ALE 6-30-2014 10-Q



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
ATC	American Transmission Company LLC
Bison Wind Energy Center	Bison 1, 2 & 3 Wind Facilities
Bison 4	Bison 4 Wind Project
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
GNTL	Great Northern Transmission Line
IBEW	International Brotherhood of Electrical Workers
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
Item ___	Item ___ of this Form 10-Q
kV	Kilovolt(s)
kWh	Kilowatt-hour
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
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.
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



Abbreviation or Acronym	Term
NOL	Net Operating Loss
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
Thomson	Thomson 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

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:

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 28 of ALLETE’s Annual Report on Form 10-K for the year ended December 31, 2013. 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.



	June 30, 2014			December 31, 2013

Assets
Current Assets
Cash and Cash Equivalents		$83.6			$97.3
Accounts Receivable (Less Allowance of $1.1 and $1.1)	78.9			96.3
Inventories	75.3			59.3
Prepayments and Other	32.2			35.1
Deferred Income Taxes	23.5			19.0
Total Current Assets	293.5			307.0
Property, Plant and Equipment - Net	3,020.4			2,576.5
Regulatory Assets	270.8			263.8
Investment in ATC	118.8			114.6
Other Investments	116.7			146.3
Other Non-Current Assets	75.4			68.6
Total Assets		$3,895.6			$3,476.8
Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable		$93.2			$99.9
Accrued Taxes	30.9			34.8
Accrued Interest	17.4			15.7
Long-Term Debt Due Within One Year	10.8			27.2
Other	61.1			52.6
Total Current Liabilities	213.4			230.2
Long-Term Debt	1,316.8			1,083.0
Deferred Income Taxes	496.3			479.1
Regulatory Liabilities	100.1			81.0
Defined Benefit Pension and Other Postretirement Benefit Plans	117.0			133.4
Other Non-Current Liabilities	234.5			127.2
Total Liabilities	2,478.1			2,133.9
Commitments, Guarantees and Contingencies (Note 15)
Equity
ALLETE’s Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 42.6 and 41.4 Shares Outstanding	945.1			885.2
Unearned ESOP Shares	(10.5		)	(14.3		)
Accumulated Other Comprehensive Loss	(16.3		)	(17.1		)
Retained Earnings	497.7			489.1
Total ALLETE Equity	1,416.0			1,342.9
Non-Controlling Interest in Subsidiaries	1.5			—
Total Equity	1,417.5			1,342.9
Total Liabilities and Equity		$3,895.6			$3,476.8



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013

Operating Revenue		$260.7			$235.6			$557.2			$499.4
Operating Expenses
Fuel and Purchased Power	83.6			78.7			179.8			165.2
Operating and Maintenance	115.1			103.8			234.9			208.5
Depreciation	33.8			28.7			66.0			56.9
Total Operating Expenses	232.5			211.2			480.7			430.6
Operating Income	28.2			24.4			76.5			68.8
Other Income (Expense)
Interest Expense	(13.5		)	(12.8		)	(26.3		)	(25.1		)
Equity Earnings in ATC	5.2			5.0			10.3			10.2
Other	1.9			1.5			3.9			4.2
Total Other Expense	(6.4		)	(6.3		)	(12.1		)	(10.7		)
Income Before Non-Controlling Interest and Income Taxes	21.8			18.1			64.4			58.1
Income Tax Expense	4.9			4.1			13.7			11.6
Net Income	16.9			14.0			50.7			46.5
Less: Non-Controlling Interest in Subsidiaries	0.1			—			0.4			—
Net Income Attributable to ALLETE		$16.8			$14.0			$50.3			$46.5
Average Shares of Common Stock
Basic	42.1			39.4			41.7			39.2
Diluted	42.3			39.6			41.9			39.3
Basic Earnings Per Share of Common Stock		$0.40			$0.36			$1.21			$1.19
Diluted Earnings Per Share of Common Stock		$0.40			$0.35			$1.20			$1.18
Dividends Per Share of Common Stock		$0.49			$0.475			$0.98			$0.95



	Quarter Ended				Six Months Ended
	June 30,				June 30,
Comprehensive Income	2014		2013		2014		2013
Millions
Net Income		$16.9		$14.0		$50.7		$46.5
Other Comprehensive Income
Unrealized Gain on Securities
Net of Income Taxes of $0.1, $0.1, $0.1, and $0.1	0.2		0.1		0.2		0.1
Unrealized Gain on Derivatives
Net of Income Taxes of $–, $0.1, $0.1, and $0.1	—		—		—		0.1
Defined Benefit Pension and Other Postretirement Benefit Plans
Net of Income Taxes of $0.2, $0.3, $0.4, and $0.5	0.3		0.5		0.6		0.8
Total Other Comprehensive Income	0.5		0.6		0.8		1.0
Total Comprehensive Income	17.4		14.6		51.5		47.5
Less: Non-Controlling Interest in Subsidiaries	0.1		—		0.4		—
Comprehensive Income Attributable to ALLETE		$17.3		$14.6		$51.1		$47.5



	Six Months Ended
	June 30,
	2014			2013

Operating Activities
Net Income		$50.7			$46.5
Allowance for Funds Used During Construction – Equity	(3.8		)	(2.1		)
Income from Equity Investments, Net of Dividends	(1.9		)	(2.3		)
Gains on Sale of Assets / Investments	(0.2		)	(0.9		)
Depreciation Expense	66.0			56.9
Amortization of Debt Issuance Costs	0.5			0.5
Deferred Income Tax Expense	13.6			11.6
Share-Based Compensation Expense	1.4			1.3
ESOP Compensation Expense	4.5			4.0
Defined Benefit Pension and Postretirement Benefit Expense	6.4			11.2
Bad Debt Expense	0.6			0.4
Changes in Operating Assets and Liabilities
Accounts Receivable	21.0			9.9
Inventories	(12.9		)	(1.2		)
Prepayments and Other	7.0			7.4
Accounts Payable	(11.0		)	(10.1		)
Other Current Liabilities	(9.7		)	(5.8		)
Cash Contributions to Defined Benefit Pension and Other Postretirement Benefit Plans	—			(10.8		)
Changes in Regulatory and Other Non-Current Assets	(11.5		)	(8.0		)
Changes in Regulatory and Other Non-Current Liabilities	5.4			2.6
Cash from Operating Activities	126.1			111.1
Investing Activities
Proceeds from Sale of Available-for-sale Securities	2.7			8.1
Payments for Purchase of Available-for-sale Securities	(3.4		)	(1.4		)
Investment in ATC	(2.3		)	(1.6		)
Changes to Other Investments	30.6			(2.6		)
Additions to Property, Plant and Equipment	(333.9		)	(128.6		)
Acquisition – Net of Cash Acquired	(23.1		)	—
Changes in Restricted Cash	6.0			—
Proceeds from Sale of Assets	—			0.9
Cash for Investing Activities	(323.4		)	(125.2		)
Financing Activities
Proceeds from Issuance of Common Stock	38.9			33.3
Proceeds from Issuance of Long-Term Debt	215.0			150.0
Reductions of Long-Term Debt	(20.8		)	(65.5		)
Debt Issuance Costs	(1.8		)	(1.3		)
Acquisition of Non-Controlling Interest	(6.0		)	—
Dividends on Common Stock	(41.7		)	(38.2		)
Cash from Financing Activities	183.6			78.3
Change in Cash and Cash Equivalents	(13.7		)	64.2
Cash and Cash Equivalents at Beginning of Period	97.3			80.8
Cash and Cash Equivalents at End of Period		$83.6			$145.0

The accompanying notes are an integral part of these 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, 2013, 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, 2014, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2014. For further information, refer to the consolidated financial statements and notes included in our 2013 Form 10-K.

Other Non-Current Assets. As of June 30, 2014, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $4.9 million related to ALLETE Clean Energy’s wind energy facilities debt service and other requirements. As of December 31, 2013, the Company had restricted cash of $5.4 million related to cash held in escrow pending the closing of the wind energy facilities acquisition, which was completed on January 30, 2014 (see Note 4. Acquisition).



For the Six Months Ended June 30,	2014		2013
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$23.7		$22.8
Cash Paid During the Period for Income Taxes		$0.2		$0.6
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment		$3.6	$(28.2)
Capitalized Asset Retirement Costs		$0.6		$1.9
AFUDC – Equity		$3.8		$2.1
ALLETE Common Stock Contributed to the Pension Plan		$19.5	—

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, the FASB issued an accounting standard update on the financial statement presentation of unrecognized tax benefits when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward. To the extent an NOL carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from the disallowance of a tax position or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This guidance was adopted in the first quarter of 2014, and did not have a material impact on our consolidated financial position, results of operations, or cash flows.

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. In April 2014, the FASB issued an accounting standard update modifying the criteria for determining which disposals should be presented as discontinued operations and modifying the related disclosure requirements. Additionally, the new guidance requires that a business which qualifies as held for sale upon acquisition should be reported as discontinued operations. The new guidance will be effective beginning in the first quarter of 2015, and applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. This guidance is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

Revenue from Contracts with Customers. In May 2014, the FASB issued amended revenue recognition guidance to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This accounting guidance is effective for the Company beginning in the first quarter of 2017 using one of two prescribed retrospective methods. Early adoption is not permitted for public companies. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s consolidated financial statements.

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 which acquired three wind energy facilities in January 2014, and is 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, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended June 30, 2014
Operating Revenue		$260.7			$229.6			$31.1
Fuel and Purchased Power Expense	83.6			83.6			—
Operating and Maintenance Expense	115.1			89.0			26.1
Depreciation Expense	33.8			29.6			4.2
Operating Income	28.2			27.4			0.8
Interest Expense	(13.5		)	(11.4		)	(2.1		)
Equity Earnings in ATC	5.2			5.2			—
Other Income (Expense)	1.9			2.0			(0.1		)
Income (Loss) Before Non-Controlling Interest and Income Taxes	21.8			23.2			(1.4		)
Income Tax Expense (Benefit)	4.9			5.7			(0.8		)
Net Income (Loss)	16.9			17.5			(0.6		)
Less: Non-Controlling Interest in Subsidiaries	0.1			—			0.1
Net Income (Loss) Attributable to ALLETE		$16.8			$17.5		$(0.7)

	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 Non-Controlling Interest and 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		)
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income (Loss) Attributable to ALLETE		$14.0			$16.3		$(2.3)



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Six Months Ended June 30, 2014
Operating Revenue		$557.2			$493.8			$63.4
Fuel and Purchased Power Expense	179.8			179.8			—
Operating and Maintenance Expense	234.9			179.2			55.7
Depreciation Expense	66.0			58.4			7.6
Operating Income	76.5			76.4			0.1
Interest Expense	(26.3		)	(22.9		)	(3.4		)
Equity Earnings in ATC	10.3			10.3			—
Other Income	3.9			3.8			0.1
Income (Loss) Before Non-Controlling Interest and Income Taxes	64.4			67.6			(3.2		)
Income Tax Expense (Benefit)	13.7			16.2			(2.5		)
Net Income (Loss)	50.7			51.4			(0.7		)
Less: Non-Controlling Interest in Subsidiaries	0.4			—			0.4
Net Income (Loss) Attributable to ALLETE		$50.3			$51.4		$(1.1)

As of June 30, 2014
Total Assets		$3,895.6			$3,424.3			$471.3
Property, Plant and Equipment – Net		$3,020.4			$2,791.7			$228.7
Accumulated Depreciation		$1,288.9			$1,221.1			$67.8
Capital Additions		$341.7			$335.6			$6.1



	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 Non-Controlling Interest and 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		)
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income (Loss) Attributable to ALLETE		$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

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, 2014 (none for the year ended December 31, 2013).

Long-Term Finance Receivables. As of June 30, 2014, long-term finance receivables were $1.4 million net of an allowance ($1.4 million net of an allowance as of December 31, 2013). 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, 2014, we had an allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2013).

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake) and Condon, Oregon (Condon) from The AES Corporation (AES) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015. The acquisition supports ALLETE’s strategy to pursue energy-centric initiatives through ALLETE Clean Energy that include less carbon intensive and more sustainable energy sources.

Lake Benton, Storm Lake and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake began commercial operations in 1998, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032 (see Note 15. Commitments, Guarantees and Contingencies). Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility in June 2015. Armenia Mountain began operations in 2009.

ALLETE Clean Energy acquired a controlling interest in the limited liability company (LLC) which owns Lake Benton and Storm Lake, and a controlling interest in the LLC that owns Condon. The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as shown in the table below. During the second quarter of 2014, the Company recorded minor adjustments to certain assets and liabilities. The result of these adjustments had no impact on the results of operations for the period ended June 30, 2014. Fair value measurements were valued primarily using the discounted cash flow method.



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	14.3
Property, Plant and Equipment – Net	156.9
Other Non-Current Assets (a)	7.5
Total Assets Acquired		$182.5
Liabilities Assumed
Other Current Liabilities (b)		$15.2
Long-Term Debt Due Within One Year	2.2
Long-Term Debt	21.1
Power Purchase Agreements	99.4
Other Non-Current Liabilities	10.6
Non-Controlling Interest (c)	7.1
Total Liabilities and Non-Controlling Interest Assumed	155.6
Net Identifiable Assets Acquired		$26.9

ALLETE Clean Energy incurred $1.4 million after-tax of acquisition-related costs during the first quarter of 2014, which were expensed when incurred and were recorded in Other Expenses on the Consolidated Statement of Income. The results of operations of this business from its acquisition date are included in the Investments and Other segment. The pro forma impact of this acquisition was not significant to the results of the Company for the six months ended June 30, 2014 or June 30, 2013.

We have two variable-to-fixed interest rate swaps (Swaps), designated as cash flow hedges, in order to manage the interest rate risk associated with a $75.0 million Term Loan which represents approximately 6 percent of the Company’s outstanding long-term debt as of June 30, 2014. (See Note 9. Short-Term and Long-Term Debt.) The Swaps have effective dates of August 25, 2011, and 2014, and mature on August 26, 2014 and August 25, 2015, respectively. The Swaps involve the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreements at 0.825 percent and 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swaps are expected to be highly effective. If it is determined the Swaps cease to be effective, we will prospectively discontinue hedge accounting. When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessments of hedge effectiveness resulted in no ineffectiveness recorded for the quarter and six months ended June 30, 2014. As of June 30, 2014, the fair value of the Swaps was a $0.5 million liability ($0.6 million liability as of December 31, 2013) of which $0.4 million ($0.3 million as of December 31, 2013) was included in Other Non-Current Liabilities and $0.1 million ($0.3 million as of December 31, 2013) was included in Other Current Liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swaps were recorded in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet. Cash flows from the Swaps are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in Other Comprehensive Income related to the Swaps will be recorded in earnings when the hedged transactions occur or when it is probable they will not occur. Gains or losses on the interest rate hedging transactions are reflected as a component of Interest Expense on the Consolidated Statement of Income.

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 10. Fair Value to the consolidated financial statements in our 2013 Form 10-K.

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014, and December 31, 2013. 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 is excluded from the recurring fair value measures in the tables below.



	Fair Value as of June 30, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.4	—		—		$8.4
Available-for-sale – Corporate Debt Securities	—			$10.5	—	10.5
Cash Equivalents	3.4		—		—	3.4
Total Fair Value of Assets		$11.8		$10.5	—		$22.3

Liabilities:
Deferred Compensation (b)	—			$17.8	—		$17.8
Derivatives – Interest Rate Swap (c)	—		0.5		—	0.5
Total Fair Value of Liabilities	—			$18.3	—		$18.3
Total Net Fair Value of Assets (Liabilities)		$11.8	$(7.8)		—		$4.0



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.9	—		—		$7.9
Available-for-sale – Corporate Debt Securities	—			$9.8	—	9.8
Cash Equivalents	34.2		—		—	34.2
Total Fair Value of Assets		$42.1		$9.8	—		$51.9

Liabilities:
Deferred Compensation (b)	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap (c)	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$17.4	—		$17.4
Total Net Fair Value of Assets (Liabilities)		$42.1	$(7.6)		—		$34.5

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota. SWL&P, a wholly-owned subsidiary of ALLETE, is a private utility in Wisconsin and also a customer of Minnesota Power. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. The electric service agreements with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these agreements 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 formula-based rate 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 Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to July 1, 2023. Under the agreements with the remaining 15 municipal customers and SWL&P, no termination notices may be given prior to June 30, 2016.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor 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. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates.

Renewable Cost Recovery Rider. The Bison Wind Energy Center in North Dakota currently consists of 292 MW of nameplate capacity and was completed in various phases through 2012. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in a December 2013 order. Construction of Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center, commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $246.6 million was spent through June 30, 2014. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We included Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in a filing on April 29, 2014, which, upon approval, will authorize updated rates to be included on customer bills.

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which 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. Significant elements of the “EnergyForward” plan include major wind investments in North Dakota, installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in 2015 and retiring Taconite Harbor Unit 3 in 2015.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with 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 approximately $300 million. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. Intervenors have appealed this order and the Company has filed a response to the appeal. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014.

Great Northern Transmission Line (GNTL). Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500 kV transmission line, between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined that the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction is anticipated to begin in 2016, and to be completed in 2020.

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. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable commission or over the corresponding period related to the asset or liability.



Regulatory Assets and Liabilities	June 30, 2014		December 31, 2013
Millions
Current Regulatory Assets (a)
Deferred Fuel		$20.3		$23.0
Total Current Regulatory Assets	20.3		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	161.6		164.1
Income Taxes	36.6		35.3
Asset Retirement Obligations	17.4		16.0
Cost Recovery Riders (c)	45.7		39.6
PPACA Income Tax Deferral	5.0		5.0
Other	4.5		3.8
Total Non-Current Regulatory Assets	270.8		263.8
Total Regulatory Assets		$291.1		$286.8

Non-Current Regulatory Liabilities
Income Taxes		$17.3		$17.0
Plant Removal Obligations	21.5		19.7
Wholesale and Retail Contra AFUDC	30.1		19.7
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	15.5		16.3
Other	15.7		8.3
Total Non-Current Regulatory Liabilities		$100.1		$81.0

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, 2014, our equity investment in ATC was $118.8 million ($114.6 million at December 31, 2013). In the first six months of 2014, we invested $2.3 million in ATC, and on July 30, 2014, we invested an additional $0.8 million. We expect to make additional investments of approximately $2.7 million in 2014 to maintain our current ownership of ATC.

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized return on equity is 12.2%. Any change to ATC's return on equity and capital structure could result in lower equity earnings in ATC and dividends from ATC in the future. We own approximately 8 percent of ATC and estimate that for every 50 basis point reduction in ATC’s allowed return on equity our equity earnings in ATC would be impacted annually by approximately $0.5 million on an after-tax basis.

Long-Term Debt. As of June 30, 2014, total long-term debt outstanding was $1,316.8 million ($1,083.0 million as of December 31, 2013). In conjunction with ALLETE Clean Energy’s January 30, 2014 wind energy facilities acquisition, ALLETE Clean Energy assumed $23.3 million of long-term debt, including $2.2 million due within one year (see Note 4. Acquisition). Subsequent to June 30, 2014, we redeemed $111.0 million of pollution control bonds, at par, which were due on July 1, 2022.

The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision; however, each series of bonds is redeemable at par, including, in each case, accrued and unpaid interest, six months prior to the maturity date. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company intends to use the proceeds from the sale of the Bonds to refinance debt, fund utility capital expenditures 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 institutional accredited investors.

On June 27, 2014, we agreed to sell $160.0 million of the Company's first mortgage bonds (September Bonds) to certain institutional buyers in the private placement market. The September Bonds will be sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The September Bonds will be issued on or about September 16, 2014, in three series as follows:

The Company has the option to prepay all or a portion of the September Bonds at its discretion, subject to a make-whole provision; however, each series of bonds is redeemable at par, including, in each case, accrued and unpaid interest, six months prior to the maturity date. The September Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company intends to use the proceeds from the sale of the September Bonds to fund utility capital expenditures and/or for general corporate purposes.

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, 2014, our ratio was approximately 0.48 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, 2014, ALLETE was in compliance with its financial covenants.



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Millions
Current Tax Expense (Benefit)
Federal (a)	—			$(0.2)			—			—
State (a)	$0.1			—			$0.1			—
Total Current Tax Expense (Benefit)	$0.1			$(0.2)			$0.1			—
Deferred Tax Expense (Benefit)
Federal		$2.9			$3.6			$9.2			$8.2
State	2.0			0.9			4.7			3.8
Investment Tax Credit Amortization	(0.1		)	(0.2		)	(0.3		)	(0.4		)
Total Deferred Tax Expense	4.8			4.3			13.6			11.6
Total Income Tax Expense		$4.9			$4.1			$13.7			$11.6

Uncertain Tax Positions. As of June 30, 2014, we had gross unrecognized tax benefits of $1.2 million ($1.2 million as of December 31, 2013). Of the total gross unrecognized tax benefits, $0.2 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. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. The regulations are generally effective for tax years beginning January 1, 2014. As ALLETE has adopted certain utility-specific guidance for deductible repairs previously issued by the IRS, the final regulation did not have a material impact on our consolidated financial statements.



	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
For the Quarter Ended June 30, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.4)	$(0.3)	$(16.8)
Other Comprehensive Income Before Reclassifications	0.3		—	—	0.3
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(0.1	)	0.3	—	0.2
Net Other Comprehensive Income	0.2		0.3	—	0.5
Ending Accumulated Other Comprehensive Income (Loss)	$0.1		$(16.1)	$(0.3)	$(16.3)

For the Quarter Ended June 30, 2013
Beginning Accumulated Other Comprehensive Loss	$(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 Accumulated Other Comprehensive Loss	—		$(20.7)	$(0.3)	$(21.0)



	Quarter Ended		Quarter Ended
Amount Reclassified from Accumulated Other Comprehensive Income (Loss)	June 30,		June 30,
	2014		2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	$0.2		—
Income Taxes (b)	(0.1	)	—
Total, Net of Income Taxes	$0.1		—

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.1		$0.7
Actuarial Gains and Losses (c)	(0.6	)	(5.8	)
Total	(0.5	)	(5.1	)
Income Taxes (b)	0.2		2.0
Total, Net of Income Taxes	$(0.3)		$(3.1)
Total Reclassifications	$(0.2)		$(3.1)



	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items		Gains and Losses on Cash Flow Hedge	Total
Millions
For the Six Months Ended June 30, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)		$(0.3)	$(17.1)
Other Comprehensive Income Before Reclassifications	0.3		—		—	0.3
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(0.1	)	0.6		—	0.5
Net Other Comprehensive Income	0.2		0.6		—	0.8
Ending Accumulated Other Comprehensive Income (Loss)	$0.1		$(16.1)		$(0.3)	$(16.3)

For the Six Months Ended June 30, 2013
Beginning Accumulated Other Comprehensive Loss	$(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 Accumulated Other Comprehensive Loss	—		$(20.7)		$(0.3)	$(21.0)



	Six Months Ended		Six Months Ended
Amount Reclassified from Accumulated Other Comprehensive Income (Loss)	June 30,		June 30,
	2014		2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	$0.2		$0.8
Income Taxes (b)	(0.1	)	(0.3	)
Total, Net of Income Taxes	$0.1		$0.5

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.2		$1.2
Actuarial Gains and Losses (c)	(1.2	)	(11.5	)
Total	(1.0	)	(10.3	)
Income Taxes (b)	0.4		4.0
Total, Net of Income Taxes	$(0.6)		$(6.3)
Total Reclassifications	$(0.5)		$(5.8)

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units, performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below). For the quarters and six months ended June 30, 2014 and 2013, zero options to purchase shares of common stock were excluded from the computation of diluted earnings per share.



			2014					2013
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 Attributable to ALLETE		$16.8			$16.8		$14.0			$14.0
Average Common Shares	42.1		0.2	42.3		39.4		0.2	39.6
Earnings Per Share		$0.40			$0.40		$0.36			$0.35
For the Six Months Ended June 30,
Net Income Attributable to ALLETE		$50.3			$50.3		$46.5			$46.5
Average Common Shares	41.7		0.2	41.9		39.2		0.1	39.3
Earnings Per Share		$1.21			$1.20		$1.19			$1.18

Forward Sale Agreement and Issuance of Common Stock. On February 26, 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with our capital investment strategy.

Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock (borrowed shares) from third parties and sold them to the underwriters. ALLETE has the right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elects physical settlement of the Agreement, it will deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price is initially $48.01 per share, subject to adjustment as provided in the Agreement. The Agreement provides for settlement at any time on or prior to March 1, 2015. ALLETE expects to physically settle the Agreement in its entirety by delivering 2.8 million shares of its common stock. As of June 30, 2014, the Agreement has not been settled in whole or in part.

In connection with the public offering of the 2.8 million shares, ALLETE granted the underwriters an option to purchase up to an additional 0.4 million shares of ALLETE common stock (the option shares). The underwriters exercised the option in full and on March 4, 2014, the Company issued and sold the option shares to the underwriters at a price to ALLETE equal to the initial forward sale price for proceeds of $20.2 million.

The equity forward transaction was reflected in ALLETE’s diluted earnings per share using the treasury stock method, which resulted in no material dilutive impact to ALLETE’s diluted earnings per share for the quarter or six months ended June 30, 2014. Prior to a settlement date, any dilutive effect of the Agreement on our earnings per share would only occur during periods when the average market price per share of our common stock is above the per share adjusted forward sales price described above.

The equity forward transaction has no initial fair value since it was entered into at the then market price of the common stock. ALLETE will not receive any proceeds with respect to the borrowed shares until the equity forward transaction is settled, and at that time the proceeds, if any, will be recorded in equity. The equity forward transaction is accounted for as an equity instrument in accordance with the accounting guidance for distinguishing liabilities from equity and the guidance for derivatives. Under the accounting guidance, the transaction qualifies for an exception from derivative accounting because the forward sale transaction is indexed to ALLETE’s stock.



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2014			2013			2014			2013
Millions
For the Quarter Ended June 30,
Service Cost		$2.1			$2.5			$0.8			$1.0
Interest Cost	7.5			6.5			1.9			1.7
Expected Return on Plan Assets	(9.5		)	(8.8		)	(2.6		)	(2.4		)
Amortization of Prior Service Credits	—			—			(0.6		)	(0.7		)
Amortization of Net Loss	3.5			5.4			0.1			0.4
Net Periodic Benefit Expense (Income)		$3.6			$5.6		$(0.4)			—

For the Six Months Ended June 30,
Service Cost		$4.2			$5.0			$1.7			$2.0
Interest Cost	14.9			13.0			3.7			3.4
Expected Return on Plan Assets	(19.1		)	(17.6		)	(5.2		)	(4.9		)
Amortization of Prior Service Costs (Credits)	0.1			0.1			(1.2		)	(1.3		)
Amortization of Net Loss	7.1			10.7			0.2			0.8
Net Periodic Benefit Expense (Income)		$7.2			$11.2		$(0.8)			—

Employer Contributions. For the six months ended June 30, 2014, $19.5 million of ALLETE common stock was contributed to our defined benefit pension plan (no contributions for the six months ended June 30, 2013). For the six months ended June 30, 2014, we made no contributions to our other postretirement benefit plan ($10.8 million for the six months ended June 30, 2013). We do not expect to make any additional contributions to our defined benefit pension plan in 2014, and we do not expect to make any contributions to our other postretirement benefit plan in 2014.

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, 2014, Square Butte had total debt outstanding of $405.7 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the years 2014 through 2018, 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, 2014, was $29.8 million ($33.0 million for the six months ended June 30, 2013). 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 $5.2 million during the six months ended June 30, 2014 ($5.3 million for the six months ended June 30, 2013). 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. This sales agreement commenced June 1, 2014.

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 May 2020. 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. In addition, 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.

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. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., 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 a change in a governmental inflationary index and a natural gas index, as well as market prices.

Construction of Bison 4, a 205 MW wind project in North Dakota which is an addition to our Bison Wind Energy Center, has commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $246.6 million was spent through June 30, 2014. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We included Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in a filing on April 29, 2014, which, upon approval, will authorize updated rates to be included on customer bills.

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 Thomson, which had damage to the forebay canal and flooding at the facility. Minnesota Power worked closely with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs, to restore Thomson and to rebuild the forebay embankment. Minnesota Power continues restoration and upgrade work at the Thomson facility and completed rebuilding the forebay embankment. Minnesota Power anticipates partial generation at Thomson in the third quarter of 2014. Work is ongoing towards returning to full generation late in 2014 and improving the spillway capacity at the Thomson dam in 2015. Total project costs are estimated to be approximately $90 million, of which $75.5 million was spent through June 30, 2014. A request seeking cost recovery of investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider was filed with the MPUC on July 3, 2014.

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 December 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through December 2015. Currently, Minnesota Power is in discussions regarding the extension of our coal supply and transportation contracts beyond 2015. Our minimum annual payment obligation under these supply and transportation agreements is $17.7 million for the remainder of 2014 and $4.0 million for 2015. 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 2021. The aggregate amount of minimum lease payments for all operating leases is $12.1 million in 2014, $11.5 million in 2015, $9.5 million in 2016, $8.7 million in 2017, $7.4 million in 2018 and $29.2 million thereafter.

Transmission Investments. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor 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. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates.

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 and 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.

Minnesota Power is currently participating in the construction of one CapX2020 transmission line project. Minnesota Power also participated in two CapX2020 projects which were previously completed and placed into service in 2011 and 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project, which is currently under construction and expected to be in service by 2015. The North Dakota permitting process was completed in August 2012.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220-mile 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.

The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction is anticipated to begin in 2016, and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $500 million and $650 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line.

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, baghouses 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 Boswell Unit 4’s 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 reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was filed with the U.S. District Court for the District of Minnesota (Court) on July 16, 2014 and notice of the Consent Decree was published in the Federal Register July 22, 2014. Before it becomes effective, the Consent Decree must be approved by the Court after a 30-day public comment period that will end on August 21, 2014. The Consent Decree covers Minnesota Power’s Boswell, Laskin, Taconite Harbor, and Rapids Energy Centers. The Consent Decree provides for more stringent emissions limits at all affected units, and the option of refueling, retrofits, or retirements at some units. It also includes the addition of 200 megawatts of wind energy. Minnesota Power will also be required to spend $4.2 million on environmental mitigation projects over the next five years. Under the terms of the Consent Decree, Minnesota Power will also pay a $1.4 million civil penalty. In the second quarter of 2014, the Company recorded a liability and corresponding expense associated with the environmental mitigation projects. A liability for the civil penalty was recognized in 2013.

Since 2005, the Company has, and will, invest more than $600 million to reduce sulfur dioxide, nitrogen oxide, mercury and particulate matters emissions at its thermal generation facilities, and in 2012 placed in service over 200 MW of renewable wind energy, which fulfills certain obligations under the Consent Decree. In addition, Minnesota Power’s EnergyForward plan also addresses many of the requirements included in the Consent Decree. Under the EnergyForward plan Minnesota Power intends to: 1) retire Taconite Harbor Unit 3, 2) convert Laskin from coal to natural gas, and 3) install emission controls at Boswell Unit 4.

The Consent Decree further requires that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted to an existing Boswell scrubber. Minnesota Power estimates that if the Units are not retired, capital expenditures could range between $20 million to $40 million. We are evaluating our options with regard to the future course of action at our Boswell Units 1 and 2 facilities to comply with the Consent Decree, as well as future anticipated environmental regulations. We are required to inform the EPA no later than December 31, 2016 whether we will retire, refuel, repower or reroute Boswell Units 1 and 2. We believe that future capital expenditures or costs to retire would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, to address long-range transport of particulate matter and ozone by requiring reductions in SO₂ and NO_X from electric generating companies in the eastern half of the United States, including Minnesota. However, in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (Circuit Court of Appeals) vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule was promulgated. That decision was appealed and, in April 2014, the U.S. Supreme Court reversed the decision, remanding the case to the Circuit Court of Appeals for further proceedings consistent with the U.S. Supreme Court decision. On June 25, 2014, the EPA made a motion to the Circuit Court of Appeals to have the court’s stay of the CSAPR lifted and further asking the court to delay the CSAPR compliance deadlines by three years.

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 CSAPR requirements, if the stay is lifted and the EPA’s motion to toll compliance deadlines is granted, would go into effect in 2015 (Phase I) and 2017 (Phase 2).

So long as the Circuit Court of Appeals’ stay of the CSAPR remains in effect, the CAIR regulations continue to apply. Like the CSAPR, the CAIR regulations are intended to address long-range transport of particulate matter and ozone by means of an emissions trading program. Minnesota participation in the CAIR was stayed by EPA administrative action while the EPA promulgated a replacement rule. If the Circuit Court of Appeals lifts its stay of the CSAPR or otherwise upholds the CSAPR on remand, the CSAPR will likely become effective for Minnesota, but compliance deadlines may be extended to allow time for the State of Minnesota to develop its compliance plan.

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, built 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.

Due to legal challenges at both the state and federal levels, there is currently no applicable compliance deadline for 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. As part of our 2013 Integrated Resource Plan, which was approved by the MPUC in November 2013, we plan to retire Taconite Harbor Unit 3 in 2015. We believe that the Taconite Harbor Unit 3 retirement will be accomplished before any compliance deadline takes effect.

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 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $300 million through 2016, of which $102.3 million was spent through June 30, 2014. Our minimum payment obligation for the environmental upgrade is $104.7 million for 2014 and $72.5 million for 2015. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in an order dated November 12, 2013, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015, to position the Company for MATS compliance. On January 9, 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS to June 1, 2015, in order to align the Unit 3 retirement with MISO’s resource planning year.

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, became effective in December 2012. Major existing sources have until January 31, 2016, to achieve compliance with the final rule. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. We expect compliance to consist largely of adjustments to our operating practices; therefore costs for complying with the final rule are not expected to be material at this time.

Minnesota Mercury Emissions Reduction Act. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power must implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above, which is required to be completed by April 1, 2016 (see Mercury and Air Toxics Standards (MATS) Rule), will fulfill the requirements of the Minnesota Mercury Emissions Reduction Act. 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 (see Mercury and Air Toxics Standards (MATS) Rule).

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 late 2014 or beyond. Consequently, the costs for complying with the final ozone NAAQS cannot be estimated at this time.

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

In December 2012, the EPA issued a final rule implementing a more stringent annual PM_2.5standard, 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, designation 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.

Under the final rule, states will be responsible for additional PM_2.5monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by December 2013, based on already available monitoring data. The EPA believes that most U.S. counties 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. Minnesota is anticipating that it will retain attainment status; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly, the costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

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 may require the EPA to evaluate modeling data to determine attainment. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by June 2013. However, the State of Minnesota has delayed completing the documents pending receipt of EPA guidance to states for preparing the SIP submittal. Guidance was expected in 2013 and has been delayed.

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 GHG 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:

President Obama’s Climate Action Plan. In June 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.

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the 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.

In June 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established lower permitting thresholds for GHG than for other pollutants subject to PSD. However, the court also upheld the EPA’s power to require BACT for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions. We are unable to predict the compliance costs that we might incur.

In March 2012, the EPA announced a proposed rule to apply CO₂ emission New Source Performance Standards (NSPS), under Section 111(b) of the Clean Air Act, to new fossil fuel-fired electric generating units. The proposed NSPS would have applied only to new or re-powered units. Based on the volume of comments received, the EPA announced its intent to re-propose the rule. In September 2013, the EPA retracted its March 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO₂ emissions.

In June 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units” (Clean Power Plan or CPP). The EPA intends to finalize such rules by June 1, 2015. In the Clean Power Plan, the EPA proposes to set state-specific rate-based goals for CO₂ emissions from the power sector that the EPA maintains are achievable if a state undertakes a combination of measures across its power sector that constitute the EPA’s guideline for a Best System of Emission Reductions (BSER).

The EPA then established state goals, expressed as a carbon intensity target in CO₂ tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016 intended to achieve the state carbon intensity goals.

Minnesota’s Next Generation Energy Act of 2007. On April 14, 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Act of 2007 violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO₂-producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO₂ emissions in Minnesota. State officials have appealed the decision.

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 final pre-Federal Register publication of the Section 316(b) rule was issued on May 19, 2014 with Federal Register publication still pending. As it stands, the Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. We are in the process of assessing the compliance costs and there remains the possibility they 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. In April 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 in June 2013, with public comments due in September 2013. The EPA has agreed to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, 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.

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. The EPA has committed to determine whether or not a final rule will be issued under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous) by December 19, 2014, and may publish the final rule at that time, or announce its schedule for such publication. 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.

BNI Coal. As of June 30, 2014, BNI Coal had surety bonds outstanding of $47.5 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 for an additional $2.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $49.3 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, 2014, 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, 2014, we owned 73 percent of the assessable land in the Town Center District (73 percent at December 31, 2013) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2013). 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.

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. In response to a Motion for Summary Judgment by Minnesota Power, the Sixth Judicial District for the State of Minnesota dismissed all of plaintiffs’ claims in an August 2013 order. In October 2013, the plaintiffs appealed the decision to the Minnesota Court of Appeals. The Company has filed a response to the appeal and the appeal was heard by the Minnesota Court of Appeals on May 21, 2014. A decision is expected in the third quarter of 2014. As of June 30, 2014, a potential loss is not currently probable or reasonably estimable.

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, which it supplemented in March 2014. 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, 2014, 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. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.

The following discussion should be read in conjunction with our consolidated financial statements and notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from the 2013 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 headings: “Forward-Looking Statements” located on page 6 and “Risk Factors” located in Part I, Item 1A, beginning on page 28 of our 2013 Form 10‑K. The risks and uncertainties described in this Form 10-Q and our 2013 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 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 144,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota. SWL&P is a Wisconsin utility 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 Clean Energy, our business which acquired three wind energy facilities in January 2014, and is 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, and ALLETE Properties, our Florida real estate investment. This segment also includes other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

Net income attributable to ALLETE for the six months ended June 30, 2014, was $50.3 million, or $1.20 per diluted share, compared to $46.5 million, or $1.18 per diluted share, for the same period of 2013. Net income for 2014 reflected $1.4 million after-tax expense, or $0.03 per share, of acquisition costs for ALLETE Clean Energy’s wind energy facilities acquisition which closed on January 30, 2014 (see Note 4. Acquisition). In addition, net income for 2014 reflected a $2.5 million after-tax expense, or $0.06 per share, reflecting a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement (see Note 15. Commitments, Guarantees and Contingencies). Net income for 2014 reflected higher cost recovery rider revenue, transmission revenues, kWh sales, gas sales and earnings from ALLETE Clean Energy’s wind energy facilities acquisition which closed in January 2014. These increases were partially offset by higher operating and maintenance, depreciation and interest expenses. Earnings per share dilution was $0.08 due to additional shares of common stock outstanding as of June 30, 2014.

Regulated Operations net income attributable to ALLETE was $51.4 million for the six months ended June 30, 2014, compared to $48.4 million for the same period of 2013. Net income for 2014 reflected a $2.5 million after-tax expense, or $0.06 per share, reflecting a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. Net income for 2014 reflected higher cost recovery rider revenue, transmission revenues, kWh sales, and gas sales, partially offset by higher operating and maintenance, depreciation and interest expenses.

Investments and Other net loss attributable to ALLETE was $1.1 million for the six months ended June 30, 2014, compared to a net loss of $1.9 million for the same period of 2013. The net loss for 2014 reflected $1.4 million after-tax expense, or $0.03 per share, of acquisition costs for ALLETE Clean Energy’s wind energy facilities acquisition. Earnings from ALLETE Clean Energy’s wind energy facilities acquisition were partially offset by gains on sales of investments in 2013. ALLETE Properties recorded a net loss of $1.8 million for the six months ended June 30, 2014 (net loss of $1.9 million for the six months ended June 30, 2013). BNI Coal recorded net income of $2.6 million for the six months ended June 30, 2014 ($2.8 million for the six months ended June 30, 2013).

Revenue from Regulated Operations kWh sales were comparable to 2013. The decrease in sales to our municipal customers reflects a wholesale customer contract expiration effective December 31, 2013. 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, and were 3.4 percent higher in 2014 due to more energy available for sale.



Kilowatt-hours Sold			Quantity		%
Quarter Ended June 30,	2014	2013	Variance		Variance
Millions
Regulated Utility
Retail and Municipals
Residential	249	251	(2	)	(0.8	)%
Commercial	333	335	(2	)	(0.6	)%
Industrial	1,788	1,769	19		1.1	%
Municipals	198	225	(27	)	(12.0	)%
Total Retail and Municipals	2,568	2,580	(12	)	(0.5	)%
Other Power Suppliers	631	610	21		3.4	%
Total Regulated Utility Kilowatt-hours Sold	3,199	3,190	9		0.3	%

Revenue from electric sales to taconite/iron concentrate customers accounted for 23 percent of consolidated operating revenue in 2014 (26 percent in 2013). Revenue from electric sales to paper and pulp mills accounted for 7 percent of consolidated operating revenue in 2014 (8 percent in 2013). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2014 (7 percent in 2013).

Operating and Maintenance Expense increased $6.2 million, or 7 percent, from 2013. In the second quarter of 2014, a $4.2 million expense was recorded to reflect a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. Operating and maintenance expense was also higher due to higher purchased gas and transmission expense, partially offset by lower benefit expense. Purchased gas expense increased due to higher gas sales in 2014; purchased gas expenses are recovered from our customers through a purchased gas adjustment clause (see Operating Revenue). Transmission expense increased primarily due to higher MISO related expenses. Benefit expense was lower due to higher discount rates for 2014 attributable to our defined benefit pension and other postretirement benefit plans.

Operating revenue increased $11.3 million, or 57 percent, from 2013 primarily due to a $8.7 million increase in revenue generated at ALLETE Clean Energy due to the acquisition of three wind energy facilities in the first quarter of 2014. Also contributing to the increase was a $1.9 million increase in revenue at BNI Coal. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher revenue primarily as a result of higher expenses in 2014. (See Operating Expense.)

Operating expenses increased $7.7 million, or 34 percent, from 2013 primarily due to higher operating and depreciation expenses of $5.4 million as a result of the ALLETE Clean Energy wind energy facilities acquisition in the first quarter of 2014. Also contributing to the increase were higher expenses of $2.0 million at BNI Coal primarily due to higher fuel costs and repair expenses, which are recovered through the cost-plus contract. (See Operating Revenue.)

Revenue from Regulated Operations increased $13.5 million from 2013 due to a 1.8 percent increase in total kWh sales. The increase was due primarily to a 10.8 percent increase in kWh 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, and were higher in 2014 due to more energy available for sale. Also contributing to the increase was higher sales to residential and commercial customers primarily due to unseasonably cold temperatures during the first four months of 2014 compared to the same period in 2013. In the first four months of 2014, heating degree days in Duluth, Minnesota were approximately 13 percent higher than the same period in 2013. The decrease in sales to our municipal customers reflects a wholesale customer contract expiration effective December 31, 2013.



Kilowatt-hours Sold			Quantity		%
Six Months Ended June 30,	2014	2013	Variance		Variance
Millions
Regulated Utility
Retail and Municipals
Residential	647	605	42		6.9	%
Commercial	728	712	16		2.2	%
Industrial	3,604	3,614	(10	)	(0.3	)%
Municipals	440	499	(59	)	(11.8	)%
Total Retail and Municipals	5,419	5,430	(11	)	(0.2	)%
Other Power Suppliers	1,331	1,201	130		10.8	%
Total Regulated Utility Kilowatt-hours Sold	6,750	6,631	119		1.8	%

Revenue from electric sales to taconite/iron concentrate customers accounted for 23 percent of consolidated operating revenue in 2014 (25 percent percent in 2013). Revenue from electric sales to paper and pulp mills accounted for 7 percent of consolidated operating revenue in 2014 (8 percent in 2013). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2014 (6 percent in 2013).

Operating and Maintenance Expense increased $14.2 million, or 9 percent, from 2013. In the second quarter of 2013, a $4.2 million expense was recorded to reflect a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. Operating and maintenance expense was also higher due to higher purchased gas and transmission expense, partially offset by lower benefit expense. Purchased gas expense increased due to higher gas sales in 2014; purchased gas expenses are recovered from our customers through a purchased gas adjustment clause (see Operating Revenue). Transmission expense increased primarily due to higher MISO related expense. Benefit expense was lower due to higher discount rates in 2014.

Operating revenue increased $21.2 million, or 50 percent, from 2013 primarily due to a $15.8 million increase in revenue generated at ALLETE Clean Energy due to the acquisition of three wind energy facilities in the first quarter of 2014. Also contributing to the increase was a $3.2 million increase in revenue at BNI Coal. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher revenue primarily as a result of higher expenses in 2014. (See Operating Expense.)

Operating expenses increased $16.8 million, or 36 percent, from 2013 primarily due to higher operating and depreciation expenses of $11.3 million as a result of the ALLETE Clean Energy wind energy facilities acquisition in the first quarter of 2014. Also contributing to the increase were higher expenses of $2.9 million at BNI Coal primarily due to higher fuel costs and repair expenses, which are recovered through the cost-plus contract. (See Operating Revenue.)

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 2013 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 2013 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 and balance our exposure to global business cycles and changing demand. The new energy-centric pursuits will be in renewable energy, 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 adding another 205 MW at the Bison Wind Energy Center (see Regulated Operations – Renewable Energy). In addition, in 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. In January 2014, ALLETE Clean Energy acquired three wind energy facilities with existing long-term PPAs. 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.

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 GNTL, the CapX2020 initiative, 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 customer viability. 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 (see Regulated Operations – EnergyForward). 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 Minnesota Power will not earn its allowed rate of return in 2014.

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 2014 will be similar to 2013. 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 2014, compared to 77 percent in 2013. Based on these projections, 2014 taconite production levels in Minnesota are expected to be similar to 2013.

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 potential projects are in the ferrous and non-ferrous mining and steel industries and include Essar Steel Minnesota LLC (Essar), PolyMet, Mesabi Nugget Delaware, LLC, USS Corporation’s Keewatin taconite expansion and Magnetation, LLC. We cannot predict the outcome of these projects, but if these projects are constructed, Minnesota Power could serve up to approximately 500 MW of new retail or wholesale load.

Nashwauk Public Utilities Commission. In April 2014, the Company amended its formula-based wholesale electric sales agreement with the Nashwauk Public Utilities Commission for all of its electric service requirements, extending the term through June 30, 2026. A new Essar taconite facility is currently under construction in the City of Nashwauk, and the Nashwauk Public Utilities Commission also amended and extended its electric service agreement with Essar. Upon completion, this facility would result in approximately 110 MW of additional load for Minnesota Power. In April 2014, Essar updated its plans for start-up of the new facility, now indicating that initial commissioning is expected to begin in the second quarter of 2015, transitioning to full production capacity levels by the first quarter of 2016. Expansions for additional pellet production, production of direct reduced iron and production of steel slabs are also being considered by Essar for future years.

PolyMet. Minnesota Power has executed a long-term contract with PolyMet, a new industrial customer planning to start a copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. PolyMet began work on a Supplemental Draft Environmental Impact Statement (SDEIS) in 2010. The SDEIS addressed environmental issues, including those dealing with the land exchange between PolyMet and the U.S. Forest Service (USFS), which is critical to the mine site development. In December 2013, the Minnesota DNR released PolyMet’s SDEIS. A 90-day comment period ended March 13, 2014. Assuming successful completion of the SDEIS process, permits could be issued during the latter part of 2014. Construction could commence immediately upon issuance of permits and Minnesota Power could begin to supply between 45 MW and 50 MW of load initially as early as 2016 through a 10-year power supply contract period that would begin upon start-up of the mining operations.

Magnetation. Magnetation produces iron ore concentrate from low-grade natural ore tailing basins, already mined stockpiles and newly mined iron formations. Magnetation’s facility near Taconite, Minnesota is fully operational. Construction is underway at their newest concentrate facility near Coleraine, Minnesota, with production expected to commence by the end of 2014. On January 27, 2014, Minnesota Power and Magnetation entered into a new ten-year electric service agreement, which was approved by the MPUC on May 1, 2014, for its facility near Coleraine, Minnesota. This agreement is effective through at least December 31, 2025. In addition, a transmission service extension is required to be constructed by Minnesota Power and is expected to be complete in the fourth quarter of 2014. On June 19, 2014, Minnesota Power received MPUC approval of a transmission route for the service extension, and permits were received on July 2, 2014. Minnesota Power expects to supply approximately 20 MW of power to this new facility, making it a Large Power Customer of Minnesota Power. The new facility is expected to supply iron ore concentrate to Magnetation’s new pellet plant that is under construction in Reynolds, Indiana. The Reynolds pellet plant is expected to come on line in fourth quarter of 2014 and will produce about 3 million tons of taconite pellets annually for AK Steel.

EnergyForward. In January 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:

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with 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 approximately $300 million, of which $102.3 million was spent through June 30, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. In November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. Intervenors have appealed this order and the Company has filed a response to the appeal. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014.

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and municipal energy sales in Minnesota to 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 2013 Integrated Resource Plan. Minnesota Power’s 2013 Integrated Resource Plan, which was approved by the MPUC in a November 2013 order, included an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See EnergyForward.)

Wind Energy. Our wind energy facilities consist of the 292 MW Bison Wind Energy Center located in North Dakota and the 25 MW Taconite Ridge Energy Center located in northeastern Minnesota. 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. We have also commenced construction of Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $246.6 million was spent through June 30, 2014. The Bison 4 wind project is expected to be completed by the end of 2014.

Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in a December 2013 order. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We included Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in a filing on April 29, 2014, which, upon approval, will authorize updated rates to be included on customer bills.

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 May 2020. 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. In addition, 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.

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 Thomson, which had damage to the forebay canal and flooding at the facility. Minnesota Power worked closely with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs, to restore Thomson and to rebuild the forebay embankment. Minnesota Power continues restoration and upgrade work at the Thomson facility and completed rebuilding the forebay embankment. Minnesota Power anticipates partial generation at Thomson in the third quarter of 2014. Work is ongoing towards returning to full generation late in 2014 and improving the spillway capacity at the Thomson dam in 2015. Total project costs are estimated to be approximately $90 million, of which $75.5 million was spent through June 30, 2014. A request seeking cost recovery of capital expenditures related to the restoration and repair of Thomson through a renewable resources rider was filed with the MPUC on July 3, 2014.

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; however, any investment is expected to be recovered in customer rates.

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. These include the GNTL 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.

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.

The GNTL is subject to various federal and state regulatory approvals. Before a large energy facility can be sited or constructed in Minnesota, the MPUC requires a Certificate of Need, which was filed in October 2013. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction is anticipated to begin in 2016, and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $500 million and $650 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line.

Investment in ATC. As of June 30, 2014, our equity investment in ATC was $118.8 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 2013, ATC updated its 10-year transmission assessment covering the years 2013 through 2022 which identifies a need for between $3.0 and $3.6 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 2014, we invested $2.3 million in ATC, and on July 30, 2014, we invested an additional $0.8 million. We expect to make additional investments of approximately $2.7 million in 2014 to maintain our current ownership of ATC. (See Note 8. Investment in ATC.)

ALLETE Clean Energy. ALLETE Clean Energy aims to develop or acquire capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake) and Condon, Oregon (Condon) from The AES Corporation (AES) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015. The acquisition supports ALLETE’s strategy to pursue energy-centric initiatives through ALLETE Clean Energy, that include less carbon intensive and more sustainable energy sources.

Lake Benton, Storm Lake and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake began commercial operations in 1999, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility in June 2015. Armenia Mountain began operations in 2009. (See Note 4. Acquisition.)

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. Market conditions can impact land sales and could result in our inability to cover our operating expenses and fixed carrying costs such as community development district assessments and property taxes. ALLETE does not intend to acquire additional Florida real estate.



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	964	2,485	2,236,700
Palm Coast Park	3,777	3,554	3,096,800
Total Current Development Projects	4,741	6,039	5,333,500

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	10,699	8,989	8,548,500

Income Taxes. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2014. On an ongoing basis, ALLETE has 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, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income from operations before non-controlling interest and income taxes, state and federal tax law changes that become effective during the year, business combinations and configuration changes, tax planning initiatives and resolution of prior years’ tax matters. Due primarily to increased federal production tax credits as a result of wind generation, we expect our effective tax rate to be approximately 21 percent for 2014. 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 11. Income Tax Expense.)

Operating Activities. Cash from operating activities was $126.1 million for the six months ended June 30, 2014 ($111.1 million for the six months ended June 30, 2013). Cash from operating activities was higher in 2014 primarily due to cash contributions of $10.8 million in 2013 to other postretirement benefit plans and higher receipts on accounts receivable, which were partially offset by increased fuel inventory purchases.

Investing Activities. Cash used for investing activities was $323.4 million for the six months ended June 30, 2014 ($125.2 million for the six months ended June 30, 2013). The increase in cash used for investing activities was primarily due to higher capital expenditures in 2014, and the ALLETE Clean Energy wind energy facilities acquisition in January 2014, partially offset by a transfer of cash in Other Investments to Cash and Cash Equivalents.

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, 2014, we had available consolidated bank lines of credit aggregating $401.0 million ($400.7 million available as of June 30, 2013), the majority of which expire in November 2018. In addition, as of June 30, 2014, we had 2.3 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, 3.0 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets, Inc. and 2.8 million original issue shares of common stock available for issuance under a forward sale agreement (see Securities). 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 Lampert Capital Markets, Inc., in February 2008, as amended most recently in May 2014, 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 3.0 million remain available for issuance. For the six months ended June 30, 2014, 0.2 million shares of common stock were issued under this agreement, resulting in net proceeds of $8.2 million (0.3 million shares were issued for the six months ended June 30, 2013, resulting in net proceeds of $11.7 million). The shares sold in 2013 through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

During the six months ended June 30, 2014, we issued 0.2 million shares of common stock through Invest Direct, the Employee Stock Purchase Plan, and the Retirement Savings and Stock Ownership Plan, resulting in net proceeds of $10.5 million (0.4 million shares were issued for net proceeds of $21.6 million during the six months ended June 30, 2013). These shares of common stock were registered under Registration Statement Nos. 333-188315, 333-183051 and 333-162890.

On February 26, 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock. Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock from third parties and sold them to the underwriters. ALLETE has right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elects physical settlement of the Agreement, it will deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price is initially $48.01 per share, subject to adjustment as provided in the Agreement. The Agreement provides for settlement at any time on or prior to March 1, 2015. ALLETE expects to physically settle the Agreement in its entirety by delivering 2.8 million shares of its common stock. As of June 30, 2014, the Agreement has not been settled in whole or in part.

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. On January 10, 2014, we contributed $19.5 million to our defined benefit pension plan, all of which was contributed in shares of ALLETE common stock. We do not expect to make additional contributions to our defined benefit pension plan in 2014, and we do not expect to make any contributions to our other postretirement benefit plan in 2014. (See Note 14. Pension and Other Postretirement Benefit Plans.)

Our 2014 projected capital expenditures include significant investments in environmental upgrades (see Outlook – Boswell Mercury Emissions Reduction Plan) and renewable energy (see Outlook – Renewable Energy – Wind Energy). Our 2014 capital expenditures are expected to be incurred ratably over the four quarters of 2014. We are well positioned to meet our financing needs due to adequate operating cash flows, available additional working capital, and access to capital markets. We will finance capital expenditures from a combination of internally generated funds and debt and equity issuance proceeds. We intend to maintain a capital structure with capital ratios near current levels. (See Liquidity and Capital Resources – Capital Structure.)

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 2013 Form 10-K, with additional disclosure in Note 15. Commitments, Guarantees and Contingencies.

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).

Our power marketing activities consist of: (1) purchasing energy in the wholesale market to serve our regulated service territory when 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 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, 2014, 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 $0.6 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, 2014.

Evaluation of Disclosure Controls and Procedures. As of June 30, 2014, 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.

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. In response to a Motion for Summary Judgment by Minnesota Power, the Sixth Judicial District for the State of Minnesota dismissed all of plaintiffs’ claims in a August 2013 order. In October 2013, the plaintiffs’ appealed the decision to the Minnesota Court of Appeals. The Company has filed a response to the appeal and the appeal was heard by the Minnesota Court of Appeals on May 21, 2014. An accrual related to this lawsuit has not been recorded as of June 30, 2014, because a potential loss is not currently probable or reasonably estimable.

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.



Exhibit Number
4			Thirty-sixth Supplemental Indenture, dated as of June 1, 2014, between ALLETE, Inc. and The Bank of New York Mellon, as corporate trustee, and Philip L. Watson, as co-trustee.
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, 2014, announcing 2014 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



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



Large Accelerated Filer x	Accelerated Filer ¨
Non-Accelerated Filer ¨	Smaller Reporting Company ¨



			Page

Definitions			3

Forward-Looking Statements			5

Part I.	Financial Information

	Item 1.	Financial Statements (Unaudited)

	Consolidated Balance Sheet -
		June 30, 2014 and December 31, 2013	6

	Consolidated Statement of Income -
		For the Quarter and Six Months Ended June 30, 2014 and 2013	7

	Consolidated Statement of Comprehensive Income -
		For the Quarter and Six Months Ended June 30, 2014 and 2013	8

	Consolidated Statement of Cash Flows -
		For the Six Months Ended June 30, 2014 and 2013	9

	Notes to Consolidated Financial Statements		10

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	51

	Item 4.	Controls and Procedures	52

Part II.	Other Information

	Item 1.	Legal Proceedings	52

	Item 1A.	Risk Factors	53

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53

	Item 3.	Defaults Upon Senior Securities	53

	Item 4.	Mine Safety Disclosures	53

	Item 5.	Other Information	53

	Item 6.	Exhibits	53

Signatures			54



Inventories	June 30, 2014		December 31, 2013
Millions
Fuel		$22.9		$13.1
Materials and Supplies	52.4		46.2
Total Inventories		$75.3		$59.3



Other Current Liabilities	June 30, 2014		December 31, 2013
Millions
Customer Deposits		$22.8		$26.0
Power Purchase Agreements (a)	12.7		—
Other	25.6		26.6
Total Other Current Liabilities		$61.1		$52.6



x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended June 30, 2014



¨	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from ______________ to ______________


•	our ability to successfully implement our strategic objectives;


•	global and domestic economic conditions affecting us or our customers;


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


•	effects of restructuring initiatives in the electric industry;


•	changes in tax rates or policies or in rates of inflation;


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


•	the impacts of laws and regulations related to renewable and distributed generation;


•	the outcome of legal and administrative proceedings (whether civil or criminal) and settlements;


•	war, acts of terrorism and cyber attacks;


•	weather conditions, natural disasters and pandemic diseases;


•	our ability to access capital markets and bank financing;


•	changes in interest rates and the performance of the financial markets;


•	availability and management of construction materials and skilled construction labor for capital projects;


•	changes in operating expenses and capital expenditures and our ability to recover these costs;


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


•	our ability to replace a mature workforce and retain qualified, skilled and experienced personnel;


•	our ability to manage expansion and integrate acquisitions;


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


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



Prepayments and Other Current Assets	June 30, 2014		December 31, 2013
Millions
Deferred Fuel Adjustment Clause		$20.3		$23.0
Restricted Cash (a)	3.3		—
Other	8.6		12.1
Total Prepayments and Other Current Assets		$32.2		$35.1


(a)	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements.


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisition on January 30, 2014 (see Note 4. Acquisition).


(a)	As of June 30, 2014, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $2.3 million, in three years to less than five years was $1.8 million, and in five or more years was $6.2 million.


(b)	During the first three months of 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.



		Gross Unrealized
Available-For-Sale Securities	Cost	Gain	Loss	Fair Value
Millions
June 30, 2014	$18.9	$0.4	$0.4	$18.9
December 31, 2013	$18.3	—	$0.6	$17.7



	Net	Gross Realized
Available-For-Sale Securities (Continued)	Proceeds	Gain	Loss
Millions
Quarter Ended June 30,
2014	$2.1	$0.2	—
2013	$0.2	—	—
Six Months Ended June 30,
2014	$2.7	$0.2	—
2013	$8.1	$0.8	—


(a)	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.


(c)	The purchase price accounting valued the non-controlling interest of Lake Benton, Storm Lake and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake was subsequently purchased by ALLETE Clean Energy.