SEC Filing | ALLETE, Inc.

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ALE 6-30-2013 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended June 30, 2013



¨	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. x 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). x 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 x	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 x No

Common Stock, no par value,

40,127,405 shares outstanding

as of June 30, 2013

INDEX



			Page

Definitions			3

Forward-Looking Statements			5

Part I.	Financial Information

	Item 1.	Financial Statements (Unaudited)

	Consolidated Balance Sheet -
		June 30, 2013 and December 31, 2012	6

	Consolidated Statement of Income -
		Quarter and Six Months Ended June 30, 2013 and 2012	7

	Consolidated Statement of Comprehensive Income -
		Quarter and Six Months Ended June 30, 2013 and 2012	8

	Consolidated Statement of Cash Flows -
		Six Months Ended June 30, 2013 and 2012	9

	Notes to Consolidated Financial Statements		10

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49

	Item 4.	Controls and Procedures	50

Part II.	Other Information

	Item 1.	Legal Proceedings	50

	Item 1A.	Risk Factors	50

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50

	Item 3.	Defaults Upon Senior Securities	50

	Item 4.	Mine Safety Disclosures	51

	Item 5.	Other Information	51

	Item 6.	Exhibits	51

Signatures			52

ALLETE Second Quarter 2013 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 – the cost of both debt and equity funds used to finance utility plant additions during construction periods
ALLETE	ALLETE, Inc.
ALLETE Clean Energy	ALLETE Clean Energy, Inc.
ALLETE Properties	ALLETE Properties, LLC, and its subsidiaries
ArcelorMittal	ArcelorMittal USA, Inc.
ATC	American Transmission Company LLC
Bison	Bison Wind Energy Center
BNI Coal	BNI Coal, Ltd.
Boswell	Boswell Energy Center
CAIR	Clean Air Interstate Rule
CO₂	Carbon Dioxide
Company	ALLETE, Inc., and its subsidiaries
CSAPR	Cross-State Air Pollution Rule
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
GAAP	United States Generally Accepted Accounting Principles
GHG	Greenhouse Gases
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
Item ___	Item ___ of this Form 10-Q
kV	Kilovolt(s)
Laskin	Laskin Energy Center
LIBOR	London Interbank Offered Rate
MACT	Maximum Achievable Control Technology
Manitoba Hydro	Manitoba Hydro-Electric Board
MATS	Mercury and Air Toxics Standards
Medicare Part D	Medicare Part D provision of The Patient Protection and Affordable Care Act of 2010
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.

ALLETE Second Quarter 2013 Form 10-Q



Definitions (Continued)
Abbreviation or Acronym	Term
MISO	Midcontinent Independent System Operator, Inc.
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission
MW / MWh	Megawatt(s) / Megawatt-hour(s)
NAAQS	National Ambient Air Quality Standards
NDPSC	North Dakota Public Service Commission
Non-residential	Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NO₂	Nitrogen Dioxide
NO_X	Nitrogen Oxides
Note ___	Note ___ to the consolidated financial statements in this Form 10-Q
NPDES	National Pollutant Discharge Elimination System
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
PolyMet	PolyMet Mining Corporation
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PSCW	Public Service Commission of Wisconsin
Rainy River Energy	Rainy River Energy Corporation - Wisconsin
SEC	Securities and Exchange Commission
SIP	State Implementation Plan
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
U.S.	United States of America
USS Corporation	United States Steel Corporation
WDNR	Wisconsin Department of Natural Resources

ALLETE Second Quarter 2013 Form 10-Q

Forward-Looking Statements

Statements in this report that are not statements of historical facts are 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 can be 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,” “likely,” “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 providing this cautionary statement to identify important factors that could cause our actual results to differ materially from those indicated in forward-looking statements made by or on behalf of ALLETE in this 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 that could cause our actual results to differ materially from those indicated in the forward-looking statements:


•	our ability to successfully implement our strategic objectives;

•

regulatory or legislative actions, including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, the EPA and various state, local and county regulators, and city administrators, that impact our allowed rates of return, capital structure, ability to secure financing, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power, capital investments and other expenses, including present or prospective wholesale and retail competition and environmental matters;


•	our ability to manage expansion and integrate acquisitions;


•	our current and potential industrial and municipal customers’ ability to execute announced expansion plans;


•	the impacts on our Regulated Operations of climate change and future regulation to restrict the emissions of GHG;


•	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, acts of terrorism and cyber attacks;


•	wholesale power market conditions;


•	population growth rates and demographic patterns;


•	effects of competition, including competition for retail and wholesale customers;


•	zoning and permitting of land held for resale, real estate development or changes in the real estate market;


•	pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such 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 and capital 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.

Additional disclosures regarding factors that could cause our results or performance to differ from those anticipated by this report are discussed in Item 1A under the heading “Risk Factors” beginning on page 27 of our 2012 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 we assess the impact of each of these factors on our businesses 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 identify the risks and uncertainties that may affect our business.

ALLETE Second Quarter 2013 Form 10-Q

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLETE

CONSOLIDATED BALANCE SHEET

Millions – Unaudited



	June 30, 2013			December 31, 2012

Assets
Current Assets
Cash and Cash Equivalents		$145.0			$80.8
Accounts Receivable (Less Allowance of $1.1 and $1.0)	78.7			89.0
Inventories	71.0			69.8
Prepayments and Other	26.2			33.6
Total Current Assets	320.9			273.2
Property, Plant and Equipment - Net	2,397.2			2,347.6
Regulatory Assets	337.5			340.3
Investment in ATC	111.2			107.3
Other Investments	140.2			143.5
Other Non-Current Assets	43.9			41.5
Total Assets		$3,350.9			$3,253.4
Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable		$52.1			$90.5
Accrued Taxes	26.4			30.2
Accrued Interest	15.9			15.6
Long-Term Debt Due Within One Year	37.9			84.5
Other	60.8			62.6
Total Current Liabilities	193.1			283.4
Long-Term Debt	1,064.7			933.6
Deferred Income Taxes	435.5			423.8
Regulatory Liabilities	63.1			60.1
Defined Benefit Pension and Other Postretirement Benefit Plans	216.2			228.2
Other Non-Current Liabilities	129.3			123.3
Total Liabilities	2,101.9			2,052.4
Commitments, Guarantees and Contingencies (Note 14)
Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 40.1 and 39.4 Shares Outstanding	819.3			784.7
Unearned ESOP Shares	(17.2		)	(21.3		)
Accumulated Other Comprehensive Loss	(21.0		)	(22.0		)
Retained Earnings	467.9			459.6
Total Equity	1,249.0			1,201.0
Total Liabilities and Equity		$3,350.9			$3,253.4

The accompanying notes are an integral part of these statements.

ALLETE Second Quarter 2013 Form 10-Q

ALLETE

CONSOLIDATED STATEMENT OF INCOME

Millions Except Per Share Amounts – Unaudited



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Operating Revenue		$235.6			$216.4			$499.4			$456.4
Operating Expenses
Fuel and Purchased Power	78.7			72.1			165.2			149.2
Operating and Maintenance	103.8			96.2			208.5			196.1
Depreciation	28.7			24.8			56.9			49.4
Total Operating Expenses	211.2			193.1			430.6			394.7
Operating Income	24.4			23.3			68.8			61.7
Other Income (Expense)
Interest Expense	(12.8		)	(10.1		)	(25.1		)	(21.1		)
Equity Earnings in ATC	5.0			4.8			10.2			9.4
Other	1.5			1.2			4.2			1.9
Total Other Expense	(6.3		)	(4.1		)	(10.7		)	(9.8		)
Income Before Income Taxes	18.1			19.2			58.1			51.9
Income Tax Expense	4.1			4.8			11.6			13.1
Net Income		$14.0			$14.4			$46.5			$38.8
Average Shares of Common Stock
Basic	39.4			37.3			39.2			37.0
Diluted	39.6			37.4			39.3			37.1
Basic Earnings Per Share of Common Stock		$0.36			$0.39			$1.19			$1.05
Diluted Earnings Per Share of Common Stock		$0.35			$0.39			$1.18			$1.05
Dividends Per Share of Common Stock		$0.475			$0.46			$0.95			$0.92

The accompanying notes are an integral part of these statements.

ALLETE Second Quarter 2013 Form 10-Q

ALLETE

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

Millions – Unaudited



	Quarter Ended					Six Months Ended
	June 30,					June 30,
Comprehensive Income (Loss)	2013		2012			2013		2012
Millions
Net Income		$14.0		$14.4			$46.5		$38.8
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Securities
Net of Income Taxes of $0.1, $(0.5), $0.1 and $0.2	0.1		(0.5		)	0.1		0.5
Unrealized Gain (Loss) on Derivatives
Net of Income Taxes of $0.1, $–, $0.1 and $(0.1)	—		(0.1		)	0.1		(0.2		)
Defined Benefit Pension and Other Postretirement Benefit Plans
Net of Income Taxes of $0.3, $0.4, $0.5 and $0.7	0.5		0.5			0.8		1.0
Total Other Comprehensive Income (Loss)	0.6		(0.1		)	1.0		1.3
Comprehensive Income		$14.6		$14.3			$47.5		$40.1

The accompanying notes are an integral part of these statements.

ALLETE Second Quarter 2013 Form 10-Q

ALLETE

CONSOLIDATED STATEMENT OF CASH FLOWS

Millions – Unaudited



	Six Months Ended
	June 30,
	2013			2012

Operating Activities
Net Income		$46.5			$38.8
Allowance for Funds Used During Construction – Equity	(2.1		)	(1.9		)
Income from Equity Investments, Net of Dividends	(2.3		)	(1.7		)
Gain on Sale of Assets	(0.1		)	—
Gain on Sale of Investments	(0.8		)	—
Depreciation Expense	56.9			49.4
Amortization of Debt Issuance Costs	0.5			0.5
Deferred Income Tax Expense	11.6			13.1
Share-Based Compensation Expense	1.3			1.2
ESOP Compensation Expense	4.0			3.7
Defined Benefit Pension and Postretirement Benefit Expense	11.2			13.8
Bad Debt Expense	0.4			0.5
Changes in Operating Assets and Liabilities
Accounts Receivable	9.9			12.4
Inventories	(1.2		)	(0.2		)
Prepayments and Other	7.4			1.6
Accounts Payable	(10.1		)	(8.2		)
Other Current Liabilities	(5.8		)	—
Cash Contributions to Defined Benefit Pension and Other Postretirement Benefit Plans	(10.8		)	—
Changes in Regulatory and Other Non-Current Assets	(8.0		)	(1.8		)
Changes in Regulatory and Other Non-Current Liabilities	2.6			6.9
Cash from Operating Activities	111.1			128.1
Investing Activities
Proceeds from Sale of Available-for-sale Securities	8.1			1.0
Payments for Purchase of Available-for-sale Securities	(1.4		)	(1.0		)
Investment in ATC	(1.6		)	(2.0		)
Changes to Other Investments	(2.6		)	(3.2		)
Additions to Property, Plant and Equipment	(128.6		)	(221.8		)
Proceeds from Sale of Assets	0.9			—
Cash for Investing Activities	(125.2		)	(227.0		)
Financing Activities
Proceeds from Issuance of Common Stock	33.3			30.5
Proceeds from Issuance of Long-Term Debt	150.0			15.6
Payments for Notes Payable	—			(1.1		)
Payments for Long-Term Debt	(65.5		)	(3.1		)
Debt Issuance Costs	(1.3		)	—
Dividends on Common Stock	(38.2		)	(35.5		)
Cash from Financing Activities	78.3			6.4
Change in Cash and Cash Equivalents	64.2			(92.5		)
Cash and Cash Equivalents at Beginning of Period	80.8			101.1
Cash and Cash Equivalents at End of Period		$145.0			$8.6

The accompanying notes are an integral part of these statements.

ALLETE Second Quarter 2013 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, 2012, 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 June 30, 2013, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2013. For further information, refer to the consolidated financial statements and notes included in our 2012 Form 10-K.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

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



Inventories	June 30, 2013		December 31, 2012
Millions
Fuel		$25.3		$28.0
Materials and Supplies	45.7		41.8
Total Inventories		$71.0		$69.8



Prepayments and Other Current Assets	June 30, 2013		December 31, 2012
Millions
Deferred Fuel Adjustment Clause		$18.3		$22.5
Other	7.9		11.1
Total Prepayments and Other Current Assets		$26.2		$33.6



Other Current Liabilities	June 30, 2013		December 31, 2012
Millions
Customer Deposits		$29.1		$28.8
Other	31.7		33.8
Total Other Current Liabilities		$60.8		$62.6



Other Non-Current Liabilities	June 30, 2013		December 31, 2012
Millions
Asset Retirement Obligation		$81.6		$77.9
Other	47.7		45.4
Total Other Non-Current Liabilities		$129.3		$123.3

ALLETE Second Quarter 2013 Form 10-Q

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flows Information.



For the Six Months Ended June 30,	2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$22.8		$21.7
Cash Paid During the Period for Income Taxes		$0.6		$0.2
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment		$28.2		$14.8
Capitalized Asset Retirement Costs		$1.9		$2.4
AFUDC – Equity		$2.1		$1.9

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

New Accounting Standards.

Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued an accounting standard update on disclosure of amounts reclassified out of accumulated other comprehensive income. This update requires entities to provide information about amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under GAAP that provide additional detail on these amounts. This guidance was adopted beginning with the quarter ended March 31, 2013, and required additional disclosures but did not have an impact on our consolidated financial position, results of operations, or cash flows. (See Note 11. Reclassifications Out of Accumulated Other Comprehensive Income (Loss).)

ALLETE Second Quarter 2013 Form 10-Q

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 regulated 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, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,000 acres of land in Minnesota, and earnings on cash and investments.



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended June 30, 2013
Operating Revenue		$235.6			$215.8			$19.8
Fuel and Purchased Power Expense	78.7			78.7			—
Operating and Maintenance Expense	103.8			82.8			21.0
Depreciation Expense	28.7			27.1			1.6
Operating Income (Loss)	24.4			27.2			(2.8		)
Interest Expense	(12.8		)	(10.4		)	(2.4		)
Equity Earnings in ATC	5.0			5.0			—
Other Income	1.5			1.1			0.4
Income (Loss) Before Income Taxes	18.1			22.9			(4.8		)
Income Tax Expense (Benefit)	4.1			6.6			(2.5		)
Net Income (Loss)		$14.0			$16.3		$(2.3)



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended June 30, 2012
Operating Revenue		$216.4			$197.0			$19.4
Fuel and Purchased Power Expense	72.1			72.1			—
Operating and Maintenance Expense	96.2			76.1			20.1
Depreciation Expense	24.8			23.4			1.4
Operating Income (Loss)	23.3			25.4			(2.1		)
Interest Expense	(10.1		)	(9.9		)	(0.2		)
Equity Earnings in ATC	4.8			4.8			—
Other Income	1.2			1.2			—
Income (Loss) Before Income Taxes	19.2			21.5			(2.3		)
Income Tax Expense (Benefit)	4.8			7.1			(2.3		)
Net Income		$14.4			$14.4		—

ALLETE Second Quarter 2013 Form 10-Q

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Six Months Ended June 30, 2013
Operating Revenue		$499.4			$457.2			$42.2
Fuel and Purchased Power Expense	165.2			165.2			—
Operating and Maintenance Expense	208.5			165.0			43.5
Depreciation Expense	56.9			53.9			3.0
Operating Income (Loss)	68.8			73.1			(4.3		)
Interest Expense	(25.1		)	(21.1		)	(4.0		)
Equity Earnings in ATC	10.2			10.2			—
Other Income	4.2			2.2			2.0
Income (Loss) Before Income Taxes	58.1			64.4			(6.3		)
Income Tax Expense (Benefit)	11.6			16.0			(4.4		)
Net Income (Loss)		$46.5			$48.4		$(1.9)

As of June 30, 2013
Total Assets		$3,350.9			$2,997.0			$353.9
Property, Plant and Equipment – Net		$2,397.2			$2,329.6			$67.6
Accumulated Depreciation		$1,202.8			$1,143.2			$59.6
Capital Additions		$100.2			$97.2			$3.0



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Six Months Ended June 30, 2012
Operating Revenue		$456.4			$415.6			$40.8
Fuel and Purchased Power Expense	149.2			149.2			—
Operating and Maintenance Expense	196.1			154.2			41.9
Depreciation Expense	49.4			46.6			2.8
Operating Income (Loss)	61.7			65.6			(3.9		)
Interest Expense	(21.1		)	(19.5		)	(1.6		)
Equity Earnings in ATC	9.4			9.4			—
Other Income (Expense)	1.9			2.0			(0.1		)
Income (Loss) Before Income Taxes	51.9			57.5			(5.6		)
Income Tax Expense (Benefit)	13.1			18.7			(5.6		)
Net Income		$38.8			$38.8		—

As of June 30, 2012
Total Assets		$2,962.2			$2,755.4			$206.8
Property, Plant and Equipment – Net		$2,177.5			$2,119.9			$57.6
Accumulated Depreciation		$1,124.5			$1,070.1			$54.4
Capital Additions		$235.1			$232.3			$2.8

ALLETE Second Quarter 2013 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 in other postretirement plans to fund employee benefits, the cash equivalents within these plans, and other assets consisting primarily of land in Minnesota.



Other Investments	June 30, 2013		December 31, 2012
Millions
ALLETE Properties		$91.1		$91.1
Available-for-sale Securities (a)	20.4		26.8
Cash Equivalents	24.4		20.7
Other	4.3		4.9
Total Other Investments		$140.2		$143.5


(a)	As of June 30, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $1.2 million, in one year to less than three years was $5.1 million, in three years to less than five years was $1.3 million, and in five or more years was $0.9 million.



ALLETE Properties	June 30, 2013		December 31, 2012
Millions
Land Inventory Beginning Balance		$86.5		$86.0
Deeds to Collateralized Property	—		0.5
Cost of Sales	—		(0.2		)
Capitalized Improvements and Other	0.1		0.2
Land Inventory Ending Balance	86.6		86.5
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4		1.4
Other	3.1		3.2
Total Real Estate Assets		$91.1		$91.1

Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair value. Land values are reviewed for impairment on a quarterly basis and no impairments were recorded for the six months ended June 30, 2013 (none for the year ended December 31, 2012).

Long-Term Finance Receivables. As of June 30, 2013, long-term finance receivables were $1.4 million net of allowance ($1.4 million net of allowance as of December 31, 2012). Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. As of June 30, 2013, we had an allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2012).

ALLETE Second Quarter 2013 Form 10-Q

NOTE 4. DERIVATIVES

During the third quarter of 2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 7 percent of the Company’s outstanding long-term debt as of June 30, 2013. (See Note 8. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting with respect to that derivative. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in the value of the Swap are deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the quarter and six months ended June 30, 2013. The mark-to-market fluctuation on the cash flow hedge was recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. As of June 30, 2013, the fair value of the Swap was a $0.5 million liability (a $0.7 million liability as of December 31, 2012) and is included in other non-current liabilities on the Consolidated Balance Sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.

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 Note 9. Fair Value to the consolidated financial statements in our 2012 Form 10-K.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 5. FAIR VALUE (Continued)

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012. 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 these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the tables below.



	Fair Value as of June 30, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$11.9	—		—		$11.9
Available-for-sale – Corporate Debt Securities	—			$8.5	—	8.5
Cash Equivalents	24.4		—		—	24.4
Total Fair Value of Assets		$36.3		$8.5	—		$44.8

Liabilities:
Deferred Compensation	—			$15.7	—		$15.7
Derivatives – Interest Rate Swap	—		0.5		—	0.5
Total Fair Value of Liabilities	—			$16.2	—		$16.2

Total Net Fair Value of Assets (Liabilities)		$36.3	$(7.7)		—		$28.6



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$18.0	—		—		$18.0
Available-for-sale – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5

Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7

Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

There was no activity in Level 3 during the six months ended June 30, 2013 and 2012.

The Company’s policy is to recognize transfers in and transfers out of a given level as of the actual date of the event or of the change in circumstances that caused the transfer. For the six months ended June 30, 2013 and 2012 , there were no transfers in or out of Levels 1, 2 or 3.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 5. FAIR VALUE (Continued)

Fair Value of Financial Instruments. With the exception of the item listed in the table below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed below was based on quoted market prices for the same or similar instruments (Level 2).



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
June 30, 2013	$1,102.6	$1,160.2
December 31, 2012	$1,018.1	$1,143.7

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 Minnesota Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. In January 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). In February 2012, the Court granted the petition for review and oral arguments were held before the Court in October 2012. A decision is expected in the third quarter of 2013. We cannot predict the outcome at this time.

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. Minnesota Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The cost-based formula methodology also provides for a yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on December 31, 2011, this wholesale customer submitted a cancellation notice with termination effective on December 31, 2013. The 17MW of average monthly demand currently provided to this wholesale customer is expected to be used, upon termination, to supply power for prospective additional retail and municipal load.

2012 Wisconsin Rate Case. SWL&P’s 2013 retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity. The new rates reflect an average overall increase of 2.4 percent for retail customers (a 13.8 percent increase in water rates, a 1.2 percent increase in electric rates, and a 0.2 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $1.7 million in additional revenue.

Transmission Cost Recovery Riders. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. The continued use of the 2009 billing factor was approved by the MPUC in May 2011, which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In June 2011, Minnesota Power filed an updated billing factor that includes additional transmission expenditures, which is expected to be approved in the second half of 2013.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 6. REGULATORY MATTERS (Continued)

Renewable Cost Recovery Riders. The Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity and was completed in various phases through 2012. Customer billing rates for Bison were approved by the MPUC in a November 2011 order and are based on investments and expenditures through that period. Minnesota Power filed a cost recovery petition with the MPUC on May 31, 2013, to update customer billing rates for subsequent investments and expenditures since 2011, which is expected to be approved in the second half of 2013.

Rapids Energy Center. In December 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill (Blandin). Minnesota Power and Blandin entered into a new electric service agreement in September 2012 which is also subject to MPUC approval. We expect a decision from the MPUC on these filings in late 2013.

ALLETE Clean Energy. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. In July 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

Integrated Resource Plan. In May 2011, the MPUC issued its final order approving our 2010 Integrated Resource Plan. As a condition of the final order, a required baseload diversification study evaluating the impact of additional environmental regulations over the next two decades was filed in February 2012. Minnesota Power’s 2013 Integrated Resource Plan, filed on March 1, 2013, details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. A decision by the MPUC on this plan is expected in late 2013.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be between $350 million and $400 million. The MPCA issued its report on March 1, 2013, in support of the Boswell Unit 4 mercury emissions reduction plan stating that the plan is appropriate for accomplishing the objectives of reducing emissions of mercury and other pollutants under the Minnesota Statutes and recommended that the MPUC accept the report’s findings. We expect a decision by the MPUC on the plan in the third quarter of 2013. Upon approval by the MPUC, we anticipate filing a petition to include investments and expenditures in customer billing rates.

The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, the PPACA was signed into law. One of the provisions changed 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 were required to reverse previously recorded tax benefits which resulted in a non-recurring charge to net income of $4.0 million in 2010. In October 2010, we submitted a filing with the MPUC requesting deferral of the retail portion of the tax charge taken in 2010 resulting from the PPACA. In May 2011, the MPUC approved our request for deferral until the next rate case and as a result we recorded an income tax benefit of $2.9 million and a related regulatory asset of $5.0 million in the second quarter of 2011.

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

ALLETE Second Quarter 2013 Form 10-Q

NOTE 6. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	June 30, 2013		December 31, 2012
Millions
Current Regulatory Assets (a)
Deferred Fuel		$18.3		$22.5
Total Current Regulatory Assets	18.3		22.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	251.5		260.7
Income Taxes	34.3		36.0
Asset Retirement Obligation	13.9		12.1
Cost Recovery Riders (b)	29.2		18.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		4.3
Other	3.6		3.7
Total Non-Current Regulatory Assets	337.5		340.3

Total Regulatory Assets		$355.8		$362.8

Non-Current Regulatory Liabilities
Income Taxes		$17.7		$19.5
Plant Removal Obligations	19.3		18.1
Wholesale and Retail Contra AFUDC	16.7		15.5
Conservation Improvement Program	2.7		—
Other	6.7		7.0
Total Non-Current Regulatory Liabilities		$63.1		$60.1


(a)	Current regulatory assets are included in prepayments and other on the Consolidated Balance Sheet.


(b)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to Bison.

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 rates are FERC-approved and are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of June 30, 2013, our equity investment in ATC was $111.2 million ($107.3 million at December 31, 2012). In the first six months of 2013, we invested $1.6 million in ATC, and on July 30, 2013, we invested an additional $0.8 million. We expect to make additional investments of approximately $0.7 million in 2013.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2012		$107.3
Cash Investments	1.6
Equity in ATC Earnings	10.2
Distributed ATC Earnings	(7.9		)
Equity Investment Balance as of June 30, 2013		$111.2

ALLETE Second Quarter 2013 Form 10-Q

NOTE 7. INVESTMENT IN ATC (Continued)

ATC’s summarized financial data for the quarters and six months ended June 30, 2013 and 2012, is as follows:



	Quarter Ended			Six Months Ended
ATC Summarized Financial Data	June 30,			June 30,
Income Statement Data	2013		2012	2013		2012
Millions
Revenue		$152.1	$152.2		$303.9		$299.8
Operating Expense	69.9		71.8	139.7		141.3
Other Expense	20.9		21.1	42.4		41.1
Net Income		$61.3	$59.3		$121.8		$117.4
ALLETE’s Equity in Net Income		$5.0	$4.8		$10.2		$9.4

NOTE 8. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of June 30, 2013, total short-term debt outstanding was $37.9 million ($84.5 million as of December 31, 2012) and consisted of long-term debt due within one year. Short-term debt as of December 31, 2012 included $60.0 million of long-term debt that matured in April 2013.

Long-Term Debt. As of June 30, 2013, total long-term debt outstanding was $1,064.7 million ($933.6 million as of December 31, 2012).

On April 2, 2013, we issued $150.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in three series as follows:



Maturity Date	Principal Amount	Interest Rate
April 15, 2018	$50 Million	1.83%
October 15, 2028	$40 Million	3.30%
October 15, 2043	$60 Million	4.21%

We have the option to prepay all or a portion of the 1.83 percent Bonds at our discretion at any time, subject to a make-whole provision. We have the option to prepay all or a portion of the 3.30 percent Bonds at our discretion at any time prior to April 15, 2028, subject to a make-whole provision, and at any time on or after April 15, 2028, at par, including, in each case, accrued and unpaid interest. We also have the option to prepay all or a portion of the 4.21 percent Bonds at our discretion at any time prior to April 15, 2043, subject to a make-whole provision, and at any time on or after April 15, 2043, at par, including, in each case, accrued and unpaid interest. The Bonds are subject to additional terms and conditions of our utility mortgage. Proceeds from the sale of the Bonds will be used to fund utility capital investments, repay debt, and/or for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to certain institutional accredited investors in a private placement.

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. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of Indebtedness to Total Capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of June 30, 2013, our ratio was approximately 0.47 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from a lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of June 30, 2013, ALLETE was in compliance with its financial covenants.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 9. OTHER INCOME (EXPENSE)



	Quarter Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Millions
AFUDC – Equity		$1.0		$1.2		$2.1		$1.9
Gain on Sale of Available-for-sale Securities	—		—		0.8		—
Investments and Other Income	0.5		—		1.3		—
Total Other Income		$1.5		$1.2		$4.2		$1.9

NOTE 10. INCOME TAX EXPENSE



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Millions
Current Tax Expense (Benefit)
Federal (a)	$(0.2)			—			—			—
State (a)	—			—			—			—
Total Current Tax Expense (Benefit)	(0.2		)	—			—			—
Deferred Tax Expense (Benefit)
Federal	3.6				$4.8			$8.2			$13.2
State (b)	0.9			0.2			3.8			0.3
Investment Tax Credit Amortization	(0.2		)	(0.2		)	(0.4		)	(0.4		)
Total Deferred Tax Expense	4.3			4.8			11.6			13.1
Total Income Tax Expense		$4.1			$4.8			$11.6			$13.1


(a)	We incurred net operating losses (NOLs) due to the bonus depreciation provisions of the American Taxpayer Relief Act of 2012 and the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010 for the quarter and six months ended June 30, 2013 and 2012. The 2013 and 2012 federal and state NOLs will be carried forward to offset future taxable income.


(b)	The quarter and six months ended June 30, 2012, reflected increased state tax benefit from state renewable tax credits compared to the quarter and six months ended June 30, 2013.

For the six months ended June 30, 2013, the effective tax rate was 20.0 percent (25.2 percent for the six months ended June 30, 2012). The decrease from the effective tax rate for the six months ended June 30, 2012, was primarily due to increased federal production tax credits. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC ‑ Equity, investment tax credits, federal production tax credits, state income tax credits and depletion.

Uncertain Tax Positions. As of June 30, 2013, we had gross unrecognized tax benefits of $2.6 million ($2.7 million as of December 31, 2012). Of the total gross unrecognized tax benefits, $0.7 million represents the amount of unrecognized tax benefits included in the Consolidated Balance Sheet that, if recognized, would favorably impact the effective income tax rate.

ALLETE’s IRS exam for tax years 2005 through 2009 is currently under review at the IRS appeals office. We expect the IRS appeals process to be completed during the next twelve months, resulting in the reversal of substantially all of the unrecognized tax benefits as of June 30, 2013. The unrecognized tax benefits are primarily due to tax positions which are timing in nature and therefore would have an immaterial impact on our effective tax rate if recognized.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 11. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in Accumulated Other Comprehensive Loss by Component



	Unrealized Gains and Losses on Available-for-sale Securities (a)		Defined Benefit Pension, Other Postretirement Items (a)		Gains and Losses on Cash Flow Hedge (a)	Total (a)
Millions
For the Quarter Ended June 30, 2013
Beginning Balance	$(0.1)		$(21.2)		$(0.3)	$(21.6)
Other Comprehensive Income (Loss) Before Reclassifications	0.1		(2.6	)	—	(2.5	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	—		3.1		—	3.1
Net Other Comprehensive Income	0.1		0.5		—	0.6
Ending Balance	—		$(20.7)		$(0.3)	$(21.0)

For the Six Months Ended June 30, 2013
Beginning Balance	$(0.1)		$(21.5)		$(0.4)	$(22.0)
Other Comprehensive Income (Loss) Before Reclassifications	0.6		(5.5	)	0.1	(4.8	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.5	)	6.3		—	5.8
Net Other Comprehensive Income	0.1		0.8		0.1	1.0
Ending Balance	—		$(20.7)		$(0.3)	$(21.0)


(a)	Amounts shown are net of tax.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 11. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)

Reclassifications Out of Accumulated Other Comprehensive Loss



Details About Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Loss (a)			Affected Income Statement Line Item
Millions
For the Quarter Ended June 30, 2013
Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs		$0.7		(b)
Actuarial Gains and Losses	(5.8		)	(b)
	(5.1		)
	2.0			Income Tax Expense
	$(3.1)
Total Reclassifications	$(3.1)

For the Six Months Ended June 30, 2013
Unrealized Gains on Available-for-sale Securities		$0.8		Other Income (Expense) - Other
	(0.3		)	Income Tax Expense
		$0.5

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs		$1.2		(b)
Actuarial Gains and Losses	(11.5		)	(b)
	(10.3		)
	4.0			Income Tax Expense
	$(6.3)
Total Reclassifications	$(5.8)


(a)	Amounts in parentheses indicate charges to net income.


(b)	These components of accumulated other comprehensive loss are included in the computation of net pension and other postretirement benefit expense. (See Note 13. Pension and Other Postretirement Benefit Plans.)

ALLETE Second Quarter 2013 Form 10-Q

NOTE 12. EARNINGS PER SHARE AND COMMON STOCK

The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units, and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the quarters and six months ended June 30, 2013 and 2012, zero and 0.3 million options to purchase shares of common stock, respectively, were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive.



			2013					2012
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 June 30,
Net Income		$14.0			$14.0		$14.4			$14.4
Average Common Shares	39.4		0.2	39.6		37.3		0.1	37.4
Earnings Per Share		$0.36			$0.35		$0.39			$0.39
For the Six Months Ended June 30,
Net Income		$46.5			$46.5		$38.8			$38.8
Average Common Shares	39.2		0.1	39.3		37.0		0.1	37.1
Earnings Per Share		$1.19			$1.18		$1.05			$1.05

NOTE 13. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense	2013			2012			2013			2012
Millions
For the Quarter Ended June 30,
Service Cost		$2.5			$2.3			$1.0			$1.1
Interest Cost	6.5			6.6			1.7			2.3
Expected Return on Plan Assets	(8.8		)	(8.9		)	(2.4		)	(2.5		)
Amortization of Prior Service Costs	—			0.1			(0.7		)	(0.5		)
Amortization of Net Loss	5.4			4.4			0.4			1.9
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$5.6			$4.5		—				$2.4

For the Six Months Ended June 30,
Service Cost		$5.0			$4.6			$2.0			$2.1
Interest Cost	13.0			13.2			3.4			4.7
Expected Return on Plan Assets	(17.6		)	(17.7		)	(4.9		)	(5.0		)
Amortization of Prior Service Costs	0.1			0.2			(1.3		)	(0.9		)
Amortization of Net Loss	10.7			8.7			0.8			3.8
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$11.2			$9.0		—				$4.8

Employer Contributions. For the six months ended June 30, 2013, no contributions were made to our defined benefit pension plan (none for the six months ended June 30, 2012). For the six months ended June 30, 2013, we contributed $10.8 million to our other postretirement benefit plan (none for the six months ended June 30, 2012). We do not expect to contribute to our defined benefit pension plan in 2013, and we do not expect to make any additional contributions to our other postretirement benefit plan in 2013.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

Square Butte PPA. Minnesota Power has a PPA 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 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, subject to the provisions of the Minnkota Power sales agreement described below. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of June 30, 2013, Square Butte had total debt outstanding of $404.9 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the years 2013 through 2017, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during the six months ended June 30, 2013 was $33.0 million ($33.0 million for the six months ended June 30, 2012). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $5.3 million during the six months ended June 30, 2013 ($5.6 million for the six months ended June 30, 2012). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power. Under the power sales agreement, Minnesota Power will sell a portion of its output from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025.

No power will be sold under the 2009 agreement until Minnkota Power has placed in service a new AC transmission line, which is expected to occur by the end of the first quarter of 2014. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, which in turn will enable Minnesota Power to transmit additional wind generation on the existing DC transmission line.

Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity over the term June 1, 2016 through May 31, 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

Oliver Wind I and II PPAs. In 2006 and 2007, Minnesota Power entered into two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW)—wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges and we only pay for energy as it is delivered to us.

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in April 2015. Under this agreement 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.

Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and is subject to construction of additional transmission capacity between Manitoba and Minnesota’s Iron Range, along with construction of new hydroelectric generating capacity in Manitoba. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for changes in a governmental inflationary index, a natural gas index, and market prices.

In February 2012, Minnesota Power and Manitoba Hydro proposed construction of the Great Northern Transmission Line, a 500 kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy, which is targeted to be in service in 2020. Total project cost and cost allocations are still to be determined; however, at this time we expect our capital expenditures to range between $200 million and $400 million. The Great Northern Transmission Line is subject to various federal and state regulatory approvals. In addition, Manitoba Hydro must obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through 2014. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements is $22.4 million for the remainder of 2013 and $1.0 million for 2014. Our minimum annual payment obligation 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.

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 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 also 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 $11.5 million in 2013, $11.7 million in 2014, $11.4 million in 2015, $9.3 million in 2016, $8.5 million in 2017 and $35.0 million thereafter.

Transmission. We continue to make investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. This includes the CapX2020 initiative, investments in our own transmission assets, investments in other regional transmission assets (individually or in combination with others), and our investment in ATC.

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 consists of electric cooperatives, municipal and investor-owned utilities, including Minnesota’s largest transmission owners, 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 is participating in three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. The 28-mile 345 kV line between Monticello and St. Cloud was placed into service in December 2011 and the 70-mile 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process was completed in August 2012. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between $100 million and $110 million in the CapX2020 initiative through 2015. A total of $59.8 million was spent through June 30, 2013, of which $48.9 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($48.2 million as of December 31, 2012 of which $37.3 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration by both Congress and the EPA. Minnesota Power’s fossil fuel facilities will likely be subject to regulation under these proposals. Our intention is to reduce our exposure to these requirements by reshaping our generation portfolio over time to reduce our reliance on coal.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to expected future restrictive environmental requirements imposed through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible ranges of future environmental regulations to project power supply trends and impacts on customers.

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. Accruals are adjusted 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.

Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses and low NO_X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 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. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits. Resolution of the NOVs could result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to estimate the expenditures, or range of expenditures that may be required upon resolution. Any costs of installing additional pollution control equipment would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, which replaced the EPA’s 2005 CAIR. However, in August 2012, a three-judge panel of the District of Columbia Circuit Court of Appeals vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. On March 29, 2013, the EPA petitioned the Supreme Court to review the District of Columbia Circuit Court of Appeals ruling. The Supreme Court decided to grant review on June 24, 2013, and is likely to issue its decision by June 2014. If reinstated after Supreme Court review, the CSAPR would require states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR would not directly require the installation of controls. Instead, the rule would require facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would be allocated to facilities from each state’s annual budget and could be bought and sold.

The CAIR regulations similarly require certain states to improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CAIR also created an allowance allocation and trading program rather than specifying pollution controls. Minnesota participation in the CAIR was stayed by EPA administrative action while the EPA completed a review of air quality modeling issues in conjunction with the development of a final replacement rule. While the CAIR remains in effect, Minnesota participation in the CAIR will continue to be stayed. It remains uncertain if emission restrictions similar to those contained in the CSAPR will become effective for Minnesota utilities due to the August 2012 District of Columbia Circuit Court of Appeals decision.

Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Based on our expected generation, these emission reductions would have satisfied Minnesota Power’s SO₂ and NO_X emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2013. We are unable to predict any additional compliance costs we might incur if the CSAPR is reinstated or if a CSAPR replacement rule is promulgated.

Regional Haze. The federal Regional Haze Rule requires states to submit SIPs to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the first phase of the Regional Haze Rule, certain large stationary sources, 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 two steam units, Boswell Unit 3 and Taconite Harbor Unit 3, subject to BART requirements.

The MPCA requested that companies with BART-eligible units complete and submit a BART emissions control retrofit study, which was completed for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirements for that unit. In December 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA.

In December 2011, the EPA published in the Federal Register a proposal to approve a trading program in the CSAPR as an alternative to determining BART. However, as a result of the August 2012 District of Columbia Circuit Court of Appeals decision to vacate the CSAPR (See Cross-State Air Pollution Rule), Minnesota Power is now evaluating whether significant additional expenditures at Taconite Harbor Unit 3 will be required to comply with BART requirements under the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation date to bring Taconite Harbor Unit 3 into compliance with the Regional Haze Rule requirements. It is uncertain what controls would ultimately be required at Taconite Harbor Unit 3 under this scenario. On January 30, 2013, Minnesota Power announced its “EnergyForward” strategic plan, which includes retiring Taconite Harbor Unit 3 in 2015, subject to MPUC approval.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015, to position the Company for MATS compliance.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2011, a final rule was published in the Federal Register for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT). The rule was stayed by the EPA in May 2011, to allow the EPA time to consider additional comments received. The EPA re-proposed the rule in December 2011. In January 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released in December 2012. Major existing sources have until January 31, 2016 to achieve compliance with the final rule. Minnesota Power is in the process of assessing the impact of this rule on our affected units, Hibbard Renewable Energy Center and Rapids Energy Center. Costs for complying with the final rule cannot be estimated at this time.

Minnesota Mercury Emissions Reduction Act. Under the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls to address both the Minnesota mercury emissions reduction requirements and the MATS rule, which also regulates mercury emissions. Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016, was approved by the MPCA. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule discussed above.

Proposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA was scheduled to decide upon the 2008 eight-hour ozone standard in July 2011, but has since announced that it is deferring revision of this standard until 2014 or later.

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM_2.5) standard; the annual PM_2.5 standard and the 24-hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM_2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM_2.5 standards in June 2012.

In December 2012, the EPA issued a final rule implementing a more stringent annual PM_2.5 standard, while retaining the current 24-hour PM_2.5standard. To implement the new more stringent annual PM_2.5standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects and permits must comply with the new more stringent standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. States are expected to propose attainment designations by December 2013, based on already available monitoring data. The EPA believes that most U.S. counties currently already meet the new standard and plans to finalize designations of attainment by December 2014. For those counties that the EPA does not designate as having already met the requirements of the new standard, specific dates for required attainment will depend on technology availability, state permitting goals, potential legal challenges and other factors.

SO₂ and NO₂ NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO₂ and NO₂. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO₂ NAAQS also require the EPA to evaluate modeling data to determine attainment. The EPA notified states that their SIPs for attainment of the standard were required to be submitted to the EPA for approval by June 2013, but the evaluation of modeling data will not be required until 2017.

In late 2011, the MPCA initiated modeling activities that included approximately 65 sources within Minnesota that emit greater than 100 tons of SO₂ per year. However, in April 2012, the MPCA notified Minnesota Power that such modeling had been suspended as a result of the EPA’s announcement that the June 2013 SIP submittals would no longer require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The MPCA is awaiting updated EPA guidance and will communicate with affected sources once the MPCA has more information on how the state will meet the EPA’s SIP requirements. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.

Climate Change. The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:


•	Expanding our renewable energy supply;


•	Providing energy conservation initiatives for our customers and engaging in other demand side efforts;


•	Supporting research of technologies to reduce carbon emissions from generation facilities and carbon sequestration efforts; and


•	Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas generating facilities.

President Obama’s Climate Action Plan. On June 25, 2013, President Obama announced a Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions, as further described below.

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and other facilities characterized as major sources under the Clean Air Act’s Title V program. For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHG requirements. However, GHG requirements are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

In late 2010, the EPA issued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the project-specific, top-down Best Available Control Technology (BACT) determination process used for other pollutants will also be used to determine BACT for GHG emissions. Through sector-specific white papers, the EPA also provided examples and technical summaries of GHG emission control technologies and techniques the EPA considers available or likely to be available to sources. It is possible that these control technologies could be determined to be BACT on a project-by-project basis.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In March 2012, the EPA announced a proposed rule to apply CO₂ emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The proposed NSPS apply only to new or re-powered units and were open for public comment through June 25, 2012. Based on the volume of comments received, the EPA announced its intent to re-propose the rule. The CAP described above directs the EPA to re-propose the rule by September 20, 2013. The CAP also directs the EPA to propose NSPS or regulatory guidelines for existing fossil fuel-fired electric generating units by June 1, 2014, and to finalize such rules by June 1, 2015. Under the CAP, the EPA will issue regulatory guidelines and objectives to the states, which in turn will submit SIPs for EPA approval that demonstrate how the state will meet or surpass achievement of the EPA targeted objectives. The CAP directs the EPA to require states to submit such SIPs by June 30, 2016.

Minnesota has already initiated several measures consistent with those called for under the CAP. Minnesota Power has also announced its “EnergyForward” strategy that provides for significant emission reductions and diversifying our electricity generation mix to include more renewable and natural gas energy.

Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. In June 2012, the United States District Court for the District of Columbia upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. Comments on the permitting guidance were submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Water. The Clean Water Act requires NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations.

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011, and the EPA is now expected to issue a final rule in November 2013. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Steam Electric Power Generating Effluent Guidelines. On April 19, 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. Instead of proposing a single rule, the EPA proposed eight “options,” of which four are “preferred”. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register on June 7, 2013, with public comments due September 20, 2013. It is expected that the EPA will issue a final rule in 2014. Compliance with the final rule would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA.

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its coal-fired electric generating facilities. 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. In June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash. It is expected that the final rule will be published in 2014. We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Other Matters

BNI Coal. As of June 30, 2013, BNI Coal had surety bonds outstanding of $29.7 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, additional assurance 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 $2.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $32.3 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of June 30, 2013, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. 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 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 June 30, 2013, we owned 73 percent of the assessable land in the Town Center District (73 percent at December 31, 2012) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2012). At these ownership levels, our annual assessments are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

United Taconite Lawsuit. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20.0 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of June 30, 2013, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance limits for any potential loss. Our insurance carrier is providing a defense subject to a reservation of rights as to certain claims.

ALLETE Second Quarter 2013 Form 10-Q

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of June 30, 2013, because a potential loss is not currently probable or reasonably estimable.

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, and 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 our results of operations 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

OVERVIEW

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 2012 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 “Forward-Looking Statements” located on page 5 and “Risk Factors” located in Part I, Item 1A, beginning on page 27 of our 2012 Form 10‑K. The risks and uncertainties described in this Form 10-Q and our 2012 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 risks set forth are realized.

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 approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 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, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,000 acres of land 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 June 30, 2013, 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.

ALLETE Second Quarter 2013 Form 10-Q

OVERVIEW (Continued)

Financial Overview

The following net income discussion summarizes a comparison of the six months ended June 30, 2013, to the six months ended June 30, 2012.

Net income for the six months ended June 30, 2013, was $46.5 million, or $1.18 per diluted share, compared to $38.8 million, or $1.05 per diluted share, for the same period of 2012. Net income for 2013 reflected higher kilowatt-hour sales, cost recovery rider revenue and federal production tax credits, and higher FERC wholesale rates. These increases were partially offset by increased operating and maintenance, depreciation and interest expenses. Earnings per share dilution was $0.07 as a result of additional shares of common stock outstanding as of June 30, 2013.

Regulated Operations net income was $48.4 million for the six months ended June 30, 2013, compared to $38.8 million for the same period of 2012. Net income for 2013 reflected higher kilowatt-hour sales, cost recovery rider revenue and federal production tax credits, and FERC wholesale rates. These increases were partially offset by increased operating and maintenance, depreciation, and interest expenses.

Investments and Other net loss was $1.9 million for the six months ended June 30, 2013, compared to no net income for the same period of 2012. The decrease in 2013 was primarily due to higher interest and state income tax expense, partially offset by a gain on sale of available-for-sale securities.

COMPARISON OF THE QUARTERS ENDED JUNE 30, 2013 AND 2012

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

Regulated Operations

Operating revenue increased $18.8 million, or 10 percent, from 2012 primarily due to higher fuel adjustment clause recoveries, a 2.2 percent increase in kilowatt-hour sales, and higher municipal rates, gas sales, transmission revenue, and cost recovery rider revenue.

Fuel adjustment clause recoveries increased $5.2 million from 2012 due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.)

Revenue from Regulated Operations increased $4.2 million from 2012 due to a 2.2 percent increase in total kilowatt-hour sales. Kilowatt-hour sales to Other Power Suppliers increased 24.0 percent from 2012. 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. The increase in kilowatt-hour sales was also due to higher sales to residential and commercial customers. In April 2012, heating degree days in Duluth, Minnesota were approximately 35 percent lower than the same period in 2013. Kilowatt-hour sales to industrial customers decreased 4.0 percent from 2012 primarily due to 65.5 million kilowatt-hours sold in the second quarter of 2012 through a short-term, fixed price contract.

Revenue from our municipal customers increased $3.1 million from 2012 due to higher rates under the cost-based formula primarily due to higher capital expenditures and due to period-over-period fluctuations in the true-up for actual costs provisions of the contracts. The rates included in these contracts are calculated using a cost-based formula methodology that is set at July 1 each year using estimated costs and a true-up for actual costs the following year.

ALLETE Second Quarter 2013 Form 10-Q

COMPARISON OF THE QUARTERS ENDED JUNE 30, 2013 AND 2012 (Continued)

Regulated Operations (Continued)



Kilowatt-hours Sold			Quantity		%
Quarter Ended June 30,	2013	2012	Variance		Variance
Millions
Regulated Utility
Retail and Municipals
Residential	251	226	25		11.1	%
Commercial	335	326	9		2.8	%
Industrial	1,769	1,842	(73	)	(4.0	)%
Municipals	225	234	(9	)	(3.8	)%
Total Retail and Municipals	2,580	2,628	(48	)	(1.8	)%
Other Power Suppliers	610	492	118		24.0	%
Total Regulated Utility Kilowatt-hours Sold	3,190	3,120	70		2.2	%

Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2013 (28 percent in 2012). Revenue from electric sales to paper and pulp mills accounted for 8 percent of consolidated operating revenue in 2013 (9 percent in 2012). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2013 (7 percent in 2012).

Revenue from gas sales at SWL&P increased $2.4 million from 2012 due to unseasonably warm weather in April 2012 and higher purchased gas expenses. (See Operating Expenses - Operating and Maintenance Expense).

Transmission revenue increased $2.2 million from 2012 primarily due to the commencement of recovery of our transmission investment related to the 230 kV transmission system upgrade that was placed into service in March 2013 (see Outlook – Industrial Customers – City of Nashwauk) and higher MISO Regional Expansion Criteria and Benefits (RECB) revenue related to our investment in CapX2020.

Cost recovery rider revenue increased $1.1 million from 2012 as our Bison Wind Energy Center was completed in various phases through December 2012 and in service in 2013.

Operating expenses increased $17.0 million, or 10 percent, from 2012.

Fuel and Purchased Power Expense increased $6.6 million, or 9 percent, from 2012 due to an increase in kilowatt-hour sales and higher purchased power prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue.)

Operating and Maintenance Expense increased $6.7 million, or 9 percent, from 2012 primarily due to higher purchased gas expenses, higher operating and maintenance expenses related to our Bison Wind Energy Center, which was in service in 2013, and higher property tax expenses. Purchased gas expenses increased due to higher gas sales in 2013 as a result of the unseasonably warm weather in April 2012 and higher cost of gas in 2013; purchased gas costs are recovered through a purchased gas adjustment clause from customers (see Operating Revenue). Property tax expenses increased primarily due to higher taxable plant and rates.

Depreciation Expense increased $3.7 million, or 16 percent, from 2012 reflecting additional property, plant and equipment in service.

Interest expense increased $0.5 million, or 5 percent, from 2012 primarily due to higher average long-term debt balances.

Income tax expense decreased $0.5 million, or 7 percent, from 2012, primarily due to higher federal production tax credits in 2013 as our Bison Wind Energy Center was completed in various phases through December 2012 and in service in 2013.

ALLETE Second Quarter 2013 Form 10-Q

COMPARISON OF THE QUARTERS ENDED JUNE 30, 2013 AND 2012 (Continued)

Investments and Other

Operating revenue increased $0.4 million, or 2 percent, from 2012 primarily due to a $0.6 million increase in revenue at BNI Coal. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher revenue as a result of higher expenses in 2013. (See Operating Expense.)

Operating expenses increased $1.1 million, or 5 percent, from 2012 reflecting higher expenses at BNI Coal of $0.7 million primarily due to higher fuel costs and labor, which are recovered through the cost-plus contract. (See Operating Revenue.)

Interest expense increased $2.2 million from 2012 primarily due to a decrease in the proportion of ALLETE interest expense allocated to Minnesota Power. We record interest expense for Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the balance to Investments and Other.

Income tax benefits increased $0.2 million from 2012 primarily due to increased pretax losses offset by higher state tax expense. State income tax expense was higher in 2013 as more North Dakota income tax credits attributable to our North Dakota capital investments were recognized in 2012.

Income Taxes – Consolidated

For the quarter ended June 30, 2013, the effective tax rate was 22.7 percent (25.0 percent for the quarter ended June 30, 2012). The decrease from the effective tax rate for the quarter ended June 30, 2012, was primarily due to increased federal production tax credits in 2013. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, federal production tax credits, state income tax credits and depletion. (See Note 10. Income Tax Expense.)

COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2013 AND 2012

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

Regulated Operations

Operating revenue increased $41.6 million, or 10 percent, from 2012 primarily due to higher fuel adjustment clause recoveries, a 2.7 percent increase in kilowatt-hour sales, and higher municipal rates, cost recovery rider revenue, gas sales, and transmission revenue.

Fuel adjustment clause recoveries increased $12.3 million from 2012 due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.)

Revenue from Regulated Operations increased $9.6 million from 2012 due to a 2.7 percent increase in total kilowatt-hour sales. The increase was due primarily to a 19.0 percent increase in kilowatt-hour sales to Other Power Suppliers. 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. Also contributing to the increase was higher sales to residential and commercial customers. In the first four months of 2012, heating degree days in Duluth, Minnesota were approximately 29 percent lower than the same period in 2013. Kilowatt-hour sales to industrial customers decreased 2.6 percent from 2012 primarily due to 65.5 million kilowatt-hours sold in the second quarter of 2012 through a short-term, fixed price contract.

Revenue from our municipal customers increased $4.9 million from 2012 due to higher rates under the cost-based formula primarily due to higher capital expenditures and due to period-over-period fluctuations in the true-up for actual costs provisions of the contracts. The rates included in these contracts are calculated using a cost-based formula methodology that is set at July 1 each year using estimated costs and a true-up for actual costs the following year.

ALLETE Second Quarter 2013 Form 10-Q

COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2013 AND 2012 (Continued)

Regulated Operations (Continued)



Kilowatt-hours Sold			Quantity		%
Six Months Ended June 30,	2013	2012	Variance		Variance
Millions
Regulated Utility
Retail and Municipals
Residential	605	552	53		9.6	%
Commercial	712	690	22		3.2	%
Industrial	3,614	3,710	(96	)	(2.6	)%
Municipals	499	498	1		0.2	%
Total Retail and Municipals	5,430	5,450	(20	)	(0.4	)%
Other Power Suppliers	1,201	1,009	192		19.0	%
Total Regulated Utility Kilowatt-hours Sold	6,631	6,459	172		2.7	%

Revenue from electric sales to taconite customers accounted for 25 percent of consolidated operating revenue in 2013 (27 percent in 2012). Revenue from electric sales to paper and pulp mills accounted for 8 percent of consolidated operating revenue in 2013 (9 percent in 2012). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2013 (7 percent in 2012).

Cost recovery rider revenue increased $6.0 million from 2012 as our Bison Wind Energy Center was completed in various phases through December 2012 and in service in 2013. Also contributing to the increase were higher capital expenditures related to our CapX2020 projects.

Revenue from gas sales at SWL&P increased $4.3 million from 2012 as a result of the unseasonably warm weather during the first four months of 2012 and higher purchased gas expenses. (See Operating Expenses - Operating and Maintenance Expense.)

Transmission revenue increased $3.1 million from 2012 primarily due to the commencement of recovery of our transmission investment related to the 230 kV transmission system upgrade that was placed into service in March 2013 (see Outlook – Industrial Customers – City of Nashwauk) and higher MISO RECB revenue related to our investment in CapX2020.

Operating expenses increased $34.1 million, or 10 percent, from 2012.

Fuel and Purchased Power Expense increased $16.0 million, or 11 percent, from 2012 due to an increase in kilowatt-hour sales and higher purchased power prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue.)

Operating and Maintenance Expense increased $10.8 million, or 7 percent, from 2012 primarily due to higher purchased gas expenses, higher operating and maintenance expenses related to our Bison Wind Energy Center, which was in service in 2013, and higher property tax expenses. Purchased gas expenses increased due to higher gas sales in 2013 as a result of the unseasonably warm weather during the first four months of 2012 and higher cost of gas in 2013; purchased gas costs are recovered through a purchased gas adjustment clause from customers (see Operating Revenue). Property tax expenses increased primarily due to higher taxable plant and rates.

Depreciation Expense increased $7.3 million, or 16 percent, from 2012 reflecting additional property, plant and equipment in service.

Interest expense increased $1.6 million, or 8 percent, from 2012 primarily due to higher average long-term debt balances.

Income tax expense decreased $2.7 million, or 14 percent, from 2012, primarily due to higher federal production tax credits in 2013 as our Bison Wind Energy Center was completed in various phases through December 2012 and in service in 2013.

ALLETE Second Quarter 2013 Form 10-Q

COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2013 AND 2012 (Continued)

Investments and Other

Operating revenue increased $1.4 million, or 3 percent, from 2012 primarily due to a $1.5 million increase in revenue at BNI Coal. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher revenue as a result of higher expenses in 2013. (See Operating Expense.)



ALLETE Properties	2013			2012
Revenue and Sales Activity	Acres (a)	Amount		Acres (a)	Amount
Dollars in Millions
Revenue from Land Sales	19		$0.1	—	—
Other Revenue		0.3				$0.3
Total ALLETE Properties Revenue			$0.4			$0.3

(a) Acreage amounts are shown on a gross basis, including wetlands.

Operating expenses increased $1.8 million, or 4 percent, from 2012 reflecting higher expenses at BNI Coal of $1.7 million primarily due to higher labor and fuel costs, which are recovered through the cost-plus contract. (See Operating Revenue.)

Interest expense increased $2.4 million from 2012 primarily due to a decrease in the proportion of ALLETE interest expense allocated to Minnesota Power. We record interest expense for Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the balance to Investments and Other.

Other income increased $2.1 million from 2012 primarily due to a gain on sale of available-for-sale securities.

Income tax benefits decreased $1.2 million from 2012 primarily due to higher state tax expense. State income tax expense was higher in 2013 as more North Dakota income tax credits attributable to our North Dakota capital investments were recognized in 2012.

Income Taxes – Consolidated

For the six months ended June 30, 2013, the effective tax rate was 20.0 percent (25.2 percent for the six months ended June 30, 2012). The decrease from the effective tax rate for the six months ended June 30, 2012, was primarily due to increased federal production tax credits in 2013. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, federal production tax credits, state income tax credits and depletion. (See Note 10. Income Tax Expense.)

CRITICAL ACCOUNTING POLICIES

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, pension and postretirement health and life actuarial assumptions, impairment of long-lived assets 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 2012 Form 10-K.

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK

For additional information see our 2012 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. The Company has a key long-term objective of achieving minimum average earnings per share growth of 5 percent per year (using 2010 as a base year) and maintaining a competitive dividend payout. To accomplish this, Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with legislators and regulators to earn a fair rate of return. In addition, ALLETE expects to pursue new energy-centric initiatives that provide long-term earnings growth potential, while at the same time reduce our exposure to industrial electricity sales. The new energy-centric pursuits will be in renewable energy, transmission and other energy-related infrastructure or infrastructure services.

We believe that, over the long-term, less carbon intensive and more sustainable energy sources will play an increasingly important role in our nation’s energy mix. Minnesota Power has developed renewable resources which will be used to meet regulated renewable supply requirements and is considering additional investments. In addition, in June 2011, we established ALLETE Clean Energy, a wholly-owned subsidiary of ALLETE. ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements, and will be subject to applicable state and federal regulatory approvals. For wind development, we intend to capitalize on our existing presence in North Dakota through BNI Coal, our DC transmission line and our Bison Wind Energy Center. We have a long-term business presence and established landowner relationships in North Dakota.

We plan to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. This includes the Great Northern Transmission Line and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. Transmission investments could be made by Minnesota Power or a subsidiary of ALLETE. (See Regulated Operations – Transmission.)

North American energy trends continue to evolve, and may be impacted by emerging technological, environmental, and demand changes. We believe this may create opportunity, and we are exploring investing in other energy-centric businesses related to energy infrastructure and infrastructure services. Our investment criteria focuses on investments with recurring or contractual revenues, differentiated offerings and reasonable barriers to entry. In addition, investments would typically support ALLETE’s investment grade credit metrics and dividend policy.

Regulated Operations. Minnesota Power’s long-term strategy is to be the leading electric energy provider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable requirements. Keeping the cost of energy production 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. We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with legislators and regulators to earn a fair rate of return. We project that our Regulated Operations will not earn its allowed rate of return in 2013.

Minnesota Public Utilities Commission. The MPUC has regulatory authority over Minnesota Power’s service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters.

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK (Continued)

Regulated Operations (Continued)

Interim Rate Appeal. In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. In January 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). In February 2012, the Court granted the petition for review and oral arguments were held before the Court in October 2012. A decision is expected in the third quarter of 2013. We cannot predict the outcome at this time.

Federal Energy Regulatory Commission. 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. Minnesota Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The cost-based formula methodology also provides for a yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on December 31, 2011, this wholesale customer submitted a cancellation notice with termination effective on December 31, 2013. The 17 MW of average monthly demand currently provided to this wholesale customer is expected to be used, upon termination, to supply power for prospective additional retail and municipal load.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and wood products, and pipeline industries. Approximately 54 percent of our Regulated Utility kilowatt-hour sales in the six months ended June 30, 2013 (57 percent in the six months ended June 30, 2012) were made to our industrial customers in these industries.

Minnesota Power provides electric service to five taconite customers capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five percent of Minnesota taconite production is exported outside of North America.

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The World Steel Association, an association of approximately 170 steel producers, national and regional steel industry associations, and steel research institutes representing around 85 percent of world steel production, projected U.S. steel consumption in 2013 will be similar to 2012. The American Iron and Steel Institute (AISI), an association of North American steel producers, reported that U.S. raw steel production operated at approximately 77 percent of capacity during the first six months of 2013, compared to 78 percent in 2012. Based on this information, 2013 taconite production levels in Minnesota are expected to be similar to 2012.

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK (Continued)

Regulated Operations (Continued)

Prospective Additional Load. Minnesota Power is pursuing new wholesale and retail loads in and around its service territory. Currently, several companies in northeastern Minnesota continue to progress in the development of natural resource based projects that represent long-term growth potential and load diversity for Minnesota Power. These projects are in the ferrous and non-ferrous mining and steel industries and include PolyMet, Mesabi Nugget Delaware, LLC, USS Corporation’s Keewatin taconite expansion, Magnetation, Inc. and additional Essar Steel Minnesota LLC (Essar) load growth (see City of Nashwauk). We cannot predict the outcome of these projects, but if these projects are constructed, Minnesota Power could serve up to approximately 600 MW of new retail or wholesale load.

City of Nashwauk. In May 2012, the Company entered into a new formula-based wholesale electric sales agreement with the City of Nashwauk, Minnesota for all of the City’s electric service requirements, effective April 1, 2013 through June 30, 2024. A new Essar taconite facility is currently under construction in the City of Nashwauk. This facility will result in up to approximately 110 MW of additional load for Minnesota Power. Under the terms of a facilities construction agreement, Minnesota Power constructed a 230 kV transmission system upgrade to serve the Essar load which was placed into service in March 2013, with a total cost of approximately $35 million. This upgrade will allow the City of Nashwauk to provide electric service for Essar’s new taconite facility. Billings to Essar to recover our transmission investments began in April 2013. Currently, Essar expects to begin blasting, mining and commissioning equipment in 2014. These activities will require an insignificant amount of electric power and as a result, we expect minimal impact from electric sales on our results of operations through 2014. Essar is expected to begin increasing its electric power requirements as it ramps up production in late 2014, into 2015 and beyond. Expansions for additional pellet production, production of direct reduced iron and production of steel slabs are also being considered by Essar for future years. In addition, on February 11, 2013, Essar announced a ten-year iron ore pellet off-take agreement with ArcelorMittal. Under the terms of the agreement, Essar will supply approximately 3 million to 4 million metric tons of pellets annually to ArcelorMittal through 2024.

EnergyForward. On January 30, 2013, Minnesota Power announced “EnergyForward”, a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes completed and planned investments in wind and hydroelectric power, the addition of natural gas as a generation fuel source, and the installation of emissions control technology. Significant elements of the “EnergyForward” plan include:


•	Major wind investments in North Dakota. Including the 210 MW of wind generation commissioned in December 2012, our Bison Wind Energy Center has 292 MW of nameplate capacity (see Renewable Energy).


•	Planned installation of approximately $350 to $400 million in emissions control technology at our Boswell Unit 4 to further reduce emissions of SO₂, particulates and mercury (see Boswell Mercury Emission Reduction Plan).


•	Planning for the proposed Great Northern Transmission Line to deliver hydroelectric power from northern Manitoba by 2020 (see Renewable Energy and Transmission).


•	The conversion of Laskin from coal to cleaner-burning natural gas in 2015.


•	Retiring Taconite Harbor Unit 3, one of three coal units at Taconite Harbor, in 2015.

Our “EnergyForward” initiatives are subject to regulatory approval, and were included in Minnesota Power’s 2013 Integrated Resource Plan filed with the MPUC on March 1, 2013 (see Integrated Resource Plan).

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be between $350 million and $400 million. The MPCA issued its report on March 1, 2013 in support of the Boswell Unit 4 mercury emissions reduction plan stating that the plan is appropriate for accomplishing the objectives of reducing emissions of mercury and other pollutants under the Minnesota Statutes and recommended that the MPUC accept the report’s findings. We expect a decision by the MPUC on the plan in the third quarter of 2013. Upon approval by the MPUC, we anticipate filing a petition to include investments and expenditures in customer billing rates. (See EnergyForward.)

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK (Continued)

Regulated Operations (Continued)

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and municipal energy sales in Minnesota be from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power met the 2012 milestone and has developed a plan to meet the future renewable milestones which is included in its 2010 and 2013 Integrated Resource Plans. The MPUC approved the 2010 Integrated Resource Plan in its final order issued in May 2011. Minnesota Power submitted its 2013 Integrated Resource Plan on March 1, 2013, which included an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See EnergyForward.)

Minnesota Power has taken several steps in executing its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers (see Wind Energy). We expect 17 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2013.

Wind Energy. Our wind energy facilities consist of our 292 MW Bison Wind Energy Center located in North Dakota completed in various phases through 2012, and our 25 MW Taconite Ridge Energy Center located in northeastern Minnesota completed in 2008. We also have two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) located in North Dakota.

Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in a November 2011 order and are based on investments and expenditures through that period. We filed a cost recovery petition with the MPUC on May 31, 2013, to update customer billing rates for subsequent investments and expenditures since 2011, which is expected to be approved in the second half of 2013.

Our capital expenditures plan includes additional wind energy investments in North Dakota to meet Minnesota’s 25 percent renewable energy mandate by 2025. On January 2, 2013, The American Taxpayer Relief Act of 2012 (ATRA) extended the availability of the production tax credit for renewable energy facilities that commence construction by December 31, 2013, among other ATRA requirements.

On May 3, 2013, we filed for NDPSC site permit approval for construction of Bison 4, an approximately 200 MW wind project in North Dakota. If approved by the NDPSC, construction would commence in the second half of 2013 and would be expected to be completed by the end of 2014. The total project investment is estimated to be approximately $345 million (see Liquidity and Capital Resources – Capital Requirements). We also expect to file for MPUC approval of the project in the third quarter of 2013. Upon approval by the MPUC, we will seek current cost recovery eligibility for our investment.

Minnesota Power uses the 465-mile, 250 kV DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit. The DC transmission line capacity can be increased if renewable energy or transmission needs justify investments to upgrade the line.

Manitoba Hydro. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in April 2015. Under this agreement 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.

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK (Continued)

Regulated Operations (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for changes in a governmental inflationary index, a natural gas index, and market prices. The agreement is subject to construction of additional transmission capacity between Manitoba and Minnesota’s Iron Range. In addition, we are exploring other regional grid enhancements that would allow for the movement of more renewable energy in the Upper Midwest while at the same time strengthening electric reliability in the region. (See Transmission.)

Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota and surrounding areas. The flooding impacted Minnesota Power’s St. Louis River hydro system, particularly the Thomson Energy Center, which is currently off-line due to damage to the forebay canal and flooding at the facility. Minnesota Power continues to work on restoring the Thomson facility and to assess options for rebuilding the forebay canal. We are in close contact with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs. Until that assessment is complete, we are not able to fully estimate the capital cost and schedule for rebuilding the forebay canal and resuming generation; however, based on a preliminary evaluation, the capital rebuild cost is estimated to be approximately $25 million. In addition to the forebay work, Minnesota Power is performing restoration and upgrade work on electrical, mechanical and flow line systems at the Thomson facility, which is estimated to cost a total of approximately $35 million (net of anticipated insurance recoveries). Any expenditures to restore and upgrade systems and rebuild the forebay canal will be capitalized. Minnesota Power is working towards returning to partial generation from the Thomson Energy Center by the end of 2013 and to full generation by the end of 2014. In addition to the work at the Thomson facility, additional work on the Thomson Dam and other facilities in the St. Louis River hydro system are necessary to meet high flow events like that experienced in June 2012, which is estimated to cost approximately $10 million dollars through 2015. We expect to file a request with the MPUC in the third quarter of 2013 for cost recovery of capital expenditures related to the restoration and repair of the Thomson facility and other related St. Louis River hydro system projects through a renewable resources rider.

Minnesota Solar Mandate. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain industrial customers, to be generated by solar energy by the end of 2020. At least ten percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Minnesota Power is in the process of evaluating the potential impact of this legislation on our operations.

Integrated Resource Plan. In May 2011, the MPUC issued its final order approving our 2010 Integrated Resource Plan. As a condition of the final order, a required baseload diversification study evaluating the impact of additional environmental regulations over the next two decades was filed in February 2012. Minnesota Power’s 2013 Integrated Resource Plan, filed on March 1, 2013, details our “EnergyForward” strategic plan (see EnergyForward), and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. A decision by the MPUC on this plan is expected in late 2013.

Transmission. We plan to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. This includes the Great Northern Transmission Line and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC.

Transmission Investments. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. The continued use of the 2009 billing factor was approved by the MPUC in May 2011, which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In June 2011, Minnesota Power filed an updated billing factor that includes additional transmission expenditures, which is expected to be approved in the second half of 2013.

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK (Continued)

Regulated Operations (Continued)

Great Northern Transmission Line. As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. In February 2012, Minnesota Power and Manitoba Hydro proposed construction of the Great Northern Transmission Line, a 500 kV transmission line between Manitoba and Minnesota’s Iron Range, in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy, which is targeted to be in service in 2020. Total project cost and cost allocations are still to be determined; however, at this time we expect our capital expenditures to range between $200 million and $400 million. The Great Northern Transmission Line is subject to various federal and state regulatory approvals. In addition, Manitoba Hydro must obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada.

ATC Joint Development. Minnesota Power and ATC are evaluating the joint development of a 345 kV transmission line from Minnesota’s Iron Range to Duluth, Minnesota, for service after 2020, as a potential second phase of the Great Northern Transmission Line. This is in addition to assessing transmission alternatives in Wisconsin that would allow for the movement of more renewable energy in the Upper Midwest while at the same time strengthening electric reliability in the region. Total project costs, ownership shares and cost allocations are still to be determined.

Investment in ATC. As of June 30, 2013, our equity investment in ATC was $111.2 million, representing an approximate 8 percent ownership interest. ATC rates are based on a FERC approved 12.2 percent return on common equity dedicated to utility plant. In September 2012, ATC updated its 10-year transmission assessment covering the years 2012 through 2021 which identifies a need for between $3.9 and $4.8 billion in transmission system investments. These investments by ATC are expected to be funded through a combination of internally generated cash, debt and investor contributions. As opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro rata ownership interest in ATC. In the first six months of 2013, we invested $1.6 million in ATC, and on July 30, 2013, we invested an additional $0.8 million. We expect to make additional investments of approximately $0.7 million in 2013. (See Note 7. Investment in ATC.)

In April 2011, ATC and Duke Energy Corporation announced the creation of a joint venture, Duke-American Transmission Co. (DATC) that intends to build, own and operate new electric transmission infrastructure in the U.S. and Canada. DATC is subject to the rules and regulations of the FERC, MISO, PJM Interconnection LLC and various other independent system operators and state regulatory authorities. In September 2011, DATC announced its first set of proposed transmission projects, which include seven new transmission line projects in five Midwestern states. The individual projects have a total cost of approximately $4 billion. We intend to maintain our approximate 8 percent ownership interest in ATC.

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK (Continued)

Investments and Other

BNI Coal. BNI Coal anticipates selling approximately 4 million tons of coal in 2013 (4.4 million tons were sold in 2012) and has sold 2.0 million tons through June 30, 2013 (2.2 million tons were sold as of June 30, 2012).

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, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. If weak market conditions continue, the impact on our future operations would be the continuation of little or no sales while still incurring operating expenses and carrying costs such as community development district assessments and property taxes, or impairments. ALLETE does not intend to acquire additional Florida real estate.

Our two major development projects are Town Center and Palm Coast Park. Another major project, Ormond Crossings, is in the permitting stage. The City of Ormond Beach, Florida, approved a development agreement for Ormond Crossings which 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 (100% Owned)		Residential	Non-residential
Land Available-for-Sale	Acres (a)	Units (b)	Sq. Ft. (b, c)
Current Development Projects
Town Center	965	2,485	2,246,200
Palm Coast Park	3,888	3,554	3,096,800
Total Current Development Projects	4,853	6,039	5,343,000

Planned Development Project
Ormond Crossings	2,914	2,950	3,215,000
Other
Lake Swamp Wetland Mitigation Project	3,044	(d)	(d)
Total of Development Projects	10,811	8,989	8,558,000


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


(b)	Units and square footage are estimated. 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 permitted, regionally significant wetlands mitigation bank. Wetland mitigation credits will be used at Ormond Crossings and are available-for-sale to developers of other projects that are located in the bank’s service area.

In addition to the three development projects and the mitigation bank, ALLETE Properties has 1,941 acres of other land available-for-sale.

ALLETE Second Quarter 2013 Form 10-Q

OUTLOOK (Continued)

Income Taxes. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2013. On an ongoing basis, ALLETE has certain tax credits and other tax adjustments that reduce the statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, renewable tax credits, AFUDC-Equity, domestic manufacturer’s deduction, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income from operations before 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. Due primarily to increased production tax credits as a result of additional wind generation, we expect our effective tax rate to be approximately 20 percent for 2013. We also expect that our effective tax rate will be lower than the statutory rate over the next ten years due to production tax credits attributable to our wind generation. (See Note 10. Income Tax Expense.)

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Position. ALLETE is well-positioned to meet the Company’s liquidity needs. As of June 30, 2013, we had cash and cash equivalents of $145.0 million, $400.7 million in available consolidated lines of credit and a debt-to-capital ratio of 47 percent.

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



	June 30, 2013		%	December 31, 2012		%
Millions
ALLETE Equity		$1,249.0	53		$1,201.0	54
Long-Term Debt (Including Current Maturities)	1,102.6		47	1,018.1		46
		$2,351.6	100		$2,219.1	100

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



For the Six Months Ended June 30,	2013			2012
Millions
Cash and Cash Equivalents at Beginning of Period		$80.8			$101.1
Cash Flows from (used for)
Operating Activities	111.1			128.1
Investing Activities	(125.2		)	(227.0		)
Financing Activities	78.3			6.4
Change in Cash and Cash Equivalents	64.2			(92.5		)
Cash and Cash Equivalents at End of Period		$145.0			$8.6

Operating Activities. Cash from operating activities was $111.1 million for the six months ended June 30, 2013 ($128.1 million for the six months ended June 30, 2012). Cash from operating activities was lower than 2012 primarily due to cash contributions to other postretirement benefit plans ($10.8 million in 2013 and none in 2012), decreased other current liabilities due to receipt of customer security deposits in 2012, and increased cost recovery rider receivable, offset by higher net income.

Investing Activities. Cash used for investing activities was $125.2 million for the six months ended June 30, 2013 ($227.0 million for the six months ended June 30, 2012). The decrease in cash used for investing activities was primarily due to lower payments for capital expenditures in 2013 as we completed our Bison project in late 2012.

Financing Activities. Cash from financing activities was $78.3 million for the six months ended June 30, 2013 ($6.4 million for the six months ended June 30, 2012). The increase in cash from financing activities was primarily due to proceeds of $150.0 million from long-term debt issuances in 2013 partially offset by $60.0 million of long-term debt maturing in April 2013.

ALLETE Second Quarter 2013 Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES (Continued)

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. As of June 30, 2013, we had available consolidated bank lines of credit aggregating $400.7 million, of which $150.0 million expires in January 2014, and $250.0 million expires in June 2015. In addition, we have 2.7 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 4.2 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Ltd. The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.

Securities. We entered into a distribution agreement with KCCI, Ltd. in February 2008, as amended most recently in August 2012, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 4.2 million remain available for issuance. For the six months ended June 30, 2013, 0.3 million shares of common stock were issued under this agreement, resulting in net proceeds of $11.7 million (0.4 million shares were issued for the six months ended June 30, 2012, resulting in net proceeds of $18.7 million). The shares issued in 2013 were, and the remaining shares may be, offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-170289.

During the six months ended June 30, 2013, we issued 0.4 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 $21.6 million (0.3 million shares were issued for net proceeds of $11.8 million during the six months ended June 30, 2012). These shares of common stock were registered under Registration Statement Nos. 333-188315, 333-183051 and 333-162890.

On April 2, 2013, we issued $150.0 million of the Company’s First Mortgage Bonds (Bonds) in a private placement in three series. (See Note 8. Short-Term and Long-Term Debt.) Proceeds from the sale of the Bonds will be used to fund utility capital investments, repay debt, and/or for general corporate purposes.

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

Pension and Other Postretirement Benefit Plans. 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 do not expect to contribute to our defined benefit pension plan in 2013, and we do not expect to make any additional contributions to our other postretirement benefit plan in 2013. (See Note 13. Pension and Other Postretirement Benefit Plans.)

Off-Balance Sheet Arrangements

Off-balance sheet arrangements are summarized in our 2012 Form 10-K, with additional disclosure in Note 14. Commitments, Guarantees and Contingencies.

Credit Ratings. Access to reasonably priced capital markets is dependent in part on credit and ratings. Our securities have been rated by Standard & Poor’s and by Moody’s. Rating agencies use both quantitative and qualitative measures in determining a company’s credit rating. These measures include business risk, liquidity risk, competitive position, capital mix, financial condition, predictability of cash flows, management strength and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative ones are more subjective. The disclosure of these credit ratings is not a recommendation to buy, sell or hold our securities. Ratings are subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating.

ALLETE Second Quarter 2013 Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Standard & Poor’s recently revised its criteria for rating utility first mortgage bonds. As part of Standard & Poor’s revised utility first mortgage bond criteria implementation, the senior secured rating for ALLETE was raised from “A–” to “A”.



Credit Ratings	Standard & Poor’s	Moody’s
Issuer Credit Rating	BBB+	Baa1
Commercial Paper	A-2	P-2
Senior Secured
First Mortgage Bonds (a)	A	A2


(a)	Includes collateralized pollution control bonds.

Capital Requirements

Our capital expenditures for 2013 are expected to be approximately $375 million. For the six months ended June 30, 2013, capital expenditures totaled $100.2 million ($235.1 million for the six months ended June 30, 2012). The expenditures were primarily made in the Regulated Operations segment.

ALLETE’s projected capital expenditures for the years 2013 through 2017 are presented in the table below. Actual capital expenditures may vary from the estimates due to changes in forecasted plant maintenance, regulatory decisions or approvals, future environmental requirements, base load growth, capital market conditions or execution of new business strategies.



Capital Expenditures		2013		2014		2015		2016		2017		Total
Millions
Regulated Utility Operations
	Base and Other (a)		$208		$160		$152		$155		$138		$813
	Cost Recovery (b)
	Environmental (c)	55		148		111		3		—		317
	Renewable (d)	60		287		—		—		—		347
	Transmission (e)	36		22		11		3		40		112
	Total Cost Recovery	151		457		122		6		40		776
Regulated Utility Capital Expenditures		359		617		274		161		178		1,589
Other		16		25		11		9		3		64
Total Capital Expenditures			$375		$642		$285		$170		$181		$1,653


(a)	Total capital expenditures of approximately $70 million relating to Minnesota Power’s hydro system are included in Base and Other, of which approximately $55 million relating to Thomson Energy Center is expected to be spent in 2013. (See Outlook – Regulated Operations.)


(b)	Estimated current capital expenditures eligible for cost recovery outside of a rate case.


(c)	Environmental capital expenditures primarily relate to compliance with the MATS rule for Boswell Unit 4. (See Note 14. Commitments, Guarantees and Contingencies.) Boswell Unit 4 capital expenditures included above reflect Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4.


(d)	Includes a total of approximately $345 million in 2013 and 2014, related to Bison 4. (See Outlook – Regulated Operations.)


(e)	Transmission capital expenditures related to CapX2020 are estimated at approximately $50 million over the 2013 to 2015 period. Capital expenditures of approximately $40 million are included related to construction of the Great Northern Transmission Line. (See Outlook – Regulated Operations.)

We will finance capital expenditures from a combination of internally generated funds and debt and equity proceeds. We intend to maintain a capital structure with capital ratios near current levels. (See Liquidity and Capital Resources – Capital Structure.)

ALLETE Second Quarter 2013 Form 10-Q

OTHER

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. 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. Environmental Matters are summarized in our 2012 Form 10-K, with additional disclosure in Note 14. Commitments, Guarantees and Contingencies. We are unable to predict the outcome of the matters discussed.

NEW ACCOUNTING STANDARDS

New accounting standards are discussed in Note 1. Operations and Significant Accounting Policies.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SECURITIES INVESTMENTS

Available-for-sale Securities. As of June 30, 2013, our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits and the cash equivalents within these plans. (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 territory in Wisconsin. Our Minnesota regulated utility’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates. Conversely, costs below those in base rates 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 (Minnesota Power) and natural gas (SWL&P).

POWER MARKETING

Our power marketing activities consist of: (1) purchasing energy in the wholesale market to serve our regulated service territory 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 municipal customers in our regulated service territory. We actively sell any excess energy to the wholesale market to optimize the value of our generating facilities.

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

INTEREST RATE RISK

We are 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. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. Interest rates on variable rate long-term debt are reset on a periodic basis reflecting prevailing market conditions. Based on the variable rate debt outstanding at June 30, 2013, and assuming no other changes to our financial structure, an increase 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 increase to the average variable interest rate on the variable rate debt outstanding as of June 30, 2013.

ALLETE Second Quarter 2013 Form 10-Q

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As of June 30, 2013, 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. 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

United Taconite Lawsuit. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of June 30, 2013, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance limits for any potential loss. Our insurance carrier is providing a defense subject to a reservation of rights as to certain claims.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Part 1, Item 1A Risk Factors of our 2012 Form 10-K.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ALLETE Second Quarter 2013 Form 10-Q

ITEM 4. MINE SAFETY DISCLOSURES

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and this Item are included in Exhibit 95 to this Form 10-Q.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS



Exhibit Number
10 (a)			Amended and Restated ALLETE Non-Employee Director Stock Plan, effective May 15, 2013.
10 (b)			First Amendment to Amended and Restated Letter of Credit Agreement, dated as of June 1, 2013, between ALLETE, Inc. and Wells Fargo Bank, National Association, as Issuing Bank, Administrative Agent and sole Participating Bank.
10 (c)			July 2013 ALLETE and Affiliated Companies Compensation Recovery Policy
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.
32			Section 1350 Certification of Periodic Report by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95			Mine Safety
99			ALLETE News Release dated August 1, 2013, announcing 2013 second quarter earnings. (This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.)
101.INS			XBRL Instance
101.SCH			XBRL Schema
101.CAL			XBRL Calculation
101.DEF			XBRL Definition
101.LAB			XBRL Label
101.PRE			XBRL Presentation

ALLETE Second Quarter 2013 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.




August 1, 2013		/s/ Mark A. Schober
		Mark A. Schober
		Senior Vice President and Chief Financial Officer





August 1, 2013		/s/ Steven Q. DeVinck
		Steven Q. DeVinck
		Controller and Vice President – Business Support

ALLETE Second Quarter 2013 Form 10-Q

ALE 6-30-2013 EX-10.A

Exhibit 10 (a)

ALLETE

NON-EMPLOYEE DIRECTOR

STOCK PLAN

(As amended and restated effective May 15, 2013)

ALLETE NON-EMPLOYEE DIRECTOR STOCK PLAN

(As amended and restated effective May 15, 2013)

Article 1

Establishment and Purpose

This document includes the terms of the ALLETE Non-Employee Director Stock Plan (the “Plan”), the purpose of which is to provide ownership of the Company's stock to members of its Board of Directors in order to improve the Company's ability to attract and retain highly qualified individuals to serve as Directors and to strengthen the commonality of interest between Directors and Company shareholders. The Plan, first established effective May 9, 1995, was amended as follows: effective September 1, 2000, the Plan was amended to reflect the Company's name change; effective January 1, 2002, January 1, 2003, February 15, 2007, May 1, 2009, May 1, 2010 and October 1, 2010, respectively, the Plan was amended to reflect changes in Director compensation; effective July 20, 2004, the Plan was amended to provide for tax withholding; and, effective May 1, 2009, the Plan was amended to permit Directors to defer their Annual Retainer awarded pursuant to the Plan under the ALLETE Amended and Restated Non-Employee Director Compensation Deferral Plan II. The Company now further amends and restates the Plan, effective May 15, 2013, to increase by 150,000 the number of shares authorized for issuance under this Plan, and to make other conforming amendments. Capitalized terms, unless otherwise defined herein, shall have the meaning provided in Article 10.

Article 2

Administration

2.1

Administrator. The Executive Compensation Committee of the Board shall administer the Plan. Notwithstanding the foregoing, the Administrator may delegate any of its duties to such other person or persons from time to time as it may designate. Members of the Executive Compensation Committee may participate in the Plan; however, any Director serving on the Executive Compensation Committee shall not vote or act on any matter relating solely to himself or herself.

2.2

Duties. The Administrator has the authority to construe and interpret all provisions of the Plan, to resolve any ambiguities, to adopt rules and practices concerning the administration of the Plan, to make any determinations and calculations necessary or appropriate hereunder, and to remedy any errors, inconsistencies or omissions. The Company shall pay all expenses and liabilities incurred in connection with Plan administration.


2.3	Agents. The Administrator may engage the services of accountants, attorneys, actuaries, investment consultants, and such other professional personnel as are deemed necessary or advisable to assist in fulfilling the Administrator's responsibilities. The Administrator, the Company and the Board may rely upon the advice, opinions or valuations of any such persons.

2.4

Binding Effect of Decisions. The decision or action of the Administrator with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final, conclusive and binding upon all persons having any interest in the Plan. Neither the Administrator, its delegates, nor the Board shall be personally liable for any good faith action, determination or interpretation with respect to the Plan, and each shall be fully protected by the Company in respect of any such action, determination or interpretation.


2.5	Company Information. To enable the Administrator to perform its duties, the Company shall supply full and timely information to the Administrator on all matters relating to the Annual Retainer, the Directors and such other pertinent information as the Administrator may reasonably require.

Article 3

Common Stock Subject to the Plan

Subject to Article 6 below, the maximum aggregate number of shares of Common Stock that may be delivered under the Plan is 164,661 shares. The Common Stock to be delivered under the Plan may be made available from authorized but unissued shares of Common Stock or shares of Common Stock purchased on the open market.

Article 4

Determination of Annual Retainer and Stock Payments


4.1.	The Board shall determine the Annual Retainer payable to each Director. Unless otherwise specified by the Board, the Annual Retainer, once established, will remain in effect until the Board changes it.

4.2

Each Director shall receive a Stock Payment for services rendered during the Service Period on the first business day of June or as soon as practicable following that date. The number of shares shall be calculated by dividing the amount of the Stock Payment by the fair market value of a share of Common Stock, which for this purpose means the average New York Stock Exchange closing price for the last five (5) days up to and including the date that is ten (10) calendar days prior to June 1 of the Service Period (or on the first business day thereafter if June 1 is not a business day).

To the extent the Director has not elected to defer any or all of the Stock Payment pursuant to the ALLETE Amended and Restated Non-Employee Director Compensation Deferral Plan II, or any successor deferral plan or arrangement established by the Company for such purpose, the Company shall either issue shares or cause the appropriate number of shares of Common Stock to be purchased in the market and delivered to the Director or, at the Company's election, to the Director's Invest Direct account or to the Director's account in such successor dividend reinvestment plan as the Company may establish. Fractional shares may be paid in cash. Any Director joining the Board during a Service Period after the first business day in June will receive his or her Stock Payment, valued using the same general methodology described above and prorated to reflect the number of months included in the Director's initial Service Period, as soon as practicable after the first business day following the effective date of his or her election or appointment to the Board.


4.3	Any Director may decline a Stock Payment for any Plan Year, provided, however, that no cash compensation shall be paid in lieu thereof. Any Director who declines a Stock Payment must do so in writing prior to the performance of any services as a Director for the Plan Year to which such Stock Payment relates.


4.4	No Director shall be required to forfeit or otherwise return any shares of Common Stock issued as a Stock Payment pursuant to the Plan (including any shares of Common Stock received as a result of an election under Article 5) notwithstanding any change in status of such Director that renders him or her ineligible to continue as a Director in the Plan.


4.5	The cash portion of the Annual Retainer for such Plan Year shall be paid to Directors at such times and in such manner as may be determined by the Board of Directors, unless the Director has elected to defer some or all of the cash portion of the Annual Retainer pursuant to the ALLETE Amended and Restated Non-Employee Director Compensation Deferral Plan II.


4.6	Any portion of the Annual Retainer that a Director elects to defer pursuant to the ALLETE Amended and Restated Non-Employee Director Compensation Deferral Plan II shall be considered a deferral under that plan and not this Plan.

Article 5

Election to Increase Amount of Stock Payment

in Lieu of Cash Portion of Annual Retainer

5.1 Annual Election. Each Plan Year, a Director may make a written election to reduce the cash portion of the Annual Retainer and have such amount applied to purchase additional shares of Common Stock. The election shall be made on a form provided by the Administrator and must be returned to the Administrator. An election becomes irrevocable no later than the date specified by the Administrator, but in any event before the beginning of the Plan Year to which the election relates.

A Director's election will become effective only if the forms required by the Administrator have been properly completed and signed by the Director, timely delivered to, and accepted by, the Administrator. The election form shall state the percentage or amount by which the Director desires to reduce the cash portion of the Annual Retainer, which shall be applied toward the purchase of Common Stock to be delivered on the same date that the Stock Payment is made, provided, however, that no fractional shares may be purchased. Cash in lieu of any fractional share may be paid to the Director. No Director shall be allowed to change or revoke any election for the then current year.

5.2 Initial Election. A Director who first becomes eligible to participate in the Plan during a Plan Year may elect to reduce the cash portion of the Annual Retainer and have such amount applied to purchase additional shares of Common Stock by filing a signed election form with the Administrator no later than 30 days after the Director first becomes eligible to participate in the Plan. The election shall become irrevocable with respect to the Service Period covered by the election on the earlier of the 30th day following the date on which the Director first becomes eligible to participate in the Plan or the date on which payment is made to the Director.

Article 6

Adjustment for Changes in Capitalization

If the outstanding shares of Common Stock of the Company are increased, decreased, or exchanged for a different number or kind of shares or other securities, or if additional shares or new or different shares or other securities are distributed with respect to such shares of Common Stock or other securities, through merger, consolidation, sale of all or substantially all of the property of the Company, reorganization or recapitalization, reclassification, stock dividend, stock split, reverse stock split, combinations of shares, rights offering, distribution of assets or other distribution with respect to such shares of Common Stock or other securities or other change in the corporate structure or shares of Common Stock, the number of shares to be granted annually, the maximum number of shares and the kind of shares that may be issued under the Plan shall be appropriately adjusted by the Administrator. Any determination by the Administrator as to any such adjustment will be final, binding, and conclusive. The maximum number of shares issuable under the Plan as a result of any such adjustment shall be rounded down to the nearest whole share.

Article 7

Amendment or Termination of Plan

The Board will have the power, in its discretion, to amend, suspend or terminate the Plan at any time.

Article 8

Duration of the Plan

Subject to the right of the Board to terminate the Plan pursuant to Article 7, the Plan shall remain in effect until all shares subject to the Plan have been purchased or acquired according to the Plan's provisions.

Article 9

Miscellaneous Provisions

9.1

Continuation of Directors in Same Status. Nothing in the Plan or any action taken pursuant to the Plan shall be construed as creating or constituting evidence of any agreement or understanding, express or implied, that the Company will retain a Director as a Director or in any other capacity for any period of time or at a particular retainer or other rate of compensation, as conferring upon any Director any legal or other right to continue as a Director or in any other capacity, or as limiting, interfering with or otherwise affecting the right of the Company to terminate a Director in his or her capacity as a Director or otherwise at any time for any reason, with or without cause, and without regard to the effect that such termination might have upon him or her as a participant under the Plan.

9.2

Compliance with Government Regulation. Neither the Plan nor the Company shall be obligated to issue any shares of Common Stock pursuant to the Plan at any time unless and until all applicable requirements imposed by any federal and state securities and other laws, rules and regulations, by any regulatory agencies or by any stock exchanges upon which the Common Stock may be listed have been fully met. As a condition precedent to any issuance of shares of Common Stock, the Board or the Administrator may require a Director to take any such action and to make any such covenants, agreements and representations as the Board or the Administrator, as the case may be, in its discretion deems necessary or advisable to ensure compliance with such requirements. The Company shall in no event be obligated to register the shares of Common Stock deliverable under the Plan pursuant to the Securities Act of 1933, as amended, or to qualify or register such shares under any securities laws of any state upon their issuance under the Plan or at any time thereafter, or to take any other action in order to cause the issuance and delivery of such shares under the Plan or any subsequent offer, sale, or other transfer of such shares to comply with any such law, regulation, or requirement. Directors are responsible for complying with all applicable federal and state securities and other laws, rules, and regulations in connection with any offer, sale, or other transfer of the shares of Common Stock issued under the Plan or any interest therein including, without limitation, compliance with the registration requirements of the Securities Act of 1933 as amended (unless an exemption therefrom is available) or with the provisions of Rule 144 promulgated thereunder, if applicable, or any successor provisions. Certificates for shares of Common Stock may be legended as the Administrator shall deem appropriate.


9.3	Non-transferability of Rights. No Director shall have the right to assign the right to receive any Stock Payment or any other right or interest under the Plan, contingent or otherwise, or to cause or permit any encumbrance, pledge, or charge of any nature to be imposed on any such Stock Payment (prior to the delivery of such Stock Payment) or any such right or interest.


9.4	Severability. In the event that any provision of the Plan is held invalid, void, or unenforceable, the same shall not affect, in any respect whatsoever, the validity of any other provision of the Plan.


9.5	Governing Law. To the extent not preempted by federal law, the Plan shall be governed by the laws of the state of Minnesota.


9.6	Tax Withholding. The Company is authorized to withhold from the Annual Retainer including from the Stock Payment, amounts of withholding and other taxes due in connection with such payment by the Company and to take such other action as the Company may deem advisable to enable the Company or Director to satisfy obligations relating to the payment of any Annual Retainer.

Article 10

Definitions

When used herein, the following terms shall have the respective meanings set forth below:


10.1	“Administrator” is defined in Article 2.1 of the Plan.


10.2	“Annual Retainer” means the annual retainer payable by the Company to Directors (excluding any per meeting fees or expense reimbursements).


10.3	“Board” or “Board of Directors” means the Board of Directors of the Company.


10.4	“Common Stock” means the common stock, no par value, of the Company.


10.5	“Company” means ALLETE, Inc., f/k/a Minnesota Power, Inc. and f/k/a Minnesota Power & Light Company, a Minnesota corporation, and any successor corporation.


10.6	“Director” means any person who is elected or appointed to the Board of Directors of the Company and who is not an Employee.


10.7	“Employee” means any officer or other common law employee of the Company or of any Subsidiary.


10.8	“Exchange Act” means the Securities Exchange Act of 1934, as amended.


10.9	“Invest Direct” means the ALLETE Stock Purchase and Dividend Reinvestment Plan or any successor dividend reinvestment plan as the Company may establish.

10.10 “Plan Year” means the calendar year.

10.11

“Service Period” means, with respect to the Annual Cash Retainer, a Plan Year, and with respect to the Annual Stock Retainer, the 12-month period beginning on June 1 of each Plan Year or, with respect to a Director who first becomes eligible to participate in the Plan after June 1 of a Plan Year, such lesser period beginning on the date the Director joins the Board and ending on the following May 31.


10.12	“Stock Payment” means that portion of the Annual Retainer to be paid to Directors in shares of Common Stock rather than cash for services rendered as a Director of the Company, as provided in Article 4 hereof, including that portion of the Stock Payment resulting from any election specified in Article 5 hereof.


10.13	“Subsidiary” means any corporation that is a “subsidiary corporation” of the Company, as that term is defined in Section 424(f) of the Internal Revenue Code of 1986, as amended.

In Witness Whereof, the Board of Directors of ALLETE, Inc. has caused this amended and restated ALLETE Non-Employee Director Stock Plan to be signed by its duly authorized representative, effective as of May 15, 2013.

ALLETE, Inc.

/s/ Alan R. Hodnik

Alan R. Hodnik

Chairman, President and Chief Executive Officer

ATTEST:

/s/ Deborah A. Amberg

Deborah A. Amberg

Senior Vice President, General Counsel and Secretary

ALE 6-30-2013 EX-10.B

Exhibit 10 (b)

FIRST AMENDMENT

AMENDED AND RESTATED LETTER OF CREDIT AGREEMENT

This Amendment is entered into as of June 1, 2013 by and between ALLETE, Inc., a Minnesota corporation (the “Company”), and Wells Fargo Bank, National Association, a national banking association (“Wells Fargo”), in its capacity as the Issuing Bank, Administrative Agent and sole Participating Bank under and as defined in the Reimbursement Agreement described below.

The Company and Wells Fargo are parties to an Amended and Restated Letter of Credit Agreement (as amended, supplemented, restated or otherwise modified from time to time, the “Reimbursement Agreement”) dated June 3, 2011, setting forth the terms on which Wells Fargo, as the Issuing Bank thereunder, has maintained its Irrevocable Letter of Credit No. NZS569069, dated July 5, 2006 (as amended, supplemented, restated or otherwise modified from time to time, the “Letter of Credit”) to support certain obligations arising with respect to the Collier County (Florida) Industrial Authority Industrial Development Variable Rate Demand Refunding Revenue Bonds (ALLETE, Inc. Project), Series 2006, in the principal amount of $27,800,000.

The Company has asked the Issuing Bank to amend the Letter of Credit to provide that it is automatically extended from time to time unless notice of non-extension is provided by the Issuing Bank.

The Banks (as defined in the Reimbursement Agreement) are willing to grant the Company's request, subject to the execution and delivery of this Amendment by each of the parties to the Reimbursement Agreement.

ACCORDINGLY, in consideration of the premises and the mutual covenants contained in the Reimbursement Agreement and this Amendment, the parties hereby agree as follows:

1. Definitions.

As used in this Amendment, capitalized terms defined in the Reimbursement Agreement that are not otherwise defined herein shall have the meanings given them in the Reimbursement Agreement.

2. Issuance of Letter of Credit Amendment.

The Company hereby requests that the Issuing Bank issue its amendment to the Letter of Credit in the form of Exhibit A hereto. Subject to the conditions set forth in this Amendment, the Issuing Bank hereby agrees to issue such amendment to the Letter of Credit, and each Participating Bank consents thereto.

3. Amendment of Reimbursement Agreement.

(a) Section 1.1 of the Reimbursement Agreement is hereby amended by inserting the following definition therein (in alphabetical order):

“Non-Extension Notice” means notice by the Issuing Bank to the Trustee, in accordance with the terms of the Letter of Credit, that the Issuing Bank has elected not to extend the Letter of Credit beyond the date specified in such notice.

(b) Section 2.15 of the Reimbursement Agreement is hereby amended in its entirety to read as follows:

Section 2.15 Extension of Stated Expiration Date.

(a) The Letter of Credit provides by its terms that the Stated Expiration Date shall be automatically extended for successive one-year terms (but not later than July 5, 2018) unless the Issuing Bank provides a Non-Extension Notice not less than 30 days prior to the then-current Stated Expiration Date. The Issuing Bank may (and shall, if so directed by the Administrative Agent) provide such Non-Extension Notice at any time. The Administrative Agent shall direct the Issuing Bank to provide such Non-Extension Notice if so requested by the Company or any Participating Bank in writing to the Administrative Agent not more than 120 days and not less than 90 days prior to the then-applicable Stated Expiration Date. The Issuing Bank may issue any Non-Extension Notice, and any Participating Bank may make any request for issuance of a Non-Extension Notice under this Section 2.15, in each case in its sole and absolute discretion, whether or not any Potential Default or Event of Default exists. As a condition to allowing the extension of the Letter of Credit, any Bank may require the Company to deliver one or more amendments to this Agreement (which may include modifications to any fees or other amounts required to be paid hereunder) or certificates (which may cover, among other things, the continued accuracy of the representations and warranties made hereunder), or impose other conditions thereto. The Issuing Bank shall notify the Company of any decision not to extend the Stated Expiration Date promptly, and in any event not later than concurrently with the giving of such notice to the Trustee in accordance with the Letter of Credit. Unless notice of non-extension is provided in accordance with the Letter of Credit, the Stated Expiration Date shall be automatically extended in accordance with the terms of the Letter of Credit, and all references in this Agreement to the Stated Expiration Date shall be deemed to be references to the expiration date as so extended in accordance with the terms of the Letter of Credit.

(b) So long as the Company delivers a request for such notice to the Issuing Bank not more than 120 days and not less than 90 days prior to the then-applicable Stated Expiration Date, the Issuing Bank will notify the Company, not less than 75 days prior to the then-applicable Stated Expiration Date, if it intends to issue a Non-Extension Notice effective as of such Stated Expiration Date; provided, however, that nothing herein shall limit the Issuing Bank from issuing a Non-Extension Notice at any time while a Potential Default or Event of Default is continuing, even if the Issuing Bank has failed to give such notice of its intention.

Section 7.10 Amendments and Waivers.

Neither this Agreement nor any Related Document, nor any terms hereof or thereof may be amended, supplemented or modified except in accordance with the provisions of this subsection. The Majority Participating Banks may, or, with, but only with, the written consent of the Majority Participating Banks, the Administrative Agent or the Issuing Bank, as applicable, may, from time to time, (a) enter into with the Company written amendments, supplements or modifications hereto and to the other Financing Documents for the purpose of adding any provisions to this Agreement or the other Financing Documents or changing in any manner the rights of the Participating Banks or of the Company hereunder or thereunder or (b) waive, on such terms and conditions as the Majority Participating Banks or the Administrative Agent, as the case may be, may specify in such instrument, any of the requirements of an Event of Default and its consequences; provided, however, that no such waiver and no such amendment,

supplement or modification shall, without the consent of each Participating Bank, (i) reduce the amount or extend the scheduled date of maturity of any Obligation or any installment thereof, or reduce the stated rate of any interest or fee payable hereunder or extend the scheduled date of any payment thereof or increase the amount or extend the Stated Expiration Date, in each case without the consent of each Participating Bank affected thereby (provided, however, that each Participating Bank shall be deemed to have given its consent to any automatic extension of the Stated Expiration Date in accordance with the terms of the Letter of Credit unless, in accordance with Section 2.15, such Participating Bank has directed the Administrative Agent to direct the Issuing Bank to give a Non-Extension Notice), or (ii) amend, modify or waive any provision of this subsection or reduce the percentage specified in the definition of Majority Participating Banks, or consent to the assignment or transfer by the Company of any of its rights and obligations under this Agreement and the other Financing Documents, in each case without the written consent of all the Participating Banks, or (iii) amend, modify or waive any provision of Article VIII or any provision hereunder affecting the rights or obligations of the Issuing Bank without the written consent of the Administrative Agent or the Issuing Bank, respectively. Any such waiver and any such amendment, supplement or modification shall apply equally to each of the Participating Banks and shall be binding upon the Company, the Participating Banks, the Issuing Bank and the Administrative Agent. In the case of any waiver, the Company, the Participating Banks, the Issuing Bank and the Administrative Agent shall be restored to their former positions and rights hereunder and under the other Financing Documents, and any Potential Default or Event of Default waived shall be deemed to be cured and not continuing; no such waiver shall extend to any subsequent or other Potential Default or Event of Default or impair any right consequent thereon.

4. Representations and Warranties.

The Company hereby represents and warrants to the Banks as follows:

(a) The Company has all requisite power and authority, corporate or otherwise, to execute and deliver this Amendment and to perform all of its obligations under this Amendment and under the Reimbursement Agreement as amended hereby. This Amendment has been duly and validly executed and delivered to the Administrative Agent by the Company, and this Amendment, and the Reimbursement Agreement as amended hereby, constitute the legal, valid and binding obligation of the Company, enforceable in accordance with its terms, except that the enforceability thereof may be limited by applicable bankruptcy, insolvency, or other laws affecting the enforcement of creditors' rights generally and by equitable principles.

(b) The execution, delivery and performance of this Amendment, and the performance of the Reimbursement Agreement as amended hereby, have been duly authorized by all necessary action and do not and will not (i) require any authorization, consent or approval by any governmental department, commission, board, bureau, agency or instrumentality, domestic or foreign, (ii) violate the Company's articles of incorporation or bylaws or any provision of any law, rule, regulation or order presently in effect having applicability to the Company, or (iii) result in a breach of or constitute a default under any indenture or agreement to which the Company is a party or by which the Company or its properties may be bound or affected.

(c) All of the representations and warranties contained in Article IV of the Reimbursement Agreement, as amended hereby, are correct on and as of the date hereof as though made on and as of such date, except to the extent that such representations and warranties relate solely to an earlier date.

5. Conditions.

The obligations of the Issuing Bank under Section 2 and the amendments set forth in Section 3 shall be effective only if the Administrative Agent has received, on or before the date hereof (or such later date as the Administrative Agent may agree to in writing), the following, each satisfactory to the Administrative Agent in form and substance:

(a) This Amendment, duly executed by the Company.

(b) A certificate of the secretary or other appropriate officer of the Company (i) certifying that the execution, delivery and performance by the Company of this Amendment, and the performance of the Reimbursement Agreement as amended hereby, have been duly approved by all necessary action of the Company, and attaching true and correct copies of the applicable resolutions granting such approval, (ii) certifying that there have been no amendments to or restatements of the Company's by‑laws and articles of incorporation as furnished to the Administrative Agent in connection with the execution and delivery of the Reimbursement Agreement, other than those that may be attached to the certificate, and (iii) certifying the names of the officers of the Company that are authorized to sign this Amendment, together with the true signatures of such officers.

(c) A certificate of good standing for the Company from the Secretary of State of the State of Minnesota, dated not more than 30 days prior to the date hereof.

(d) A signed copy of an opinion of counsel for the Company, addressed to the Banks, opining as to the matters set forth in Section 4 (other than those in Section 4(c)) and such other matters as any Bank may require.

(e) To the extent requested by the Administrative Agent, payment or reimbursement in full for all reasonable legal fees charged, and all costs and expenses incurred, by counsel for the Banks through the date hereof in connection with the transactions contemplated under this Amendment.

6. Miscellaneous.

The Company shall pay all costs and expenses of the Banks, including attorneys' fees, incurred in connection with the drafting and preparation of this Amendment and any related documents. Except as amended by this Amendment, all of the terms and conditions of the Reimbursement Agreement shall remain in full force and effect. This Amendment may be executed in any number of counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which counterparts of this Amendment, taken together, shall constitute but one and the same instrument. Delivery of an executed counterpart of a signature page to this Amendment by facsimile or by e-mail transmission of a PDF or similar copy shall be equally as effective as delivery of an original executed counterpart of this Amendment. Any party delivering an executed counterpart signature page to this Amendment by facsimile or by e-mail transmission shall also deliver an original executed counterpart of this Amendment but the failure to deliver an original executed counterpart shall not affect the validity, enforceability or binding effect of this Amendment. This Amendment shall be governed by the substantive law of the State of Minnesota.

Signature pages follow

In witness whereof, the parties hereto have executed this Amendment as of the day and year first above written.

ALLETE, INC.



By	/s/ Mark A. Schober
Name:	Mark A. Schober
Title:	Sr. Vice President and CFO

Signature Page for First Amendment to Letter of Credit Agreement

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, as Issuing Bank and as a Participating Bank



By	/s/ Nick Brokke
Name:	Nick Brokke
Title:	Assistant Vice President

Signature Page for First Amendment to Letter of Credit Agreement

Exhibit A

Letter of Credit Amendment

See attached.

Exhibit A-1

Wells Fargo Bank, N.A.

U. S. Trade Services

Standby Letters of Credit

MAC A0195-212

One Front Street, 21^st Floor

San Francisco, CA. 94111

Phone: 1(800) 798-2815 Option 1

E-Mail: sftrade@wellsfargo.com

Amendment To

Irrevocable Standby Letter Of Credit

Number : NZS569069

Amendment Number : 2

Amend Date : June 1, 2013

BENEFICIARY APPLICANT

U.S. BANK NATIONAL ASSOCIATION ALLETE, INC.

ATTENTION: CORP. TRUST DEPT. 30 W. SUPERIOR STREET

60 LIVINGSTON AVENUE ATTN: RICHARD AUSMAN-CASH MGR

ST. PAUL, MINNESOTA 55107 DULUTH, MINNESOTA 55802

LADIES AND GENTLEMEN:

AT THE REQUEST AND FOR THE ACCOUNT OF THE ABOVE REFERENCED APPLICANT, WE HEREBY AMEND OUR IRREVOCABLE STANDBY LETTER OF CREDIT (THE “WELLS CREDIT”) IN YOUR FAVOR AS FOLLOWS:

THE THIRD PARAGRAPH OF THE FIRST PAGE OF OUR LETTER OF CREDIT DATED JULY 5, 2006 IS NOW TO READ:

THIS LETTER OF CREDIT EXPIRES AT OUR LETTER OF CREDIT OPERATIONS OFFICE IN SAN FRANCISCO, CALIFORNIA ON JULY 5, 2014, BUT SHALL BE AUTOMATICALLY EXTENDED, WITHOUT WRITTEN AMENDMENT, TO JULY 5 IN EACH SUCCEEDING CALENDAR YEAR UP TO, BUT NOT BEYOND, JULY 5, 2018 UNLESS YOU HAVE RECEIVED WRITTEN NOTICE FROM US SENT BY EXPRESS COURIER OR REGISTERED MAIL TO YOUR ADDRESS ABOVE, OR BY FACSIMILE TRANSMISSION TO YOUR FAX NUMBER 651-466-7430 (THE “BENEFICIARY FAX NUMBER”), THAT WE ELECT NOT TO EXTEND THIS LETTER OF CREDIT BEYOND THE DATE SPECIFIED IN SUCH NOTICE, WHICH DATE WILL BE A DATE BEFORE JULY 5, 2018. (THE EARLIER OF (I) THE DATE SPECIFIED IN SUCH NOTICE FROM US AND (II) JULY 5, 2018, OR IF SUCH EARLIER DATE IS NOT A BUSINESS DAY THEN THE FIRST (1ST) SUCCEEDING BUSINESS DAY THEREAFTER, WILL BE HEREINAFTER REFERRED TO AS THE "EXPIRATION DATE".) TO BE EFFECTIVE, SUCH NOTICE FROM US MUST BE RECEIVED BY YOU AT LEAST 30 CALENDAR DAYS BEFORE THE EXPIRATION DATE.”

ALL OTHER TERMS AND CONDITIONS REMAIN UNCHANGED.

THIS AMENDMENT IS TO BE ATTACHED TO THE ORIGINAL WELLS CREDIT AND IS AN INTEGRAL PART THEREOF.

Very Truly Yours,

WELLS FARGO BANK, N.A.

By: ________________________________________

Authorized Signature

The original of the Letter of Credit contains an embossed seal over the Authorized Signature.

Exhibit A-2

Please direct any written correspondence or inquiries regarding this Letter of Credit, always quoting our

reference number, to Wells Fargo Bank, National Association, Attn: U.S. Standby Trade Services



at either	One Front Street	or	401 Linden Street
	MAC A0195-212,		MAC D4004-017,
	San Francisco, CA 94111		Winston-Salem, NC 27101

Phone inquiries regarding this credit should be directed to our Standby Customer Connection Professionals



1-800-798-2815 Option 1	1-800-776-3862 Option 2
(Hours of Operation: 8:00 a.m. PT to 5:00 p.m. PT)	(Hours of Operation: 8:00 a.m. EST to 5:30 p.m. EST)

Exhibit A-3

ALE 6-30-2013 EX-10.C

Exhibit 10(c)

Approved by ALLETE Board

of Directors on July 26, 2013

ALLETE and Affiliated Companies

Compensation Recovery Policy

The Board of Directors of the Company (the “Board”) has determined that it is in the best interests of the Company to adopt a Compensation Recovery Policy (“Policy”) that will allow ALLETE (together with its affiliates, the “Company”) to recover incentive payments and other forms of compensation (at the discretion of the Board) from Section 16 Officers in the event of a Financial Restatement, and from Covered Executives in the event of an Error or Misconduct. The Policy is generally effective January 1, 2011 and shall apply to all incentive payments earned on or after that date, and, to the extent required by applicable law, to payments earned before that date.

Definitions

“Administrator” means, with respect to Section 16 Officers, the Executive Compensation Committee of the Board, and with respect to any other Covered Executive, the Company.

“Covered Executive” means an individual who is or was either a Section 16 Officer or an Incentive Plan Participant, or both.

“Dodd-Frank Act” means the Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub. Law No. 111-203, as amended from time to time.

“Error” means a Covered Executive received an incentive award payment based on the attainment of performance criteria, the measurement of which is later determined by the Administrator, in its sole discretion, to be materially inaccurate, without regard to whether the inaccuracy is the result of Misconduct.

“Financial Restatement” means that the Company is or was required to prepare financial restatement due to material non-compliance with any financial reporting requirement under the securities laws of the United States.

“Incentive Plan Participant” means an individual, whether or not an employee at the time of an event triggering this Policy, who is or becomes entitled to receive any payment pursuant to the Company's annual incentive plan, payment on account of an award granted pursuant to the Company's long-term incentive plan, or both.

“Misconduct” means the occurrence of either or both of the following, as determined by the Administrator, in its sole discretion:

(a) an act or omission by the Covered Executive involving dishonesty in connection with his or her responsibilities as an employee of the Company; or

(b) the Covered Executive's conviction of, or entry of a plea of nolo contendere to, any felony or a misdemeanor involving moral turpitude, provided that a misdemeanor motor vehicle violation will not constitute a crime of moral turpitude unless it involves driving while impaired within the scope of employment or another serious driving offense committed within the scope of employment.

Misconduct can occur regardless of whether the Company discovers the Misconduct before or after the Covered Executive's employment with the Company is terminated and regardless of whether the Company terminates the Covered Executive on account of Misconduct.

“Section 16 Officer” means any individual, whether or not an employee at the time of an event triggering this Policy, determined by the Company to be currently or formerly subject to Section 16 of the Securities Exchange Act of 1934.

Administration

The Administrator shall administer this Policy and shall have sole and express discretionary authority to interpret and administer this Policy and to make all determinations with respect to this Policy in its sole discretion. The Administrator may consult with the Board from time to time as the Administrator deems appropriate. All determinations of the Administrator shall be final and binding on all Covered Executives.

Applicability

This Policy applies to all Covered Executives and supplements the provisions on forfeiture or termination of amounts payable under Company plans or agreements. The terms and conditions of any incentive award program under which Covered Executives may receive incentive payments from the Company and each individual award pursuant to any such program shall incorporate the requirements of this Policy.

Events that Permit Recovery

If the Administrator determines, in its sole discretion, that any one or more of the following events has occurred, it may require recovery of amounts from a Covered Executive in accordance with this Policy:

With respect to Section 16 Officers:


•	a Financial Restatement; and

With respect to Covered Executives:


•	Error; and, or


•	Misconduct.

Amount of Recovery

The amount of an incentive payment subject to forfeiture or recovery on account of and upon Financial Restatement, with respect to Section 16 Officers, or an Error, with respect to Covered Executives, shall be the amount of the incentive payment to the individual in excess of the amount that would have been paid (or if no amount would have been paid, the entire amount) according to the restated financial statements or the corrected performance metric criteria or other Error. The right to recovery shall apply to incentive payments that were received during the three years prior to the date on which the Company is required to prepare a Financial Restatement or the Company discovers an Error, as applicable.

The amount subject to forfeiture or recovery on account of and upon Misconduct shall be the entire amount of any incentive payment or bonus that is attributable to, or relates to, the period during which the Misconduct occurred and any subsequent period, regardless of when the incentive payment or bonus is or was earned and paid.

In addition, the Administrator may equitably adjust or recover from a Covered Executive, the amount of any other payment the amount of which is based in whole or in part on an incentive award payment forfeited or recovered pursuant to this Policy.

Sources of Repayment

If the Administrator determines that a Covered Executive must repay any amounts to the Company, the Administrator may, in its sole discretion, authorize the reduction of future payments or seek repayment or return of prior payments to the Covered Executive at the time and in the form specified by the Administrator. Without limiting the foregoing, the Company shall have the right to withhold any such repayment amount from any compensation otherwise payable to the Covered Executive, including but not limited to unpaid incentive payments, executive retirement benefits and elective and non-elective deferrals under the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan and The ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II, wages or any other amounts payable by the Company to the Covered Executive. All actions by the Company to recover incentive payments or other compensation shall be taken in accordance with applicable law.

Notice

The Company shall take all appropriate steps to inform Covered Executives of this Policy, so that such Policy shall be enforceable to the fullest extent legally permissible. These steps may include, but not be limited to providing that this Policy shall be acknowledged by Covered Executives, and incorporating the terms of this policy into the terms of any incentive plan or incentive award agreement applicable to Covered Executives. In addition, the Company shall take all appropriate steps to disclose this policy in accordance with the requirements of the Dodd-Frank Act.

Coordination with Law

This policy is designed, and shall be interpreted, to comply with section 954 of the Dodd-Frank Act, and Section 10D of the Securities Exchange Act of 1934, as amended, and, in each case, any regulations promulgated with respect thereto, and in the event that any provision of this Policy is inconsistent with any requirement of the Dodd-Frank Act or any interpretive regulations issued thereunder, the Administrator shall administer this Policy to comply with the Dodd-Frank Act and the regulations. In addition, the Administrator shall have the authority to amend this Policy at any time as the Administrator deems necessary or appropriate, in its sole discretion, to comply with the requirements of the Dodd-Frank Act and the regulations.

General Rights

This Policy shall not limit the rights of the Company to take any other actions or pursue other remedies that the Company may deem appropriate under the circumstances and under applicable law.

This Policy may be amended from time to time by the Board.

ALE 6-30-2013 EX-31.A

Exhibit 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

I, Alan R. Hodnik, of ALLETE, Inc. (ALLETE), certify that:


1.	I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2013, of ALLETE;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: August 1, 2013		/s/ Alan R. Hodnik
		Alan R. Hodnik
		Chairman, President and Chief Executive Officer

ALE 6-30-2013 EX-31.B

Exhibit 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

I, Mark A. Schober, of ALLETE, Inc. (ALLETE), certify that:


1.	I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2013, of ALLETE;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: August 1, 2013		/s/ Mark A. Schober
		Mark A. Schober
		Senior Vice President and Chief Financial Officer

ALE 6-30-2013 EX-32

Exhibit 32

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

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, each of the undersigned officers of ALLETE, Inc. (ALLETE), does hereby certify that:


1.	The Quarterly Report on Form 10-Q of ALLETE for the period ended June 30, 2013, (Report) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and


2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of ALLETE.



Date: August 1, 2013
		/s/ Alan R. Hodnik
		Alan R. Hodnik
		Chairman, President and Chief Executive Officer



Date: August 1, 2013
		/s/ Mark A. Schober
		Mark A. Schober
		Senior Vice President and Chief Financial Officer

This certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to liability pursuant to that section. Such certification shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that ALLETE specifically incorporates it by reference.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ALLETE and will be retained by ALLETE and furnished to the Securities and Exchange Commission or its staff upon request.

ALE 6-30-2013 EX-95

Exhibit 95

Mine Safety Disclosure

Mine or Operating Name/MSHA Identification Number

Section 104 S&S Citations (#)

Section 104(b) Orders (#)

Section 104(d) Citations and Orders (#)

Section 110(b)(2) Violations (#)

Section 107(a) Orders (#)

Total Dollar Value of MSHA Assessments Proposed ($)

Total Number of Mining Related Fatalities (#)

Received Notice of Pattern of Violation Under Section 104(e) (yes/no)

Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)

Legal Actions Pending as of Last Day of Period (#)

Legal Actions Initiated During Period (#)

Legal Actions Resolved During Period (#)

Center Mine / 3200218

—

599

—

For the quarter ended June 30, 2013, BNI Coal, owner of Center Mine, received two citations under Section 104(a) of the Mine Safety Act, one of which was a significant and substantial (S&S) citation. The total penalties assessed on BNI with respect to the two citations were $599. For the quarter ended June 30, 2013, there were no citations, orders, violations or notices under Sections 104(b), 104(d), 107(a), 104(e) or 110(b)(2) of the Mine Safety Act and there were no fatalities.

ALE 6-30-2013 EX-99



		Exhibit 99
	For Release:	August 1, 2013
	Investor Contact:	Tim Thorp
		218-723-3953
		tthorp@allete.com

NEWS

ALLETE reports second quarter earnings and reaffirms guidance

Industrial demand nominations strong for remainder of 2013

DULUTH, Minn. - ALLETE, Inc. (NYSE:ALE) today reported second quarter 2013 earnings of 35 cents per share on net income of $14.0 million and operating revenue of $235.6 million, compared to 39 cents per share on net income of $14.4 million and operating revenue of $216.4 million in 2012.

ALLETE's Regulated Operations segment, which includes Minnesota Power, Superior Water, Light and Power and the company's investment in the American Transmission Company, recorded net income of $16.3 million versus $14.4 million in 2012.

Second quarter 2013 results were impacted by several factors attributable to Minnesota Power's recent capital investments. Higher revenue from renewable energy investments and federal production tax credits were partially offset by increases in depreciation and interest expense. In late 2012, Minnesota Power completed two phases of the Bison Wind Energy Center and both have been in service during 2013. Total electric sales also rose 2.2 percent compared to a year ago.

“Industrial demand for power remains strong,” said ALLETE Chairman, President and CEO Al Hodnik. “Based on demand nominations received from our largest power users this week, these customers expect to run at full-capacity for the remainder of the year.”

ALLETE's Investments and Other segment, which includes results from BNI Coal, ALLETE Properties, ALLETE Clean Energy, and other miscellaneous income and expense, recorded a $2.3 million net loss during the quarter, versus a break-even quarter a year ago. Higher state income tax and interest expense contributed to the variance from the second quarter in 2012. State income tax expense was higher in 2013 as more North Dakota income tax credits attributable to our North Dakota capital investments were recognized in 2012.

Year-to-date financial results included 2013 earnings of $1.18 per share on net income of $46.5 million and operating revenue of $499.4 million, compared to $1.05 per share on net income of $38.8 million and operating revenue of $456.4 million in 2012. An increase from a year ago in the average number of common stock shares outstanding, with proceeds used to fund the company's capital investment program, resulted in dilution of seven cents per share.

“The year-to-date results are right where we expected them to be,” Hodnik said. “The company's full year earnings guidance remains unchanged, in an expected range of between $2.58 and $2.78 per share.” He said 2013 guidance assumes continued strong industrial demand for electricity, higher cost recovery rider revenue and federal production tax credits, higher operating and maintenance, depreciation and interest expenses, and dilution from equity issuances of between $0.10 and $0.15 per share.

The company will host a conference call and webcast at 10 a.m. Eastern time today to discuss details of its quarterly performance. Interested parties may listen live by calling (877) 303-5852, or by accessing the webcast at www.allete.com. A replay of the call will be available through August 4, 2013 by dialing (855) 859-2056, pass code 99389011.

ALLETE is an energy company headquartered in Duluth, Minn. In addition to its electric utilities, Minnesota Power and Superior Water, Light and Power of Wisconsin, ALLETE owns BNI Coal in Center, N.D., ALLETE Clean Energy, based in Duluth, and has an eight percent equity interest in the American Transmission Co. More information about ALLETE is available at www.allete.com.

The statements contained in this release and statements that ALLETE may make orally in connection with this release that are not historical facts, are forward-looking statements. Actual results may differ materially from those projected in the forward-looking statements. These forward-looking statements involve risks and uncertainties and investors are directed to the risks discussed in documents filed by ALLETE with the Securities and Exchange Commission.

ALLETE's press releases and other communications may include certain non-Generally Accepted Accounting Principles (GAAP) financial measures. A "non-GAAP financial measure" is defined as a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP in the company's financial statements.

Non-GAAP financial measures utilized by the Company include presentations of earnings (loss) per share. ALLETE's management believes that these non-GAAP financial measures provide useful information to investors by removing the effect of variances in GAAP reported results of operations that are not indicative of changes in the fundamental earnings power of the Company's operations. Management believes that the presentation of the non-GAAP financial measures is appropriate and enables investors and analysts to more accurately compare the company's ongoing financial performance over the periods presented.

ALLETE, Inc.

Consolidated Statement of Income

Millions Except Per Share Amounts - Unaudited



	Quarter Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012

Operating Revenue	$235.6		$216.4		$499.4		$456.4

Operating Expenses
Fuel and Purchased Power	78.7		72.1		165.2		149.2
Operating and Maintenance	103.8		96.2		208.5		196.1
Depreciation	28.7		24.8		56.9		49.4
Total Operating Expenses	211.2		193.1		430.6		394.7

Operating Income	24.4		23.3		68.8		61.7

Other Income (Expense)
Interest Expense	(12.8	)	(10.1	)	(25.1	)	(21.1	)
Equity Earnings in ATC	5.0		4.8		10.2		9.4
Other	1.5		1.2		4.2		1.9
Total Other Expense	(6.3	)	(4.1	)	(10.7	)	(9.8	)

Income Before Income Taxes	18.1		19.2		58.1		51.9
Income Tax Expense	4.1		4.8		11.6		13.1
Net Income	$14.0		$14.4		$46.5		$38.8

Average Shares of Common Stock
Basic	39.4		37.3		39.2		37.0
Diluted	39.6		37.4		39.3		37.1

Basic Earnings Per Share of Common Stock	$0.36		$0.39		$1.19		$1.05
Diluted Earnings Per Share of Common Stock	$0.35		$0.39		$1.18		$1.05

Dividends Per Share of Common Stock	$0.475		$0.46		$0.95		$0.92

Consolidated Balance Sheet

Millions - Unaudited



	Jun. 30,	Dec. 31,		Jun. 30,	Dec. 31,
	2013	2012		2013	2012
Assets			Liabilities and Shareholders’ Equity
Cash and Cash Equivalents	$145.0	$80.8	Current Liabilities	$193.1	$283.4
Other Current Assets	175.9	192.4	Long-Term Debt	1,064.7	933.6
Property, Plant and Equipment - Net	2,397.2	2,347.6	Deferred Income Taxes	435.5	423.8
Regulatory Assets	337.5	340.3	Regulatory Liabilities	63.1	60.1
Investment in ATC	111.2	107.3	Defined Benefit Pension & Other Postretirement Benefit Plans	216.2	228.2
Other Investments	140.2	143.5	Other Non-Current Liabilities	129.3	123.3
Other Non-Current Assets	43.9	41.5	Shareholders’ Equity	1,249.0	1,201.0
Total Assets	$3,350.9	$3,253.4	Total Liabilities and Shareholders’ Equity	$3,350.9	$3,253.4



	Quarter Ended		Six Months Ended
ALLETE, Inc.	June 30,		June 30,
Income (Loss)	2013	2012	2013		2012
Millions
Regulated Operations	$16.3	$14.4	$48.4		$38.8
Investments and Other	(2.3)	—	(1.9	)	—
Net Income Attributable to ALLETE	$14.0	$14.4	$46.5		$38.8
Diluted Earnings Per Share	$0.35	$0.39	$1.18		$1.05



Statistical Data
Corporate
Common Stock
High	$52.25	$41.99	$52.25	$42.49
Low	$46.85	$38.03	$41.39	$38.03
Close	$49.85	$41.80	$49.85	$41.80
Book Value	$31.12	$29.24	$31.12	$29.24



Kilowatt-hours Sold
Millions
Regulated Utility
Retail and Municipals
Residential	251	226	605	552
Commercial	335	326	712	690
Municipals	225	234	499	498
Industrial	1,769	1,842	3,614	3,710
Total Retail and Municipal	2,580	2,628	5,430	5,450
Other Power Suppliers	610	492	1,201	1,009
Total Regulated Utility	3,190	3,120	6,631	6,459
Non-regulated Energy Operations	33	25	64	55
Total Kilowatt-hours Sold	3,223	3,145	6,695	6,514



Regulated Utility Revenue
Millions
Regulated Utility Revenue
Retail and Municipals
Residential	$23.2	$20.5	$56.2	$49.9
Commercial	27.5	24.7	58.8	51.9
Municipals	15.8	13.9	32.4	31.3
Industrial	95.4	93.5	197.6	191.3
Total Retail and Municipals	161.9	152.6	345.0	324.4
Other Power Suppliers	22.4	17.7	44.7	36.4
Other	31.5	26.7	67.5	54.8
Total Regulated Utility Revenue	$215.8	$197.0	$457.2	$415.6

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.