence of triggering events. Additional enhanced disclosures about how an entity’s involvement with a VIE affects its financial statements and exposure to risk are required. This guidance was adopted January 1, 2010. The adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

NOTE 2. BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment. This segment also includes a small amount of non-rate base generation, approximately 7,000 acres of land available-for-sale in Minnesota, and earnings on cash and short-term investments.

ALLETE First Quarter 2010 Form 10-Q

NOTE 2. BUSINESS SEGMENTS (Continued)

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
For the Quarter Ended March 31, 2010
Operating Revenue	$233.6	$216.1	$17.5
Fuel and Purchased Power	79.8	79.8	–
Operating and Maintenance	87.7	69.8	17.9
Depreciation Expense	20.0	19.0	1.0
Operating Income (Loss)	46.1	47.5	(1.4)
Interest Expense	(8.9)	(7.6)	(1.3)
Equity Earnings in ATC	4.5	4.5	–
Other Income (Expense)	1.0	1.2	(0.2)
Income (Loss) Before Non-Controlling Interest and Income Taxes	42.7	45.6	(2.9)
Income Tax Expense (Benefit)	19.9	20.7	(0.8)
Net Income (Loss)	22.8	24.9	(2.1)
Less: Non-Controlling Interest in Subsidiaries	(0.2)	–	(0.2)
Net Income (Loss) Attributable to ALLETE	$23.0	$24.9	$(1.9)

As of March 31, 2010
Total Assets	$2,416.0	$2,196.4	$219.6
Property, Plant and Equipment – Net	$1,649.1	$1,604.0	$45.1
Accumulated Depreciation	$990.3	$942.8	$47.5
Capital Additions	$43.6	$43.4	$0.2

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
For the Quarter Ended March 31, 2009
Operating Revenue	$204.9	$186.4	$18.5
Prior Year Rate Refunds	(5.3)	(5.3)	–
Total Operating Revenue	199.6	181.1	18.5
Fuel and Purchased Power	72.8	72.8	–
Operating and Maintenance	80.5	62.8	17.7
Depreciation Expense	15.2	14.1	1.1
Operating Income (Loss)	31.1	31.4	(0.3)
Interest Expense	(8.7)	(7.3)	(1.4)
Equity Earnings in ATC	4.2	4.2	–
Other Income (Expense)	1.1	1.2	(0.1)
Income (Loss) Before Non-Controlling Interest and Income Taxes	27.7	29.5	(1.8)
Income Tax Expense (Benefit)	10.8	11.8	(1.0)
Net Income (Loss)	16.9	17.7	(0.8)
Less: Non-Controlling Interest in Subsidiaries	–	–	–
Net Income (Loss) Attributable to ALLETE	$16.9	$17.7	$(0.8)

As of March 31, 2009
Total Assets	$2,168.9	$1,872.5	$296.4
Property, Plant and Equipment – Net	$1,435.2	$1,381.9	$53.3
Accumulated Depreciation	$867.1	$817.6	$49.5
Capital Additions	$61.7	$60.8	$0.9

ALLETE First Quarter 2010 Form 10-Q

NOTE 3. INVESTMENTS

Investments. Our long-term investment portfolio includes the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits, ARS, and land held-for-sale in Minnesota.

	March 31,	December 31,
Investments	2010	2009
Millions
ALLETE Properties	$93.3	$93.1
Available-for-sale Securities	30.0	29.5
Other	9.3	7.9
Total Investments	$132.6	$130.5

	March 31,	December 31,
ALLETE Properties	2010	2009
Millions
Land Held-for-sale Beginning Balance	$74.9	$71.2
Additions during period: Capitalized Improvements	0.6	5.6
Deductions during period: Cost of Real Estate Sold	–	(1.9)
Land Held-for-sale Ending Balance	75.5	74.9
Long-Term Finance Receivables	12.5	12.9
Other	5.3	5.3
Total Real Estate Assets	$93.3	$93.1

Land Held-for-sale. Land held-for-sale is recorded at the lower of cost or fair value determined by the evaluation of individual land parcels. Land values are reviewed for impairment and no impairments have been recorded for the quarter ended March 31, 2010 (none in 2009).

Long-Term Finance Receivables. Long-term finance receivables, which are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts of $0.3 million at March 31, 2010 ($0.4 million at December 31, 2009). A majority of the receivables have maturities up to three years. Finance receivables totaling $7.6 million at March 31, 2010, were due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June of 2009. The estimated fair value of the collateral relating to these receivables was greater than the $7.6 million amount due at March 31, 2010, and no impairment was recorded on these receivables. Due to the lack of recent market activity, we estimate fair value based primarily on recent property tax assessed values. This valuation technique constitutes a Level 3 non-recurring fair value measurement.

Auction Rate Securities. Included in Available-for-sale Securities, as of March 31, 2010, is an auction rate municipal bond of $6.7 million ($6.7 million at December 31, 2009) with a stated maturity date of March 1, 2024. Our ARS consist of guaranteed student loans insured or reinsured by the federal government. Our 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. Since 2008, the auctions for our ARS 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 our 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. We anticipate our ARS will be redeemed in the second quarter of 2010, as we received a Notice of Contemplated Refunding on January 29, 2010. The investment remains classified as long-term until officially called by the issuer.

NOTE 4. DERIVATIVES

During 2009 and 2010, we entered into financial derivative instruments to manage price risk for certain power marketing contracts and congestion risk for forward power sales contracts. Outstanding derivative contracts at March 31, 2010, consist of FTRs purchased to manage congestion risk for forward power sales contracts. These FTRs are recorded on our consolidated balance sheet at fair value. As of March 31, 2010, $0.7 million of FTRs are included in other assets on our consolidated balance sheet, and will settle by May 31, 2010.

ALLETE First Quarter 2010 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. These inputs, which are used to measure fair 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). Descriptions of the three levels of the fair value hierarchy are discussed in our 2009 Form 10-K.

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010, and December 31, 2009. 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.

	Fair Value as of March 31, 2010
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities – Mutual Funds	$13.0	–	–	$13.0
Available-for-sale Securities
Corporate Debt Securities	–	$7.2	–	7.2
Debt Securities Issued by States of the United States (ARS)	–	–	$6.7	6.7
Total Available-for-sale Securities	–	7.2	6.7	13.9
Derivatives – Financial Transmission Rights	–	–	0.7	0.7
Money Market Funds	7.6	–	–	7.6
Total Fair Value of Assets	$20.6	$7.2	$7.4	$35.2

Liabilities:
Deferred Compensation	–	$14.3	–	$14.3
Total Fair Value of Liabilities	–	$14.3	–	$14.3

Total Net Fair Value of Assets (Liabilities)	$20.6	$(7.1)	$7.4	$20.9

	Fair Value as of December 31, 2009
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities – Mutual Funds	$17.8	–	–	$17.8
Available-for-sale Securities
Corporate Debt Securities	–	$6.4	–	6.4
Debt Securities Issued by States of the United States (ARS)	–	–	$6.7	6.7
Total Available-for-sale Securities	–	6.4	6.7	13.1
Derivatives - Financial Transmission Rights	–	–	0.7	0.7
Money Market Funds	1.4	–	–	1.4
Total Fair Value of Assets	$19.2	$6.4	$7.4	$33.0

Liabilities:
Deferred Compensation	–	$14.6	–	$14.6
Total Fair Value of Liabilities	–	$14.6	–	$14.6

Total Net Fair Value of Assets (Liabilities)	$19.2	$(8.2)	$7.4	$18.4

ALLETE First Quarter 2010 Form 10-Q

NOTE 5. FAIR VALUE (Continued)

Recurring Fair Value Measures Activity in Level 3	Derivatives		Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2009 and December 31, 2008, respectively	$0.7	–	$6.7	$15.2
Purchases, Sales, Issuances and Settlements, Net	–	–	–	(0.9)
Balance as of March 31, 2010 and March 31, 2009, respectively	$0.7	–	$6.7	$14.3

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

Fair Value of Financial Instruments. With the exception of the items listed below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for 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
March 31, 2010	$711.7	$751.3
December 31, 2009	$701.0	$734.8

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.

2010 Rate Case. On November 2, 2009, Minnesota Power filed a retail rate increase request 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. This retail rate request seeks a return on equity of 11.50 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.

Minnesota law allows the collection of interim rates while the MPUC processes the rate filing. On December 30, 2009, the MPUC issued an Order (the Order) authorizing $48.5 million of Minnesota Power’s November 2, 2009, interim rate increase request of $73.0 million. Interim rates, which were implemented on January 1, 2010, are subject to refund pending the MPUC’s final rate order. As interim rates are substantially below our requested levels, Minnesota Power does not anticipate that it will earn, in 2010, the return on equity that has been authorized by the MPUC.

The MPUC cited exigent circumstances in reducing Minnesota Power’s interim rate request. Because the scope and depth of this reduction in interim rates was unprecedented, and because Minnesota law does not allow Minnesota Power to formally challenge the MPUC’s action until a final decision in the case is rendered, on January 6, 2010, Minnesota Power sent a letter to the MPUC expressing its concerns about the Order and requested that the MPUC reconsider its decision on its own motion. Minnesota Power described its belief that the MPUC’s decision violates the law by prejudging the merits of the rate request prior to an evidentiary hearing and results in the confiscation of utility property. Further, the Company is concerned that the decision will have negative consequences on the environmental policy directions of the State of Minnesota by denying recovery for statutory mandates during the pendency of the rate proceeding. The MPUC has not acted in response to Minnesota Power’s letter.

The rate case process requires public hearings and an evidentiary hearing before an Administrative Law Judge. The public hearings occurred in April of 2010, and the evidentiary hearing is scheduled for May of 2010. A report and recommendation from the Administrative Law Judge is scheduled to be issued in August of 2010, with a final decision on the rate request expected in November of 2010.

ALLETE First Quarter 2010 Form 10-Q

NOTE 6. REGULATORY MATTERS (Continued)

In our April 29, 2010, rebuttal testimony filing, we lowered our initial retail rate increase request from $81 million to approximately $72 million due to adjustments for known and measurable events that have occurred since we originally filed. The largest of these adjustments is related to the increased sales to our industrial customers. We cannot predict the final level of rates that may be approved by the MPUC and we cannot predict whether a legal challenge to the MPUC’s interim rate decision will be forthcoming or successful.

2008 Rate Case – Fuel and Purchase Power. In the final rate case order, the MPUC approved the stipulation and settlement agreement that affirmed Minnesota Power’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the 2008 retail rate filing. The transition to the former base cost of fuel began with the implementation of final rates on November 1, 2009. Any revenue impact associated with this transition will be identified in a future filing related to Minnesota Power’s fuel clause operation.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal 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 customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts that transitioned these customers to formula-based rates which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are set at the beginning of the year based on expected costs and provide for a true-up calculation for actual costs. Wholesale rate increases totaling approximately $6 million and $13 million annually were implemented on February 1, 2009 and January 1, 2010, respectively. In the fourth quarter of 2009, under the true-up provision, approximately $6 million of additional revenues were accrued, which will be billed in 2010. When final actual costs are known, the final rate increase attributable to 2010 may vary from the wholesale rate increase implemented on January 1, 2010.

2009 Wisconsin Rate Increase. 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. SWL&P anticipates filing a retail rate case with the PSCW in 2010.

Deferred Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs as regulatory assets, which are probable of recovery in future utility rates. Regulatory liabilities represent amounts expected to be credited to customers in rates. No regulatory assets or liabilities are currently earning a return.

	March 31,	December 31,
Deferred Regulatory Assets and Liabilities	2010	2009
Millions
Deferred Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	$232.8	$235.8
Boswell Unit 3 Environmental Rider (a)	20.5	20.9
Deferred Fuel (b)	18.1	20.8
Income Taxes	15.6	15.7
Asset Retirement Obligation	6.6	6.3
Deferred MISO Costs	1.9	2.4
Premium on Reacquired Debt	2.0	2.0
Other	3.1	4.8
Total Deferred Regulatory Assets	$300.6	$308.7

Deferred Regulatory Liabilities
Income Taxes	$25.3	$25.9
Plant Removal Obligations	17.7	16.9
Other	4.2	4.3
Total Deferred Regulatory Liabilities	$47.2	$47.1

(a)	MPUC-approved current cost recovery rider related to environmental improvements that were placed in service in November of 2009. The rider provides for a true-up calculation to be filed with the MPUC in the first quarter of 2011 for recovery of the rider balance.

(b)	As of March 31, 2010 and December 31, 2009, $5 million of this balance relates to deferred fuel costs incurred under the former base cost of fuel calculation. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

ALLETE First Quarter 2010 Form 10-Q

NOTE 6. REGULATORY MATTERS (Continued)

Current and Non-Current Deferred	March 31,	December 31,
Regulatory Assets and Liabilities	2010	2009
Millions
Total Current Deferred Regulatory Assets (a)	$12.7	$15.5
Total Non-Current Deferred Regulatory Assets	287.9	293.2
Total Deferred Regulatory Assets	$300.6	$308.7

Total Current Deferred Regulatory Liabilities	–	–
Total Non-Current Deferred Regulatory Liabilities	$47.2	$47.1
Total Deferred Regulatory Liabilities	$47.2	$47.1

(a)	Current deferred regulatory assets are included in prepayments and other on the consolidated balance sheet.

NOTE 7. INVESTMENT IN ATC

Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATC provides transmission service under rates regulated by 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. We account for our investment in ATC under the equity method of accounting. As of March 31, 2010, our equity investment balance in ATC was $90.3 million ($79.7 million at March 31, 2009). In the first quarter of 2010, we invested $1.2 million in ATC. We expect to invest an additional $1 million in 2010.

ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2009	$88.4
Cash Investments	1.2
Equity in ATC Earnings	4.5
Distributed ATC Earnings	(3.8)
Equity Investment Balance as of March 31, 2010	$90.3

ATC's summarized financial data for the quarter ended March 31, 2010 and 2009, is as follows:

	Quarter Ended
ATC Summarized Financial Data	March 31,
Income Statement Data	2010	2009
Millions
Revenue	$138.5	$126.2
Operating Expense	62.8	57.0
Other Expense	20.6	18.3
Net Income	$55.1	$50.9

ALLETE’s Equity in Net Income	$4.5	$4.2

NOTE 8. SHORT-TERM AND LONG-TERM DEBT

Long-Term Debt. In February of 2010, we issued $80.0 million in principal amount of unregistered First Mortgage Bonds (Bonds) in the private placement market in three series as follows:

Issue Date	Maturity	Principal Amount	Coupon
February 17, 2010	April 15, 2021	$15 Million	4.85%
February 17, 2010	April 15, 2025	$30 Million	5.10%
February 17, 2010	April 15, 2040	$35 Million	6.00%

ALLETE First Quarter 2010 Form 10-Q

NOTE 8. SHORT-TERM AND LONG-TERM DEBT (Continued)

We used the proceeds from the sale of the Bonds to pay off an outstanding draw on our syndicated revolving credit facility, to fund utility capital investments and for general corporate purposes. 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 the terms and conditions of our utility mortgage. The Bonds were sold in reliance on an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

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 March 31, 2010, our ratio was approximately 0.41 to 1.00. Failure to meet this covenant would give rise to an event of default if not 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 March 31, 2010, ALLETE was in compliance with its financial covenants.

NOTE 9. OTHER INCOME (EXPENSE)

	Quarter Ended
	March 31,
	2010	2009
Millions
Loss on Emerging Technology Investments	$(0.4)	$(1.2)
AFUDC – Equity	1.2	1.3
Investment and Other Income	0.2	1.0
Total Other Income	$1.0	$1.1

NOTE 10. INCOME TAX EXPENSE

On March 23, 2010, the Patient Protection and Affordable Care Act (H.R. 3590), which was subsequently amended on March 30, 2010, was signed into law by the President. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of the provisions changes the tax treatment for retiree prescription drug expenses by eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, beginning January 1, 2013. Based on this provision, we are subject to additional taxes in the future and are required to reverse previously recorded tax benefits in the period of enactment. Consequently, the elimination of the previously recorded tax benefit resulted in a non-recurring charge to net income of $4.0 million in the first quarter of 2010. We plan to address the impacts of this legislation with our regulators in the near future, but at this time are unable to predict the outcome of this issue.

	Quarter Ended
	March 31,
	2010	2009
Millions
Current Tax Expense (Benefit)
Federal (a)	$7.2	$(0.7)
State	0.9	1.0
Total Current Tax Expense	8.1	0.3
Deferred Tax Expense
Federal (b)	9.8	9.3
State	2.2	1.5
Deferred Tax Credits	(0.2)	(0.3)
Total Deferred Tax Expense	11.8	10.5
Total Income Tax Expense	$19.9	$10.8

(a)	Due to the bonus depreciation provisions in the American Recovery and Reinvestment Act of 2009, we were in a net operating loss position for the year ended December 31, 2009. The loss will be utilized by carrying it back against prior years’ taxable income.

(b)	Included in 2010 is a one-time charge of $4.0 million as a result of the Patient Protection and Affordable Care Act eliminating the tax deduction for expenses that are reimbursed under Medicare Part D beginning January 1, 2013.

ALLETE First Quarter 2010 Form 10-Q

NOTE 10. INCOME TAX EXPENSE (Continued)

Uncertain Tax Positions. As of March 31, 2010, we have gross unrecognized tax benefits of $10.9 million. Of this total, $1.5 million represents the amount of unrecognized tax benefits that, if recognized, would favorably impact the effective income tax rate.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits as of March 31, 2010, could be reduced by $3.6 million due to statute expirations and anticipated audit settlements. This amount is primarily due to timing issues.

NOTE 11. OTHER COMPREHENSIVE INCOME

The components of total comprehensive income were as follows:

	Quarter Ended
	March 31,
Other Comprehensive Income (Loss)	2010	2009
Millions
Net Income	$22.8	$16.9
Other Comprehensive Income
Unrealized Gain (Loss) on Securities Net of income taxes of $– and $(0.6)	0.1	(1.0)
Unrealized Gain on Derivatives Net of income taxes of $– and $0.1	–	0.1
Defined Benefit Pension and Other Postretirement Plans Net of income taxes of $0.2 and $0.1	0.3	0.3
Total Other Comprehensive Income (Loss)	0.4	(0.6)
Total Comprehensive Income	$23.2	$16.3
Less: Non-Controlling Interest in Subsidiaries	(0.2)	–
Comprehensive Income Attributable to ALLETE	$23.4	$16.3

NOTE 12. EARNINGS PER SHARE AND COMMON STOCK

The difference between basic and diluted earnings per share, if any, arises from outstanding stock options and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. For the quarters ended March 31, 2010, and March 31, 2009, 0.6 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices, and therefore, their effect would have been anti-dilutive.

		2010			2009
Reconciliation of Basic and Diluted		Dilutive			Dilutive
Earnings Per Share	Basic	Securities	Diluted	Basic	Securities	Diluted
Millions Except Per Share Amounts
For the Quarter Ended March 31,
Net Income Attributable to ALLETE	$23.0	–	$23.0	$16.9	–	$16.9
Common Shares	33.8	–	33.8	30.9	0.1	31.0
Earnings Per Share	$0.68	–	$0.68	$0.55	–	$0.55

ALLETE First Quarter 2010 Form 10-Q

NOTE 13. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

	Pension		Other Postretirement
Components of Net Periodic Benefit Expense	2010	2009	2010	2009
Millions
For the Quarter Ended March 31,
Service Cost	$1.5	$1.4	$1.2	$1.0
Interest Cost	6.6	6.5	2.7	2.5
Expected Return on Plan Assets	(8.4)	(8.4)	(2.4)	(2.1)
Amortization of Prior Service Costs	0.1	0.1	–	–
Amortization of Net Loss	1.6	0.9	1.2	0.6
Amortization of Transition Obligation	–	–	0.6	0.7
Net Periodic Benefit Expense	$1.4	$0.5	$3.3	$2.7

Employer Contributions. For the quarter ended March 31, 2010, no contributions were made to our defined benefit pension plan ($18.0 million for the quarter ended March 31, 2009) and $2.6 million was contributed to our other postretirement benefit plan ($9.3 million for the quarter ended March 31, 2009). We expect to make approximately $2 million in contributions to our defined benefit pension plan and additional contributions of approximately $11 million to our other postretirement benefit plan in 2010.

We provide postretirement health benefits that include prescription drug benefits which qualify us for the federal subsidy under the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The expected reimbursement for Medicare health subsidies reduced our postretirement medical expense by $1.3 million for 2010 ($2.0 million for 2009). For the quarter ended March 31, 2010, we have not received any prescription drug reimbursements.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES

Off-Balance Sheet Arrangements

Power Purchase Agreements. Our long-term power purchase agreements (PPA) have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPA, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the following factors: we do not have control over activities that are most significant to the entity, and we have no obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our fixed capacity and energy payments.

Square Butte Power Purchase Agreement. Minnesota Power has a power purchase agreement with Square Butte that extends through 2026 (Agreement). It provides a long-term supply of energy to customers in our electric service territory and enables Minnesota Power to meet power pool reserve requirements. Square Butte, a North Dakota cooperative corporation, owns a 455-MW coal-fired generating unit (Unit) near Center, North Dakota. The Unit is adjacent to a generating unit owned by Minnkota Power, a North Dakota cooperative corporation whose Class A members are also members of Square Butte. Minnkota Power serves as the operator of the Unit and also purchases power from Square Butte.

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the contract. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s fixed costs consist primarily of debt service. At March 31, 2010, Square Butte had total debt outstanding of $290.4 million. Annual debt service for Square Butte is expected to be approximately $31 million in each of the five years, 2010 through 2014. Variable operating costs include the price of coal purchased from BNI Coal, our subsidiary, under a long-term contract.

In conjunction with the DC line purchase in December of 2009, Minnesota Power entered into a contingent power sales agreement with Minnkota Power. Under the power sales agreement, Minnesota Power will be able to sell a portion of our output from Square Butte to Minnkota, resulting in Minnkota’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025.

ALLETE First Quarter 2010 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

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

Wind Power Purchase Agreements. We have two wind power purchase agreements with an affiliate of NextEra Energy to purchase the output from two wind facilities, Oliver Wind I (50 MWs) and Oliver Wind II (48 MWs), located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities.

Hydro Power Purchase Agreement. We also have a power purchase agreement with Manitoba Hydro that began in May of 2009 and expires in April of 2015. Under the agreement with Manitoba Hydro, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

North Dakota Wind Project. On December 31, 2009, we purchased an existing 250 kV DC transmission line from Square Butte for $69.7 million. The 465-mile transmission line runs from Center, North Dakota, to Duluth, Minnesota. We expect to use this line to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit. Acquisition of this transmission line was approved by an MPUC order dated December 21, 2009. In addition, the FERC issued an order on November 24, 2009, authorizing acquisition of the transmission facilities and conditionally accepting, upon compliance and other filings, the proposed tariff revisions, interconnection agreement and other related agreements.

On July 7, 2009, the MPUC approved our petition seeking current cost recovery eligibility for investments and expenditures related to Bison I and associated transmission upgrades. On September 29, 2009, the NDPSC authorized site construction for Bison I. On March 10, 2010, the NDPSC authorized construction of a 22 mile, 230 kV transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will help fulfill the Minnesota 2025 renewable energy supply requirement for our retail load. Bison I, located near Center, North Dakota, will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 MWs and will be phased into service in late 2010 and 2011. The Bison I Project, including the associated transmission upgrades to the DC Line, will have a total capital cost of approximately $177 million. In March of 2010, we filed a petition with the MPUC to establish current cost recovery through customer billings for the approved project. We are unable to predict the outcome of this proceeding.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at a fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is $8.8 million in 2010, $8.9 million in 2011, $9.0 million in 2012, $8.5 million in 2013, $8.2 million in 2014 and $45.7 million thereafter.

Coal, Rail and Shipping Contracts. We have three primary coal supply agreements and transportation agreements providing for the purchase and delivery of a significant portion of our coal requirements. These agreements, including option terms, expire in various years between 2010 and 2015. In total, we are committed to a minimum payment of approximately $28 million under these coal, rail and shipping agreements for 2010. Our annual payment obligation for 2011 is $7.6 million, with no specific commitments beyond 2011. Our minimum annual payment obligations will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

ALLETE First Quarter 2010 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes are under consideration by both Congress and the EPA. Most notably, clean energy technologies and the regulation of GHGs have taken a lead in these discussions. Minnesota Power’s fossil fueled facilities will likely be subject to regulation under these climate change policies. Our intention is to reduce our exposure to possible future carbon and GHG legislation by reshaping our generation portfolio, over time, to reduce our reliance on coal.

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

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

Clean Air Act. The federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2 and system-wide average NOX limits. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of these facilities are equipped with pollution control equipment such as scrubbers, bag houses, or electrostatic precipitators. Minnesota Power’s generating facilities are currently in compliance with applicable emission requirements.

New Source Review. On August 8, 2008, Minnesota Power received a Notice of Violation (NOV) from the United States EPA asserting violations of the New Source Review (NSR) requirements of the Clean Air Act at Boswell Units 1-4 and Laskin Unit 2. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements, and that the Boswell Unit 4 Title V permit was violated. Minnesota Power believes the projects were in full compliance with the Clean Air Act, NSR requirements and applicable permits.

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

EPA Clean Air Interstate Rule. In March 2005, the EPA announced the Clean Air Interstate Rule (CAIR) that sought to reduce and permanently cap emissions of SO2, NOX, and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit (Court) vacated the CAIR and remanded the rulemaking to the EPA for reconsideration while also granting our petition that the EPA reconsider including Minnesota as a CAIR state. In September of 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested that the CAIR be remanded without being vacated. In December of 2008, the Court granted the request that the CAIR be remanded without being vacated, effectively reinstating a January 1, 2009 compliance date for the CAIR, including Minnesota. However, pursuant to an amendment to CAIR effective December 3, 2009, the effectiveness of CAIR with respect to Minnesota has been stayed until completion of the EPA’s determination of whether Minnesota should be included as a CAIR state.

ALLETE First Quarter 2010 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Minnesota Regional Haze. The federal regional haze rule requires states to submit state implementation plans (SIPs) to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the regional haze rule, certain large stationary sources, that were put in place between 1962 and 1977 with emissions contributing to visibility impairment are required to install emission controls, known as Best Available Retrofit Technology (BART). We have certain steam units, Boswell Unit 3 and Taconite Harbor Unit 3, which are subject to BART requirements.

Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December of 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April of 2007, the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was never filed due to the United States Court of Appeals for the District of Columbia Circuit review of CAIR as more fully described above under “EPA Clean Air Interstate Rule.” Subsequently, the MPCA requested that companies with BART eligible units complete and submit a BART emissions control retrofit study, which was done on Taconite Harbor Unit 3 in November of 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirement for that unit. On December 15, 2009, the MPCA approved the SIP for submittal to the EPA for review and approval. The EPA is expected to make a decision on whether to approve the state SIP by January of 2011. If approved, Minnesota Power will have five years to bring Taconite Harbor Unit 3 into compliance. It is uncertain what controls will ultimately be required at Taconite Harbor Unit 3 in connection with the regional haze rule.

EPA National Emission Standards for Hazardous Air Pollutants. In March of 2005, the EPA announced the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped electric utility mercury emissions in the continental United States through a cap-and-trade program. In February 2008, the United States Court of Appeals for the District of Columbia Circuit vacated the CAMR and remanded the rulemaking to the EPA for reconsideration. In October of 2008, the EPA petitioned the Supreme Court to review the Court’s decision in the CAMR case. In January of 2009, the EPA withdrew its petition, paving the way for possible regulation of mercury and other hazardous air pollutant emissions through Section 112 of the Clean Air Act, setting Maximum Achievable Control Technology standards for the utility sector. In December of 2009, Minnesota Power and other utilities received an Information Collection Request from the EPA requiring that emissions data be provided and stack testing be performed in order to develop an improved database upon which to base future regulations. On March 30, 2010, Minnesota Power responded to the Information Collection Request. Stack testing is scheduled to be completed by July 30, 2010. The EPA is subject to a consent decree which requires the EPA to propose a rule by March of 2011, with the final rule by November of 2011. Costs for complying with potential future mercury and other hazardous air pollutant regulations under the Clean Air Act cannot be estimated at this time.

Minnesota Mercury Emission Reduction Act. This legislation requires Minnesota Power to file mercury emission reduction plans for Boswell Units 3 and 4, with a goal of 90 percent reduction in mercury emissions. The Boswell Unit 3 emission reduction plan was filed with the MPCA in October of 2006. Mercury control equipment has been installed and was placed into service in November of 2009. A mercury emissions reduction plan for Boswell Unit 4 is required to be submitted by July 1, 2011, with implementation no later than December 31, 2014. This legislation calls for an evaluation of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’s customers. Minnesota legislation has been introduced that would potentially extend the mercury compliance date. Costs for the Boswell Unit 4 emission reduction plan cannot be estimated at this time.

Ozone. The EPA is attempting to control, more stringently, emissions that result in ground level ozone. In January of 2010, the EPA proposed to reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA expects to issue final standards in 2010. As proposed, states have until December of 2013 to submit plans outlining how they will meet the standards.

ALLETE First Quarter 2010 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Climate Change. Minnesota Power is addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customer’s requirements:

·	Expand our renewable energy supply.

·	Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies.

·	Provide energy conservation initiatives for our customers and other demand side efforts.

·	Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.

·	Achieve overall carbon emission reductions.

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

Federal Legislation. 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 emission allowances to the electric utility sector to mitigate cost impacts on consumers. Based on the emission allowance allocations proposed in H.R. 2454, we expect we would have to purchase additional allowances. At this time we are unable to predict the cost of these allowances.

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 a 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. We also cannot predict the nature or timing of any additional GHG legislation or regulation.

Greenhouse Gas Reduction. In 2007, Minnesota passed legislation establishing non-binding targets for carbon dioxide reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025, and at least 80 percent below 2005 levels by 2050.

Midwestern Greenhouse Gas Reduction Accord. Minnesota is also participating in the Midwestern Greenhouse Gas Reduction Accord (the Accord), a regional effort to develop a multi-state approach to GHG emission reductions. The Accord includes an agreement to develop a multi-sector cap-and-trade system to help meet the targets established by the group.

Minnesota Greenhouse Gas Emissions Reporting. In May 2008, Minnesota passed legislation that required the MPCA to track emissions and make interim emissions reduction recommendations towards meeting the State’s goal of reducing GHG by 80 percent by 2050.

International Climate Change Initiatives. The United States is not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) that requires developed countries to cap GHG emissions at certain levels during the 2008 to 2012 time period. In December 2009, leaders of developed and developing countries met in Copenhagen, Denmark, under the UNFCCC and issued the Copenhagen Accord. The Copenhagen Accord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissions of GHG by 2020 and provide for developed countries to fund GHG emissions mitigation projects in developing countries. President Obama participated in the development of, and endorsed, the Copenhagen Accord.

ALLETE First Quarter 2010 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA Greenhouse Gas Reporting Rule. On September 22, 2009, the EPA issued a final rule mandating that certain GHG emission sources, including electric generating units, 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 was 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 and data tools necessary to report 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 GHGs and includes 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, that undergo major modifications that result in a significant increase in emissions to obtain construction and operating permits that demonstrate Best Available Control Technologies (BACT) are being used at the facility. The EPA is expected to propose BACT standards for GHG emissions from stationary sources.

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 could require amending operating permits to incorporate BACT to control GHG emissions. On March 29, 2010, the EPA affirmed that they will not institute measures to require stationary source operating permits for GHG emissions under the Clean Air Act any earlier than 2011.

Minnesota Power’s existing facilities may become subject to the GHG BACT requirements if they undergo major modifications that result in a significant emissions increase. The significant increase thresholds are under review by the EPA.

EPA Endangerment Findings. On December 15, 2009, the EPA published its findings that the emissions of six GHG, including CO2, methane, and nitrous oxide, endanger human health or welfare. On April 1, 2010, the United States Department of Transportation and the EPA jointly announced establishment of motor vehicle GHG emissions standards for passenger vehicles and light trucks. Starting with 2012 model year vehicles, the rules together require automakers to improve fleet-wide fuel economy and reduce fleet-wide GHG emissions by approximately five percent every year for 2012 through 2016. The National Highway Traffic Safety Administration has established fuel economy standards that strengthen each year reaching an estimated 34.1 miles per gallon for the combined industry-wide fleet for model year 2016. There is also a possibility that the endangerment finding will enable expansion of the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. with the United States Court of Appeals for the District of Columbia Circuit on December 23, 2009. The EPA has announced that they do not intend to impose GHG emission requirements on stationary sources any earlier than January 2011.

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

ALLETE First Quarter 2010 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its steam electric stations. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use, or trucked to state permitted landfills. Minnesota Power continues to monitor state and federal legislative and regulatory activities that may affect its ash management practices. The EPA is expected to propose new regulations pertaining to the management of coal ash by electric utilities. It is unknown how potential coal ash management rule changes will affect Minnesota Power’s facilities. On March 9, 2009, the EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received an additional EPA information request pertaining to Boswell. Minnesota Power responded to both of these information requests. On August 19, 2009, dam safety officials from the Minnesota Department of Natural Resources (MDNR) visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findings or concerns from the MDNR staff during the inspections.

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site within the City of Superior, Wisconsin and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. At March 31, 2010, we have a $0.5 million liability for this site, and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.

BNI Coal. As of March 31, 2010, BNI Coal had surety bonds outstanding of $18.4 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, an additional guarantee is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a Letter of Credit with CoBANK ACB for an additional $10.0 million. The combination of the surety bonds and the Letter of Credit is sufficient to meet the requirements to guarantee BNI Coal’s total reclamation liability, currently estimated at $25.1 million.

ALLETE Properties. As of March 31, 2010, ALLETE Properties, through its subsidiaries, had surety bonds outstanding of $14.7 million primarily related to performance and maintenance obligations to governmental entities to construct improvements in the Company’s various projects. The remaining work to be completed on these improvements is estimated to be approximately $9.9 million, and ALLETE Properties does not believe it is likely that any of these outstanding bonds will be drawn upon.

Community Development District Obligations. In March of 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent Capital Improvement Revenue Bonds, Series 2005; and in May of 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent Special Assessment Bonds, Series 2006. The Capital Improvement Revenue Bonds and the Special Assessment Bonds are payable through property tax assessments on the land owners over 31 years (by May 1, 2036, and 2037, respectively). The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district, and to mitigate traffic and environmental impacts. The bonds are payable from and secured by the revenue derived from annual assessments imposed, levied and collected by each district. The assessments were billed to the landowners beginning in November 2006, for Town Center and November 2007, for Palm Coast Park. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At March 31, 2010, we owned 69 percent of the assessable land in the Town Center District (69 percent at December 31, 2009) and 86 percent of the assessable land in the Palm Coast Park District (86 percent at December 31, 2009). At these ownership levels our annual assessments are approximately $1.5 million for Town Center and $2.0 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. Under current accounting rules, these bonds are not reflected as debt on our consolidated balance sheet.

ALLETE First Quarter 2010 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other. We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base and cost of service issues, among other things. While the resolution of such matters could have a material effect on earnings and cash flows in the year of resolution, none of these matters are expected to materially change our present liquidity position, or have a material adverse effect on our financial condition.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our consolidated financial statements, notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from the 2009 Form 10-K and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-Q under the heading: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” located on page 5 and “Risk Factors” located in Part I, Item 1A, page 23 of our 2009 Form 10-K. The risks and uncertainties described in this Form 10-Q and our 2009 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the concerns set forth are realized.

OVERVIEW

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to 145,000 retail customers and wholesale electric service to 16 municipalities. Minnesota Power also provides regulated utility electric service to 1 private utility in Wisconsin. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment. This segment also includes a small amount of non-rate base generation, approximately 7,000 acres of land available-for-sale in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of March 31, 2010, unless otherwise indicated. All subsidiaries are wholly owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

Financial Overview

The following net income discussion summarizes a comparison of the quarter ended March 31, 2010, to the quarter ended March 31, 2009.

Net income attributable to ALLETE for the quarter ended March 31, 2010, was $23.0 million, or $0.68 per diluted share, compared to $16.9 million, or $0.55 per diluted share, for the same period of 2009. The first quarter of 2009 was reduced by a $3.2 million, or $0.10 per share, after-tax charge for the accrual of retail rate refunds related to 2008.

ALLETE First Quarter 2010 Form 10-Q

OVERVIEW (Continued)

Regulated Operations net income attributable to ALLETE was $24.9 million for the first quarter of 2010, compared to $17.7 million for the same period of 2009; the first quarter of 2009 was reduced by a $3.2 million after-tax charge for the accrual of retail rate refunds related to 2008. The period-over-period increase is attributable to MPUC-approved interim retail rates (subject to refund), higher FERC-approved wholesale rates, and increased transmission related margins. These increases were significantly offset by higher operating, depreciation and income tax expenses. Income tax expense included a $3.6 million charge resulting from the Patient Protection and Affordable Care Act of 2010 that eliminated the deduction for expenses reimbursed under Medicare Part D. In addition, 2010 reflected $0.2 million in additional after-tax earnings from our investment in ATC.

Investments and Other reflected a net loss attributable to ALLETE of $1.9 million in the first quarter of 2010, compared to a net loss of $0.8 million in 2009. Contributing to the decrease is a slightly higher loss at ALLETE Properties ($1.4 million loss in 2010 compared to a loss of $1.1 million in 2009), the transfer of a small generating facility to our Regulated Operations in November of 2009, and a $0.4 million charge related to the Patient Protection and Affordable Care Act of 2010.

COMPARISON OF THE QUARTERS ENDED MARCH 31, 2010 AND 2009

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

Regulated Operations

Operating revenue increased $35.0 million, or 19 percent, from 2009 due to authorized Minnesota interim retail electric rates from our 2010 rate case, higher FERC-approved wholesale rates, and the absence of an accrual of prior year retail rate refunds related to our 2008 retail rate case. Also contributing to increased revenue was higher fuel and purchased power recoveries, increased sales to our retail and municipal customers, and higher transmission revenues. These increases were partially offset by lower sales to Other Power Suppliers.

Interim retail rates authorized by the MPUC in December of 2009, and effective January 1, 2010, resulted in an increase of approximately $9.5 million. Interim rates are subject to refund pending the MPUC’s final rate order. (See Note 6. Regulatory Matters.)

Higher rates from the February 1, 2009, and January 1, 2010, FERC-approved wholesale rate increases for our municipal customers increased revenue by $4.0 million. (See Note 6. Regulatory Matters.)

Retail rate refunds related to 2008 resulting from the 2009 MPUC Order were recorded in 2009 and resulted in a reduction in 2009 revenues of $5.3 million.

Higher fuel and purchased power recoveries, along with an increase in retail and municipal kilowatt-hour sales combined for a total revenue increase of $11.5 million. Fuel and purchased power recoveries increased due to an increase in fuel and purchased power expense. (See Fuel and Purchased Power Expense.) Total kilowatt-hour sales to retail and municipal customers increased 3.5 percent from 2009 primarily due to increased sales to our taconite customers.

Transmission revenues increased $6.0 million from 2009 primarily due to revenues related to the 250 kV DC transmission line we purchased from Square Butte on December 31, 2009.

The increase in kilowatt-hour sales to retail customers has been partially offset by decreased revenue from marketing power to Other Power Suppliers, which decreased $2.8 million in 2010. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.

ALLETE First Quarter 2010 Form 10-Q

COMPARISON OF THE QUARTERS ENDED MARCH 31, 2010 AND 2009 (Continued)

Regulated Operations (Continued)

Total kilowatt-hour sales to retail and municipal customers increased 3.5 percent from 2009 primarily due to an 11 percent increase in sales to our taconite customers. Increased revenue from our industrial sales was partially offset by a 12 percent decrease in kilowatt-hour sales to Other Power Suppliers.

Kilowatt-hours Sold						Quantity	%
Quarter Ended March 31,				2010	2009	Variance	Variance
Millions
Regulated Utility
	Retail and Municipals
		Residential		357	375	(18)	(4.8) %
		Commercial		372	379	(7)	(1.8) %
		Industrial		1,429	1,323	106	8.0 %
		Municipals		265	265	–	– %
			Total Retail and Municipals	2,423	2,342	81	3.5 %
	Other Power Suppliers			803	916	(113)	(12.3) %
Total Regulated Utility Kilowatt-hours Sold				3,226	3,258	(32)	(1.0) %

Revenue from electric sales to taconite customers accounted for 21 percent of consolidated operating revenue in 2010 (19 percent in 2009). The increase in revenue from our taconite customers was partially offset by a decrease in revenue from electric sales to Other Power Suppliers which accounted for 14 percent of consolidated operating revenue in 2010 (17 percent in 2009). Revenue from electric sales to paper and pulp mills accounted for 8 percent of consolidated operating revenue in 2010 (8 percent in 2009). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2010 (7 percent in 2009).

Operating expenses increased $18.9 million, or 13 percent, from 2009.

Fuel and Purchased Power Expense increased $7.0 million, or 10 percent, from 2009. The increase is primarily due to higher fuel costs of $4.5 million resulting from higher coal prices and related transportation. Purchased power expense also increased $2.5 million reflecting higher market prices partially offset by lower kilowatt-hour purchases.

Operating and Maintenance Expense increased $7.0 million, or 11 percent, from 2009 reflecting additional MISO expenses of $4.1 million relating to the 250 kV DC transmission line we purchased from Square Butte on December 31, 2009, and increased benefits costs of $2.0 million.

Depreciation Expense increased $4.9 million, or 35 percent, from 2009 reflecting higher property, plant, and equipment placed in service.

Income tax expense increased $8.9 million, or 75 percent, from 2009 primarily due to higher pretax income and a non-recurring charge to ALLETE’s net income from the Patient Protection and Affordable Care Act of $3.6 million.

Investments and Other

Operating revenue decreased $1.0 million, or 5 percent, from 2009 primarily due to a $1.6 million reduction in sales revenue at ALLETE Properties. No sales were made during the first quarter of 2010 at ALLETE Properties, due to the continued lack of demand for our properties as a result of poor real estate market conditions in Florida. During the first quarter of 2009, ALLETE Properties sold approximately 19 acres of property located outside of its three main development projects for $2.2 million.

ALLETE First Quarter 2010 Form 10-Q

COMPARISON OF THE QUARTERS ENDED MARCH 31, 2010 AND 2009 (Continued)

Investments and Other (Continued)

ALLETE Properties	2010		2009
Revenue and Sales Activity	Quantity	Amount	Quantity	Amount
Dollars in Millions
Revenue from Land Sales
Acres (a)	–	–	19	$2.2
Contract Sales Price (b)		–		2.2
Deferred Revenue		–		(0.6)
Revenue from Land Sales		–		1.6
Other Revenue		$0.2		0.2
Total ALLETE Properties Revenue		$0.2		$1.8

(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.

Revenue from non-regulated generation was down $1.5 million primarily due to a reduction in kilowatt-hour sales as there was a transfer of a small generating facility to Regulated Operations in November of 2009. These decreases were partially offset by BNI Coal, which operates under a cost-plus contract and recorded additional revenue of $2.1 million as a result of higher expenses in 2010. (See Operating Expense.)

Operating expenses increased $0.1 million, or 1 percent, from 2009 reflecting higher expenses at BNI Coal of $2.0 million primarily due to higher fuel costs; these costs were recovered through the cost-plus contract. (See Operating Revenue.) This increase was offset by decreased expenses at ALLETE Properties of $1.0 million due to reductions in the cost of land sold and general and administrative expenses, and $0.9 million as a result of the transfer of a small generating facility to Regulated Operations in November of 2009.

Income Taxes – Consolidated

For the quarter ended March 31, 2010, the effective tax rate was 46.6 percent (39.0 percent for the quarter ended March 31, 2009). Excluding additional tax expense recorded as a result of the Patient Protection and Affordable Care Act, the 2010 effective tax rate was 37.2 percent. The 2010 effective tax rate, excluding the additional tax expense recorded as a result of the Patient Protection and Affordable Care Act, deviated from the statutory rate (approximately 41 percent) due to deductions for AFUDC-Equity, investment tax credits, wind production tax credits, and depletion. In addition to these items, the 2009 effective tax rate included the effect of deductions for Medicare prescription drug subsidies and additional expense related to a non-recurring permanent item. We expect the effective tax rate for the full year 2010 to be approximately 39 percent (36 percent excluding the effect of the Patient Protection and Affordable Care Act). (See Note 10. Income Tax Expense.)

CRITICAL ACCOUNTING ESTIMATES

Certain accounting measurements under GAAP involve management’s judgment about subjective factors and estimates, the effects of which are inherently uncertain. Accounting measurements that we believe are most critical to our reported results of operations and financial condition include: regulatory accounting, valuation of investments, pension and postretirement health and life actuarial assumptions, and taxation. These policies are reviewed with the Audit Committee of our Board of Directors on a regular basis and summarized in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2009 Form 10-K.

ALLETE First Quarter 2010 Form 10-Q

OUTLOOK

For additional information see our 2009 Form 10-K.

ALLETE is an energy company committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. To accomplish this, we intend to take the actions necessary to earn our allowed rate of return in our regulated businesses, while we pursue growth initiatives in renewable energy, transmission and other energy-centric businesses.

We believe that over the long term, wind energy will play an increasingly important role in our nation’s energy mix. We intend to pursue the establishment of a renewable energy business focused initially on developing wind assets in North Dakota and the upper Midwest. We intend to develop wind resources which will be used to meet renewable supply requirements of our regulated businesses as well as wind resources that will be marketed to others. We will capitalize on our existing presence in North Dakota through BNI Coal, our recently acquired DC transmission line and our Bison I wind project. Through BNI Coal we have a long-term business presence and established landowner relationships in North Dakota. See page 32 for more discussion on the DC line acquisition and our Bison I project. For projects to be marketed to others, we intend to secure long-term power purchase agreements prior to construction of the wind generation facilities. Establishment of the business is subject to appropriate MPUC approvals.

We also plan to make investments in upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid, or take advantage of our geographical location between sources of renewable energy and end users. In addition, we plan to make additional investments to fund our pro rata share of ATC’s future capital expansion program. Minnesota Power is also participating with other regional utilities in making regional transmission investments as a member of the CapX2020 initiative. The CapX2020 initiative is discussed in more detail on page 33.

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

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

Regulated Operations. Minnesota Power’s long-term strategy is to maintain its competitively priced production of energy, reduce customer concentration exposure, comply with environmental and renewable requirements, and earn our allowed rate of return. Keeping the production of energy competitive enables Minnesota Power to effectively compete in the wholesale power markets, and minimizes retail rate increases to help maintain the viability of its customers. As part of maintaining cost competitiveness, Minnesota Power intends to reduce its exposure to possible future carbon and GHG legislation by reshaping its generation portfolio, over time, to reduce its reliance on coal. Minnesota Power intends to reduce its customer concentration risk to reduce exposure to cyclical industries; this may include restructuring commercial contracts, additional sales to other regional power suppliers, and reshaping our power supply to be more flexible to swings in customer demand. We will monitor and review environmental proposals and may challenge those that add considerable cost with limited environmental benefit. Current economic conditions require a very careful balancing of the benefit of further environmental controls with the impacts of the costs of those controls on our customers as well as on the Company and its competitive position. We will pursue current cost recovery riders to recover environmental and renewable investments, and will work with our legislators and regulators to earn a fair return.

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

ALLETE First Quarter 2010 Form 10-Q

OUTLOOK (Continued)

Rates (Continued)

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal 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 customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts that transitioned these customers to formula-based rates which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are set at the beginning of the year based on expected costs and provide for a true-up calculation for actual costs. Wholesale rate increases totaling approximately $13 million annually were implemented on January 1, 2010. When final actual costs are known, the final rate increase attributable to 2010 may vary from the wholesale rate increase implemented on January 1, 2010.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, paper production, and pipeline industries. Approximately 44 percent of our Regulated Utility kilowatt-hour sales in the quarter ended March 31, 2010 (41 percent in the quarter ended March 31, 2009), were made to our industrial customers, which include the taconite, paper and pulp, and pipeline industries.

ALLETE First Quarter 2010 Form 10-Q

OUTLOOK (Continued)

Industrial Customers (Continued)

Beginning in the fall of 2008, worldwide steel makers began to dramatically cut steel production in response to reduced demand driven largely by the global credit concerns. United States raw steel production ran at approximately 50 percent of capacity in 2009, reflecting poor demand in automobiles, durable goods, and structural and other steel products.

In late 2008, Minnesota taconite producers began to feel the impacts of decreased steel demand, and reduced taconite production levels occurred in 2009. Annual taconite production in Minnesota was approximately 18 million tons in 2009. Consequently, 2009 kilowatt-hour sales to our taconite customers were lower by approximately 54 percent from 2008 levels, and we sold available power to Other Power Suppliers to partially mitigate the earnings impact of these lower taconite sales.

Raw steel production in the United States is projected to improve in 2010, and is estimated to run at approximately 70 percent of capacity. As a result, Minnesota Power expects an increase in taconite production in 2010 compared to 2009, although production will still be less than previous years’ levels (40 million tons in 2008). We will continue to market available power to Other Power Suppliers in an effort to mitigate the earnings impact of these lower industrial sales. Sales to Other Power Suppliers 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. We can make no assurances that our power marketing efforts will fully offset the reduced earnings resulting from lower demand nominations from our industrial customers.

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail energy sales in Minnesota to 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. Minnesota Power has identified a plan to meet the renewable goals set by Minnesota and has included this plan in the most recent filing of the Integrated Resource Plan with the MPUC. 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.

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

On July 7, 2009, the MPUC approved our petition seeking current cost recovery eligibility for investments and expenditures related to Bison I and associated transmission upgrades. On September 29, 2009, the NDPSC authorized site construction for Bison I. On March 10, 2010, the NDPSC authorized construction of a 22 mile, 230 kV transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will help fulfill the 2025 renewable energy supply requirement for our retail load. Bison I, located near Center, North Dakota, will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 MWs and is expected to be in service in late 2010 and 2011. The Bison I Project, including the associated transmission upgrades to the DC Line, will have a total capital cost of approximately $177 million. In March 2010, we filed a petition with the MPUC to establish current cost recovery through customer billings for the approved project. We are unable to predict the outcome of this proceeding.

ALLETE First Quarter 2010 Form 10-Q

OUTLOOK (Continued)

Integrated Resource Plan. On October 5, 2009, Minnesota Power filed with the MPUC its 2010 Integrated Resource Plan, 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 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 plan to reshape 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 is expected to be in service in late 2010 and 2011.

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 demand side management to meet the energy savings goals established in Minnesota legislation.

CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, 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.

Minnesota Power intends to invest in two 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. The MPUC issued the Certificate of Need for the 230 kV line in July 2009. The MPUC decisions on the Route Permit applications for the two projects are expected in 2010. Our total investment in these lines is expected to be approximately $100 million. We intend to seek recovery of these costs under the Minnesota Power transmission cost recovery tariff rider authorized by Minnesota legislation. Construction of the lines is targeted to begin in late 2010 and may take up to five years.

Emission Reduction Plans. We have made investments in pollution control equipment at our Boswell Unit 3 generating unit that reduces particulates, SO2, NOx and mercury emissions to meet future federal and state requirements. This equipment was placed in service in November of 2009. Our 2010 rate case proposes to move this project from a current cost recovery rider to base rates. (See Note 6. Regulatory Matters.)

Boswell NOX Reduction Plan. In September of 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for expenditures relating to NOX emission reductions from Boswell Units 1, 2, and 4. The Boswell NOX Reduction Plan is expected to significantly reduce NOX emissions from these units. In conjunction with the NOX reduction, we plan to make an efficiency improvement to our existing turbine/generator at Boswell Unit 4 adding approximately 60 MWs of total output. The Boswell 1, 2 and 4 selective non-catalytic reduction NOX controls are currently in service, while the Boswell 4 low NOX burners and turbine efficiency projects are anticipated to be in service in late 2010. Our 2010 rate case seeks recovery for this project in base rates.

Transmission. We have an approved cost recovery rider in place for certain transmission expenditures, and our current billing factor was approved by the MPUC in June of 2009. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. Our 2010 rate case proposes to move completed transmission projects from the current cost recovery rider to base rates.

ALLETE First Quarter 2010 Form 10-Q

OUTLOOK (Continued)

Power Sales Agreement. On October 29, 2009, Minnesota Power entered into an agreement to sell Basin 100 MWs of capacity and energy for the next ten years, beginning in May of 2010. The Basin agreement contains a fixed monthly schedule of capacity charges with an annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro-rata share of increased costs related to emissions that may occur during the last five years of the contract.

Investment in ATC. At March 31, 2010, our equity investment in ATC was $90.3 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 are based on a 12.2 percent return on common equity dedicated to utility plant. ATC has identified $2.5 billion in future projects needed over the next 10 years to improve the adequacy and reliability of the electric transmission system. This investment is expected to be funded through a combination of internally generated 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. We expect to invest an additional $1 million in 2010. (See Note 7. Investment in ATC.)

Investments and Other

BNI Coal. BNI Coal anticipates selling approximately 4 million tons of coal in 2010 (4.2 million tons were sold in 2009) and has sold approximately 1 million tons through March 31, 2010 (1.0 million tons sold as of March 31, 2009).

ALLETE Properties. ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, and sell the portfolio over time or in bulk transactions. ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise, and reinvest the proceeds in its growth initiatives. ALLETE does not intend to acquire additional Florida real estate.

Our two major development projects are Town Center and Palm Coast Park. Ormond Crossings is a third major project that is currently in the planning stage. On February 16, 2010, the City of Ormond Beach, FL approved a Development Agreement for Ormond Crossings. The agreement will facilitate development of the project as currently planned. Separately, the Lake Swamp wetland mitigation bank was permitted on land that was previously part of Ormond Crossings.

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%	854	2,089	2,191,200
Palm Coast Park	100%	3,385	3,154	3,056,800
Total Current Development Projects		4,239	5,243	5,248,000

Planned Development Project
Ormond Crossings	100%	2,924	2,950	3,215,000
Other
Lake Swamp Wetland Mitigation Project	100%	3,049	(d)	(d)

Total of Development Projects		10,212	8,193	8,463,000

(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)

The Lake Swamp wetland mitigation bank is a regionally significant wetlands mitigation bank that was permitted by the St. Johns River Water Management District in 2008 and by the U.S. Army Corps of Engineers in December 2009. Wetland mitigation credits will be used at Ormond Crossings, and will also be available-for-sale to developers of other projects that are located in the bank’s service area.

ALLETE Properties also has 1,374 acres of other land available-for-sale outside of the three development projects.

ALLETE First Quarter 2010 Form 10-Q

OUTLOOK (Continued)

Investments and Other (Continued)

Long-term finance receivables as of March 31, 2010, were $12.5 million, which included $7.6 million due from an entity that 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 $7.6 million amount due at March 31, 2010, and no impairment was recorded.

If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract, and retaining the collateral and 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.

ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise. However, if weak market conditions continue for an extended period of time, the impact on our future operations would be the continuation of minimal or 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.

Income Taxes. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2010. 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 drug subsidies, as well as other items. The annual effective rate can also be impacted by such items as changes in income 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 2010 effective tax rate to be approximately 39 percent (36 percent excluding the effect of the Patient Protection and Affordable Care Act).

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Position. ALLETE is well-positioned to meet the Company’s immediate cash flow needs. At March 31, 2010, we have a cash balance of $32.5 million, $153.2 million in available consolidated lines of credit which includes a committed, syndicated, unsecured revolving line of credit of $150.0 million, and a debt-to-capital ratio of 43 percent. At March 31, 2010, we project sufficient capital availability.

Capital Structure. ALLETE’s capital structure is as follows:

	March 31,		December 31,
	2010	%	2009	%
Millions
ALLETE Equity	$947.9	57	$929.5	57
Non-Controlling Interest	9.3	–	9.5	–
Long-Term Debt (Including Current Maturities)	711.7	43	701.0	43
Short-Term Debt	1.7	–	1.9	–
	$1,670.6	100	$1,641.9	100

Cash Flows. Selected information from ALLETE’s Consolidated Statement of Cash Flows is as follows:

For the Quarter Ended March 31,	2010	2009
Millions
Cash and Cash Equivalents at Beginning of Period	$25.7	$102.0
Cash Flows from (used for)
Operating Activities	56.7	34.5
Investing Activities	(51.7)	(69.6)
Financing Activities	1.8	31.1
Change in Cash and Cash Equivalents	6.8	(4.0)
Cash and Cash Equivalents at End of Period	$32.5	$98.0

ALLETE First Quarter 2010 Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Operating Activities. Cash from operating activities was $56.7 million for the quarter ended March 31, 2010 ($34.5 million for the quarter ended March 31, 2009). Cash from operating activities was higher in 2010 primarily due to higher net income, higher depreciation expense, and lower contributions to the defined benefit pension and other postretirement benefit plans (included in regulatory and other liabilities on the consolidated statement of cash flows).

Investing Activities. Cash used for investing activities was $51.7 million for the quarter ended March 31, 2010 ($69.6 million for the quarter ended March 31, 2009). Cash used for investing activities was lower than 2009 reflecting decreased capital additions to property, plant and equipment. Capital additions in 2009 were higher due to construction activity for environmental retrofit projects in 2009.

Financing Activities. Cash from financing activities was $1.8 million for the quarter ended March 31, 2010 ($31.1 million for the quarter ended March 31, 2009). Cash from financing activities was lower in 2010 due to higher bond proceeds in 2009. In February 2010, we issued $80 million of First Mortgage Bonds and used the majority of the proceeds to pay off the $65 million borrowed from the syndicated revolving credit facility in late 2009, resulting in net proceeds of $15 million in 2010, compared to $42 million of proceeds in 2009.

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 available consolidated bank lines of credit aggregating $153.2 million, the majority of which expire in January 2012. In addition, we have 0.2 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 3.2 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.

Securities. In February 2010, we issued $80.0 million in principal amount of unregistered First Mortgage Bonds (Bonds) in the private placement market in three series (See Note 8. Short-Term and Long-Term Debt). We used the proceeds from the sale of Bonds to pay down the syndicated revolving credit facility, to fund utility capital investments and for general corporate purposes. 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 the terms and conditions of our utility mortgage. The Bonds were sold in reliance on an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

We entered into a Distribution Agreement with KCCI, Inc., originating in February 2008, and subsequently amended in February 2009, with respect to the issuance and sale of up to an aggregate of 6.6 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 pursuant to Registration Statement No. 333-147965. For the three months ended March 31, 2010, 0.1 million shares of common stock were issued under this agreement resulting in net proceeds of $3.0 million (no shares were issued for the three months ended March 31, 2009).

In 2010, we issued 0.2 million shares of common stock through Invest Direct, the Employee Stock Purchase Plan and the Retirement Savings and Stock Ownership Plan resulting in net proceeds of $4.3 million. These shares of common stock were registered under Registration Statement Nos. 333-150681, 333-105225, and 333-124455, respectively.

Financial Covenants. See Note 8. Short-Term and Long-Term Debt for information regarding our financial covenants.

Pension and Other Postretirement Benefit Plans. The funded status of the defined benefit pension plan and other postretirement benefit plan 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.

ALLETE First Quarter 2010 Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Pension and Other Postretirement Benefit Plans (Continued)

Management considers various factors when making funding decisions, such as regulatory requirements, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the defined benefit pension plans. We expect to make approximately $2 million in contributions to our defined benefit pension plan and approximately $13 million to our other postretirement benefit plan in 2010. (See Note 13. Pension and Other Postretirement Benefit Plans.) Estimated defined benefit pension contributions for years 2011 through 2014 are expected to be up to $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 other postretirement benefit plan contributions for years 2011 through 2014 are expected to be approximately $11 million per year, and are based on estimates and assumptions that are subject to change.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements are summarized in our 2009 Form 10-K, with additional disclosure in Note 14. Commitments, Guarantees and Contingencies of this Form 10-Q.

Capital Requirements

For the quarter ended March 31, 2010, capital expenditures totaled $43.6 million ($61.7 million at March 31, 2009). The expenditures were primarily made in the Regulated Operations segment. Internally generated funds and long-term debt and equity issuances were the primary sources of funding.

OTHER

Environmental Matters

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. Environmental Matters are summarized in our 2009 Form 10-K, with additional disclosure in Note 14. Commitments, Guarantees and Contingencies of this Form 10-Q. We are unable to predict the outcome of the matters discussed.

Employees

Minnesota Power and SWL&P have an aggregate 614 employees who are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. Throughout 2009, Minnesota Power, SWL&P and IBEW Local 31 worked towards settling new contracts to replace those which expired on January 31, 2009. Final resolution of the union contract for Minnesota Power occurred in January of 2010. SWL&P achieved final resolution through arbitration on March 12, 2010. The terms of both agreements are retroactive to February 1, 2009, and will expire on January 31, 2012.

NEW ACCOUNTING STANDARDS

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

ALLETE First Quarter 2010 Form 10-Q

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SECURITIES INVESTMENTS

Available-for-sale Securities. As of March 31, 2010, our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities. (See Note 3. Investments.)

COMMODITY PRICE RISK

Our regulated utility operations incur costs for power and fuel (primarily coal and related transportation) in Minnesota, and power and natural gas purchased for resale in our regulated service territories in Wisconsin. Our Minnesota regulated utilities’ exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory environment, which allows recovery of fuel costs in excess of those in the 2008 retail rate case filing. Conversely, costs below those in the 2008 retail rate case filing result in a credit to our ratepayers. We seek to prudently manage our customers’ exposure to price risk by entering into contracts of various durations and terms for the purchase of power and coal and related transportation costs (in Minnesota), and power and natural gas (in Wisconsin).

POWER MARKETING

Our power marketing activities consist of (1) purchasing energy in the wholesale market to serve our regulated service territories when retail energy requirements exceed generation output and (2) selling excess available energy and purchased power. From time to time, our utility operations may have excess energy that is temporarily not required by retail and wholesale customers in our regulated service territory. We actively sell this energy to the wholesale market to optimize the value of our generating facilities.

Demand nominations for power from our taconite customers in 2010 are expected to be higher than 2009, but lower than previous years’ levels.

We are exposed to credit risk primarily through our power marketing activities. We use credit policies to manage credit risk, which includes utilizing an established credit approval process and monitoring counterparty limits.

Power Sales Agreement. On October 29, 2009, Minnesota Power entered into an agreement to sell Basin 100 MWs of capacity and energy for the next ten years, beginning in May of 2010. The Basin agreement contains a fixed monthly schedule of capacity charges with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro-rata share of increased costs related to emissions that may occur during the last five years of the contract.

INTEREST RATE RISK

We are also exposed to risks resulting from changes in interest rates as a result of our issuance of variable rate debt. We manage our interest rate risk by varying the issuance and maturity dates of our fixed rate debt, limiting the amount of variable rate debt, and continually monitoring the effects of market changes in interest rates. Interest rates on variable rate long-term debt are reset on a periodic basis reflecting current market conditions. Based on the variable rate debt outstanding at March 31, 2010, and assuming no other changes to our financial structure, an increase or decrease of 100 basis points in interest rates would impact the amount of pretax interest expense by $0.7 million. This amount was determined by considering the impact of a hypothetical 100 basis point change to the average variable interest rate on the variable rate debt outstanding as of March 31, 2010.

ALLETE First Quarter 2010 Form 10-Q

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As of March 31, 2010, 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

There have been no material changes from the risk factors disclosed in Part 1, Item 1A Risk Factors of our 2009 Form 10-K.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. RESERVED

ITEM 5. OTHER INFORMATION

None.

ALLETE First Quarter 2010 Form 10-Q

PART II. OTHER INFORMATION (Continued)

ITEM 6. EXHIBITS

Exhibit

Number

Thirty-first Supplemental Indenture, dated as of February 1, 2010, between ALLETE and The Bank of New York Mellon and Douglas J. MacInnes, as Trustees.

10(a)

Amendment to the ALLETE Director Stock Plan Effective May 1, 2010.

10(b)

ALLETE Non-Management Director Compensation Summary Effective May 1, 2010.

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 April 30, 2010, announcing 2010 first 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 First Quarter 2010 Form 10-Q

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.




April 30, 2010		/s/ Mark A. Schober
		Mark A. Schober
		Senior Vice President and Chief Financial Officer





April 30, 2010		/s/ Steven Q. DeVinck
		Steven Q. DeVinck
		Controller and Vice President – Business Support

ALLETE First Quarter 2010 Form 10-Q