10-K

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)
	T	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
		For the fiscal year ended December 31, 2012
	£	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
		For the transition period from ______________ to ______________

Commission File No. 1-3548

ALLETE, Inc.

(Exact name of registrant as specified in its charter)

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

30 West Superior Street, Duluth, Minnesota 55802-2093

(Address of principal executive offices, including zip code)

(218) 279-5000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, without par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes T     No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨     No T

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. T

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act).     

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

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

The aggregate market value of voting stock held by nonaffiliates on June 30, 2012, was $1,591,836,880.

As of February 1, 2013, there were 39,468,463 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference

Portions of the Proxy Statement for the 2013 Annual Meeting of Shareholders are incorporated by reference in Part III.

Index

Definitions			4
Forward-Looking Statements			6
Part I
Item 1.	Business		7
	Regulated Operations		7
		Electric Sales / Customers	7
		Power Supply	11
		Transmission and Distribution	14
		Investment in ATC	14
		Properties	15
		Regulatory Matters	15
		Regional Organizations	18
		Minnesota Legislation	18
		Competition	19
		Franchises	19
	Investments and Other		19
		BNI Coal	19
		ALLETE Properties	20
		ALLETE Clean Energy	20
		Non-Rate Base Generation	20
	Environmental Matters		21
	Employees		25
	Availability of Information		25
	Executive Officers of the Registrant		26
Item 1A.	Risk Factors		27
Item 1B.	Unresolved Staff Comments		31
Item 2.	Properties		31
Item 3.	Legal Proceedings		31
Item 4.	Mine Safety Disclosures		31
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		32
Item 6.	Selected Financial Data		33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
	Overview		34
	2012 Compared to 2011		35
	2011 Compared to 2010		37
	Critical Accounting Policies		39
	Outlook		41
	Liquidity and Capital Resources		47
	Capital Requirements		50
	Environmental and Other Matters		51
	Market Risk		51
	Recently Adopted Accounting Standards		52
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		52
Item 8.	Financial Statements and Supplementary Data		52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		52
Item 9A.	Controls and Procedures		52
Item 9B.	Other Information		53

ALLETE 2012 Form 10-K

2

Index

Part III
Item 10.	Directors, Executive Officers and Corporate Governance	54
Item 11.	Executive Compensation	54
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	54
Item 13.	Certain Relationships and Related Transactions, and Director Independence	55
Item 14.	Principal Accounting Fees and Services	55
Part IV
Item 15.	Exhibits and Financial Statement Schedules	56
Signatures		62
Consolidated Financial Statements		65

ALLETE 2012 Form 10-K

3

Definitions

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

Abbreviation or Acronym	Term
AC	Alternating Current
AFUDC	Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods
ALLETE	ALLETE, Inc.
ALLETE Clean Energy	ALLETE Clean Energy, Inc.
ALLETE Properties	ALLETE Properties, LLC and its subsidiaries
ArcelorMittal	ArcelorMittal USA, Inc.
ARS	Auction Rate Securities
ATC	American Transmission Company LLC
Basin	Basin Electric Power Cooperative
Bison 1	Bison 1 Wind Project
Bison 2	Bison 2 Wind Project
Bison 3	Bison 3 Wind Project
Bison	Bison Wind Energy Center
BNI Coal	BNI Coal, Ltd.
Boswell	Boswell Energy Center
CAIR	Clean Air Interstate Rule
CO2	Carbon Dioxide
Company	ALLETE, Inc. and its subsidiaries
CSAPR	Cross-State Air Pollution Rule
DC	Direct Current
EPA	Environmental Protection Agency
ESOP	Employee Stock Ownership Plan
FERC	Federal Energy Regulatory Commission
Form 8-K	ALLETE Current Report on Form 8-K
Form 10-K	ALLETE Annual Report on Form 10-K
Form 10-Q	ALLETE Quarterly Report on Form 10-Q
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
Hibbard	Hibbard Renewable Energy Center
IBEW	International Brotherhood of Electrical Workers
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
Item___	Item___of this Form 10-K
kV	Kilovolt(s)
Laskin	Laskin Energy Center
LIBOR	London Inter Bank Offered Rate
MACT	Maximum Achievable Control Technology
Magnetation	Magnetation, Inc.
Manitoba Hydro	Manitoba Hydro-Electric Board
MATS	Mercury and Air Toxics Standards
MBtu	Million British thermal units
Medicare Part D	Medicare Part D provision of the Patient Protection and Affordable Care Act of 2010

ALLETE 2012 Form 10-K

4

Definitions (continued)

Mesabi Nugget	Mesabi Nugget Delaware, LLC
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission
MW / MWh	Megawatt(s) / Megawatt-hour(s)
NAAQS	National Ambient Air Quality Standards
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
NOL	Net Operating Loss
Non-residential	Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NO2	Nitrogen Dioxide
NOX	Nitrogen Oxides
Note ___	Note ___ to the consolidated financial statements in this Form 10-K
NPDES	National Pollutant Discharge Elimination System
NYSE	New York Stock Exchange
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
RSOP	Retirement Savings and Stock Ownership Plan
SEC	Securities and Exchange Commission
SO2	Sulfur Dioxide
Square Butte	Square Butte Electric Cooperative
Standard & Poor’s	Standard & Poor’s Ratings Services
SWL&P	Superior Water, Light and Power Company
Taconite Harbor	Taconite Harbor Energy Center
Taconite Ridge	Taconite Ridge Energy Center
Town Center	Town Center at Palm Coast development project in Florida
Town Center District	Town Center at Palm Coast Community Development District
U.S.	United States of America
USS Corporation	United States Steel Corporation

ALLETE 2012 Form 10-K

5

Forward-Looking Statements

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

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

• our ability to successfully implement our strategic objectives;

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

• our ability to manage expansion and integrate acquisitions;

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

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

• effects of restructuring initiatives in the electric industry;

• economic and geographic factors, including political and economic risks;

• changes in and compliance with laws and regulations;

• weather conditions, natural disasters and pandemic diseases;

• war, acts of terrorism and cyber attacks;

• wholesale power market conditions;

• population growth rates and demographic patterns;

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

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

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

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

• project delays or changes in project costs;

• availability and managementof construction materials and skilled construction labor for capital projects;

• changes in operating expenses and capital expenditures;

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

• our ability to access capital markets and bank financing;

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

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

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

Additional disclosures regarding factors that could cause our results or performance to differ from those anticipated by this report are discussed in Item 1A under the heading “Risk Factors” beginning on page 27 of this Form 10-K. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can we assess the impact of each of these factors on our businesses or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by us in this Form 10-K and in our other reports filed with the SEC that attempt to identify the risks and uncertainties that may affect our business.

ALLETE 2012 Form 10-K

6

Part I

Item 1. Business

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,100 acres of land in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2012, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

Year Ended December 31	2012			2011			2010
Consolidated Operating Revenue – Millions		$961.2			$928.2			$907.0
Percentage of Consolidated Operating Revenue
Regulated Operations	91		%	92		%	92		%
Investments and Other	9		%	8		%	8		%
	100		%	100		%	100		%

For a detailed discussion of results of operations and trends, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. For business segment information, see Note 1. Operations and Significant Accounting Policies and Note 2. Business Segments.

Regulated Operations

Electric Sales / Customers

Regulated Utility Electric Sales
Year Ended December 31	2012	%	2011	%	2010	%
Millions of Kilowatt-hours
Retail and Municipals
Residential	1,132	9	1,159	9	1,150	9
Commercial	1,436	11	1,433	11	1,433	11
Industrial	7,502	57	7,365	56	6,804	52
Municipals	1,020	8	1,013	7	1,006	7
Total Retail and Municipals	11,090	85	10,970	83	10,393	79
Other Power Suppliers	1,999	15	2,205	17	2,745	21
Total Regulated Utility Electric Sales	13,089	100	13,175	100	13,138	100

ALLETE 2012 Form 10-K

7

Regulated Operations (Continued)

Seasonality

The operations of our industrial customers, which make up a large portion of our sales portfolio as shown in the table above, are not typically subject to significant seasonal variations. As a result, Minnesota Power is generally not subject to significant seasonal fluctuations in electric sales; however, residential sales as compared to 2011 were down primarily due to unseasonably warm weather during the first four months of 2012. Heating degree days in Duluth, Minnesota were approximately 22 percent lower than the first four months of 2011.

Industrial Customers. In 2012, our industrial customers represented 57 percent of total regulated utility kilowatt-hour sales. Our industrial customers are primarily in the taconite mining, iron concentrate, paper, pulp and wood products, and pipeline industries.

Industrial Customer Electric Sales
Year Ended December 31	2012	%	2011	%	2010	%
Millions of Kilowatt-hours
Taconite/Iron Concentrate	4,968	66	4,874	66	4,324	64
Paper, Pulp and Wood Products	1,571	21	1,560	21	1,573	23
Pipelines and Other Industrial	963	13	931	13	907	13
Total Industrial Customer Electric Sales	7,502	100	7,365	100	6,804	100

Five Minnesota Power taconite customers produce approximately 75 percent of the iron ore produced in theU.S. according to the U.S. Geological Survey’s 2011 Minerals Yearbook published in January 2013. Sales to taconite customers and iron concentrate customers represented 4,968 million kilowatt-hours, or 66 percent, of our total industrial sales in 2012. Taconite, an iron-bearing rock of relatively low iron content, is abundantly available in northern Minnesota and an important domestic source of raw material for the steel industry. Taconite processing plants use large quantities of electric power to grind the iron-bearing rock, and agglomerate and pelletize the iron particles into taconite pellets.

Minnesota Power’s five taconite customers have the capability to produce 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.

During 2012, the domestic steel industry’s production levels enabled Minnesota taconite producers to operate at, or near, full capacity for the entire year. According to the American Iron and Steel Institute (AISI), an association of North American steel producers, U.S. raw steel production operated at approximately 75 percent of capacity in 2012, similar to 2011 levels of 75 percent, and up from 70 percent in 2010.

ALLETE 2012 Form 10-K

8

Regulated Operations (Continued)

Industrial Customers (Continued)

Annual taconite production in Minnesota remained strong at, or near, full production with 39 million tons produced in both 2012 and 2011, up from 35 million tons in 2010. The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years.

Minnesota Power Taconite Customer Production
Year	Tons (Millions)
2012*	39
2011	39
2010	35
2009	17
2008	39
2007	38
2006	39
2005	40
2004	39
2003	34
Source: Minnesota Department of Revenue December 2012 Mining Tax Guide for years 2003 - 2011.
* Preliminary data from the Minnesota Department of Revenue.

In addition to serving the taconite industry, Minnesota Power also serves a number of customers in the paper, pulp and wood products industry, which represented 1,571 million kilowatt-hours, or 21 percent, of our total industrial sales in 2012. Four major paper mills, which represent the majority of this load, reported operating at, or near, full capacity for the majority of 2012.

Large Power Customer Contracts. Minnesota Power has 9 Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. The customers consist of five taconite producing facilities (two of which are owned by one company and are served under a single contract), one iron nugget plant, and four paper and pulp mills.

Large Power Customer contracts require Minnesota Power to have a certain amount of generating capacity available. In turn, each Large Power Customer is required to pay a minimum monthly demand charge that covers the fixed costs associated with having this capacity available to serve the customer, including a return on common equity. Most contracts allow customers to establish the level of megawatts subject to a demand charge on a four-month basis and require that a portion of their megawatt needs be committed on a take-or-pay basis for at least a portion of the term of the agreement. In addition to the demand charge, each Large Power Customer is billed an energy charge for each kilowatt-hour used that recovers the variable costs incurred in generating electricity. Three of the Large Power Customers have interruptible service which provides a discounted demand rate in exchange for the ability to interrupt the customers during system emergencies. Minnesota Power also provides incremental production service for customer demand levels above the contractual take-or-pay levels. There is no demand charge for this service and energy is priced at an increment above Minnesota Power’s cost. Incremental production service is interruptible.

All contracts with Large Power Customers continue past the contract termination date unless the required advance notice of cancellation has been given. The required advance notice of cancellation varies from one to four years. Such contracts minimize the impact on earnings that otherwise would result from significant reductions in kilowatt-hour sales to such customers. Large Power Customers are required to take all of their purchased electric service requirements from Minnesota Power for the duration of their contracts. The rates and corresponding revenue associated with capacity and energy provided under these contracts are subject to change through the same regulatory process governing all retail electric rates. (See Item 1. Business – Regulated Operations – Regulatory Matters – Electric Rates.)

ALLETE 2012 Form 10-K

9

Regulated Operations (Continued)

Large Power Customer Contracts (Continued)

Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customer’s energy usage, forecasted energy prices, and fuel clause adjustment estimates. Minnesota Power’s four taconite-producing Large Power Customers have generally predictable energy usage on a week-to-week basis, and any differences that occur are trued-up the following month.

Contract Status for Minnesota Power Large Power Customers

As of February 1, 2013

Customer	Industry	Location	Ownership	Earliest Termination Date
ArcelorMittal – Minorca Mine (a)	Taconite	Virginia, MN	ArcelorMittal	January 31, 2017
Hibbing Taconite Co. (a)	Taconite	Hibbing, MN	62.3% ArcelorMittal 23.0% Cliffs Natural Resources Inc. 14.7% USS Corporation	January 31, 2017
United Taconite LLC (a)	Taconite	Eveleth, MN	Cliffs Natural Resources Inc.	January 31, 2017
USS Corporation (USS – Minnesota Ore) (a,b)	Taconite	Mt. Iron, MN and Keewatin, MN	USS Corporation	January 31, 2017
Mesabi Nugget	Iron Nugget	Hoyt Lakes, MN	80% Steel Dynamics, Inc. 20% Kobe Steel USA	December 31, 2017
Boise White Paper, LLC	Paper	International Falls, MN	Boise Paper Holdings, LLC	January 31, 2015
UPM, Blandin Paper Mill (a)	Paper	Grand Rapids, MN	UPM-Kymmene Corporation	January 31, 2017
NewPage Corporation – Duluth Mill (c)	Paper and Pulp	Duluth, MN	NewPage Corporation	December 31, 2022
Sappi Cloquet LLC (a)	Paper and Pulp	Cloquet, MN	Sappi Limited	January 31, 2017

(a) The contract will terminate four years from the date of written notice from either Minnesota Power or the customer. No notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is January 31, 2017.

(b) USS Corporation owns both the Minntac Plant in Mountain Iron, MN and the Keewatin Taconite Plant in Keewatin, MN.

(c) NewPage emerged from Chapter 11 bankruptcy in December 2012. The Duluth mill operations continued without interruption throughout the bankruptcy proceedings and a new 10-year contract was approved by the MPUC in a December 10, 2012 order. (See Note 1. Operations and Significant Accounting Policies – Concentration of Credit Risk.)

Residential and Commercial Customers. In 2012, our residential and commercial customers represented 20 percent of total regulated utility kilowatt-hour sales. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 143,000 residential and commercial customers. 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.

Municipal Customers. In 2012, our municipal customers represented 8 percent of total regulated utility kilowatt-hour sales, which included 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. The private non-affiliated utility in Wisconsin, which requires 17 MW of average monthly demand, has submitted a cancellation notice with termination effective December 31, 2013. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Other Power Suppliers. The Company also enters into off-system sales with Other Power Suppliers. These sales are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.

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

ALLETE 2012 Form 10-K

10

Regulated Operations (Continued)

Other Power Suppliers (Continued)

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. (See Note 11. Commitments, Guarantees and Contingencies.)

Power Supply

In order to meet our customers’ electric requirements, we utilize a mix of Company generation and purchased power. The Company’s generation is primarily coal-fired, but also includes approximately 91 MW of hydroelectric generation from ten hydro stations in Minnesota, 317 MW of nameplate capacity wind generation, and 81 MW of biomass co-fired generation. Purchased power consists of long-term coal, wind and hydro PPAs as well as market purchases. The following table reflects the Company’s generating capabilities as of December 31, 2012, and total electrical output for 2012. Minnesota Power had an annual net peak load of 1,633 MW on July 2, 2012.

ALLETE 2012 Form 10-K

11

Regulated Operations (Continued)

Power Supply (Continued)

				Year Ended
	Unit	Year	Net	December 31, 2012
Regulated Utility Power Supply	No.	Installed	Capability	Generation and Purchases
			MW	MWh	%
Coal-Fired
Boswell Energy Center	1	1958	68
in Cohasset, MN	2	1960	68
	3	1973	362
	4	1980	468	(a)
			966	6,484,096	48.6
Laskin Energy Center	1	1953	47
in Hoyt Lakes, MN	2	1953	50
			97	368,364	2.8
Taconite Harbor Energy Center	1	1957	79
in Schroeder, MN	2	1957	76
	3	1967	84
			239	872,319	6.4
Total Coal			1,302	7,724,779	57.8
Biomass/Coal/Natural Gas
Hibbard Renewable Energy Center in Duluth, MN	3 & 4	1949, 1951	58	20,332	0.2
Cloquet Energy Center in Cloquet, MN	5	2001	23	66,803	0.5
Total Biomass/Coal/Natural Gas			81	87,135	0.7
Hydro (b)
Group consisting of ten stations in MN	Multiple	Multiple	91	285,118	2.1
Wind (c)
Taconite Ridge Energy Center in Mt. Iron, MN	Multiple	2008	4	62,393	0.5
Bison Wind Energy Center in Oliver and Morton Counties, ND	Multiple	2010-2012	42	280,869	2.1
Total Wind			46	343,262	2.6
Total Company Generation			1,520	8,440,294	63.2
Long-Term Purchased Power
Lignite Coal - Square Butte near Center, ND				1,630,776	12.2
Wind - Oliver County, ND				341,105	2.6
Hydro - Manitoba Hydro in Winnipeg, MB, Canada				359,395	2.7
Total Long-Term Purchased Power				2,331,276	17.5
Other Purchased Power (d)				2,577,648	19.3
Total Purchased Power				4,908,924	36.8
Total			1,520	13,349,218	100.0

(a) Boswell Unit 4 net capability shown above reflects Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4. (See Note 4. Jointly-Owned Facilities.)

(b) In June 2012, record rainfall and flooding occurred near Duluth, Minnesota and surrounding areas impacting Minnesota Power’s hydro system, particularly the Thomson Energy Center, which is currently off-line due to damage to the forebay canal and flooding at the facility. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Outlook - Hydro Operations.)

(c) Taconite Ridge consists of 10 wind turbine generator units with a total nameplate capacity of 25 MW. Bison Wind Energy Center consists of 101 wind turbine generator units, with a total nameplate capacity of 292 MW. The net capability reflected in the table is the actual accredited capacity of the facility, which is the amount of net generating capability associated with the facility for which capacity credit was obtained using limited historical data. As more data is collected, actual accredited capacity may increase. Bison 1 was commissioned in December 2010 and January 2012 while Bison 2 and Bison 3 were commissioned in December 2012.

(d) Includes short-term market purchases in the MISO market and from Other Power Suppliers.

ALLETE 2012 Form 10-K

12

Regulated Operations (Continued)

Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin region located in Montana and Wyoming. Coal consumption in 2012 for electric generation at Minnesota Power’s coal-fired generating stations was approximately 4.6 million tons. As of December 31, 2012, Minnesota Power had a coal inventory of 0.8 million tons. Minnesota Power’s coal supply agreements have expiration dates through 2014. In 2013, Minnesota Power expects to obtain coal under these coal supply agreements and in the spot market. Minnesota Power also continues to explore other future coal supply options. We believe that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.

Minnesota Power also has transportation agreements in place for the delivery of a significant portion of its coal requirements. These transportation agreements have expiration dates through 2015. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Coal Delivered to Minnesota Power
Year Ended December 31	2012		2011		2010
Average Price per Ton		$29.58		$28.85		$25.49
Average Price per MBtu		$1.64		$1.60		$1.42

Long-Term Purchased Power. Minnesota Power has contracts to purchase capacity and energy from various entities, including output from certain hydro and wind generating facilities.

Square Butte PPA. Under the long-term agreement with Square Butte, which expires at the end of 2026, Minnesota Power is currently entitled to 50 percent of the output of a 455-MW coal-fired generating unit located near Center, North Dakota. (See Note 11. Commitments, Guarantees and Contingencies.) BNI Coal supplies lignite coal to Square Butte. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit. Square Butte’s cost of lignite burned in 2012 was approximately $1.35 per MBtu.

Minnkota Power PPA. On December 12, 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity over the term June 1, 2016 through May 31, 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

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

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in April 2015. Under this agreement, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only transaction 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 a long-term PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba (See Item 1. Business – Regulated Operations – Transmission and Distribution.) 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.

ALLETE 2012 Form 10-K

13

Regulated Operations (Continued)

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 345 kV (29 miles), 250 kV (465 miles), 230 kV (698 miles), 161 kV (43 miles), 138 kV (128 miles), 115 kV (1,244 miles) and less than 115 kV (6,233 miles). We own and operate 170 substations with a total capacity of 11,322 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region’s transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

Minnesota Power is participating in three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. The 28-mile 345 kV line between Monticello and St. Cloud was placed into service in December 2011 and the 70-mile 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process was completed on August 12, 2012. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.

Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between $100 million and $110 million in the CapX2020 initiative through 2015. A total of $48.2 million was spent through December 31, 2012, of which $37.3 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($27.8 million as of December 31, 2011 of which $20.4 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $7.4 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Great Northern Transmission Line. As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. (See Item 1. Business – Regulated Operations – Power Supply.) In February 2012, Minnesota Power and Manitoba Hydro proposed construction of the Great Northern Transmission Line, a 500 kV transmission line between Manitoba and Minnesota’s Iron Range, in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy, which is targeted to be in service in 2020. Total project cost and cost allocations are still to be determined. The Great Northern Transmission Line is subject to various federal and state regulatory approvals. In addition, Manitoba Hydro must obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada.

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

Investment in ATC

Rainy River Energy, our wholly-owned subsidiary, 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 December 31, 2012, our equity investment in ATC was $107.3 million ($98.9 million at December 31, 2011). (See Note 6. Investment in ATC.)

ALLETE 2012 Form 10-K

14

Regulated Operations (Continued)

Investment in ATC (Continued)

In September 2012, ATC updated its 10-year transmission assessment covering the years 2012 through 2021 which identifies between $3.9 and $4.8 billion in transmission system improvements. 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 April 2011, ATC and Duke Energy Corporation announced the creation of a joint venture, Duke-American Transmission Co. (DATC) that intends to build, own and operate new electric transmission infrastructure in the U.S. and Canada. DATC is subject to the rules and regulations of the FERC, MISO, PJM Interconnection LLC and various other independent system operators and state regulatory authorities. In September 2011, DATC announced its first set of proposed transmission projects, which include seven new transmission line projects in five Midwestern states. The individual projects have a total cost of approximately $4 billion. We intend to maintain our approximate 8 percent ownership interest in ATC.

Properties

We own office and service buildings, an energy control center, repair shops, and storerooms in various localities. All of our electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. All of our generating plants and most of our substations are located on real property owned by us, subject to the lien of a mortgage, whereas most of our electric lines are located on real property owned by others with appropriate easement rights or necessary permits from governmental authorities. WPPI Energy owns 20 percent of Boswell Unit 4. WPPI Energy has the right to use our transmission line facilities to transport its share of Boswell generation. (See Note 4. Jointly-Owned Facilities.)

Regulatory Matters

We are subject to the jurisdiction of various regulatory authorities and other organizations. The MPUC has regulatory authority over Minnesota Power’s service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for the sale of electricity for resale and transmission of electricity in interstate commerce, certain accounting and record-keeping practices and ATC. The NERC has been certified by the FERC as the national electric reliability organization and has jurisdiction over certain aspects of the Company’s generation and transmission operations, including cybersecurity relating to reliability. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas, water, issuances of securities, and other matters. The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities necessary for construction in North Dakota.

Electric Rates. All rates and contract terms in our Regulated Operations are subject to approval by applicable regulatory authorities. Minnesota Power designs its retail electric service rates based on cost of service studies under which allocations are made to the various classes of customers as approved by the MPUC. Nearly all retail sales include billing adjustment clauses, which adjust electric service rates for changes in the cost of fuel and purchased energy, recovery of current and deferred conservation improvement programexpenditures and recovery of certain environmental, transmission and renewable expenditures.

Information published by the Edison Electric Institute (Typical Bills and Average Rates Report – Summer 2012 and Rankings – July 1, 2012) ranked Minnesota Power as having the fourth lowest average retail rates out of 169 utilities in the U.S. Minnesota Power had the lowest rates in Minnesota and second lowest in the region consisting of Iowa, Kansas, Minnesota, Missouri, North Dakota, South Dakota and Wisconsin.

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

2010 Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

ALLETE 2012 Form 10-K

15

Regulated Operations (Continued)

Regulatory Matters (Continued)

In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). On February 14, 2012, the Court granted the petition for review and oral arguments were held before the Court on October 9, 2012. A decision is expected in early 2013; however, we cannot predict the outcome at this time.

Pension. In December 2011, the Company filed a petition with the MPUC requesting a mechanism to recover the cost of capital associated with the prepaid pension asset (or liability) created by the required contributions under the pension plan in excess of (or less than) annual pension expense. The Company further requested a mechanism to defer pension expenses in excess of (or less than) those currently being recovered in base rates. On February 14, 2013, the MPUC denied the Company's petition for recovery of the pension asset and deferral of expenses outside of a general rate case. The MPUC decision does not impact the results of operations for the year ended December 31, 2012.

ALLETE Clean Energy.In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. On July 23, 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

Bison Wind Energy Center. Our Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity. The 82 MW Bison 1 wind facility was completed in two phases; the first phase in 2010 and the second phase in January 2012. The 105 MW Bison 2 and 105 MW Bison 3 wind facilities were completed in December 2012. Total project costs for our Bison Wind Energy Center were $473.3 million through December 31, 2012. In September 2011 and November 2011, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively.

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated with Bison 1. We anticipate filing a cost recovery petition with the MPUC in the first half of 2013 to update customer billing rates for Bison 1 and to include investments and expenditures associated with Bison 2 and Bison 3.

Integrated Resource Plan. In May 2011, the MPUC issued its final order approving our 2010 Integrated Resource Plan. As a condition of the final order, a required baseload diversification study evaluating the impact of additional environmental regulations over the next two decades was filed on February 6, 2012. Minnesota Power’s Integrated Resource Plan to be filed on March 1, 2013, will detail our “EnergyForward” strategic plan (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward), and will include an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction and the Federal MATS rule. On August 31, 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 and are estimated to be between $350 million and $400 million. The MPCA has 180 days to comment on the mercury emissions reduction plan, which then is reviewed by the MPUC for a decision. We expect a decision by the MPUC on the plan in the third quarter of 2013. After approval by the MPUC we anticipate filing a petition to include investments and expenditures in customer billing rates.

ALLETE 2012 Form 10-K

16

Regulated Operations (Continued)

Regulatory Matters (Continued)

Transmission Investments. We have an approved cost recovery rider in place for certain transmission expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In June 2011, we filed a request with the MPUC to approve an updated billing factor that includes additional transmission expenditures, which we expect to be approved in the first quarter of 2013.

Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues from service provided in the state on energy CIPs each year. These investments are recovered from retail customers through a combination of the conservation cost recovery charge included in retail base rates and a conservation program adjustment, which is adjusted annually through the CIP consolidated filing. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, any financial incentive earned for cost-effective program achievements, and a carrying charge on the deferred account balance. Minnesota’s Next Generation Energy Act of 2007 introduced, in addition to the minimum spending requirements, an energy-saving goal of 1.5 percent of gross annual retail electric energy sales beginning with program year 2010. In June 2010, a triennial filing was submitted for 2011 through 2013, and was subsequently approved by the Minnesota Department of Commerce. Minnesota Power’s CIP investment goal was $6.0 million for 2012 ($5.9 million for 2011; $4.6 million for 2010), with actual spending of $6.8 million in 2012 ($6.3 million in 2011; $5.6 million in 2010).

In light of the changes in the Next Generation Energy Act of 2007, the MPUC adjusted the utility performance incentive to recognize utilities for making progress toward and meeting the energy-savings goals established. This new incentive mechanism became effective beginning with the 2010 program year. On March 30, 2012, Minnesota Power submitted its 2011 CIP consolidated filing that calculated CIP financial incentives based upon the MPUC’s new mechanism. The total requested incentive was $7.8 million in 2012 ($6.8 million in 2011 related to the 2010 CIP consolidated filing). The requested CIP financial incentive was approved by the MPUC in an order received on November 27, 2012, and was recorded as revenue and as a regulatory asset; the approved financial incentive will be billed in 2013.

Rapids Energy Center. On December 19, 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill (Blandin). Minnesota Power and Blandin entered into a new electric service agreement in September 2012 which is also subject to MPUC approval. We expect a decision from the MPUC on these filings in mid-2013.

Federal Energy Regulatory Commission. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for transmission of electricity in interstate commerce and electricity sold at wholesale (including the rates for our municipal customers), natural gas transportation, certain accounting and record-keeping practices, certain activities of our regulated utilities, and the operations of ATC. FERC jurisdiction also includes enforcement of NERC mandatory electric reliability standards. Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. Minnesota Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July 1, 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 City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin. This customer submitted a cancellation notice with termination effective on December 31, 2013. The 17 MW of average monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in 2014.

ALLETE 2012 Form 10-K

17

Regulated Operations (Continued)

Regulatory Matters (Continued)

Public Service Commission of Wisconsin. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas and water, issuances of securities and other matters.

During 2012, SWL&P’s retail rates were based on a 2010 PSCW retail rate order, which was effective January 1, 2011. SWL&P’s 2013 retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, and allows for a 10.9 percent return on common equity. The new rates reflect an average overall increase of 2.4 percent for retail customers (a 13.8 percent increase in water rates, a 1.2 percent increase in electric rates, and a 2.0 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $1.7 million in additional revenue.

North Dakota Public Service Commission. The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities in North Dakota.

Regional Organizations

Midwest Independent Transmission System Operator, Inc. (MISO). Minnesota Power and SWL&P are members of MISO, a regional transmission organization. While Minnesota Power and SWL&P retain ownership of their respective transmission assets, their transmission networks are under the regional operational control of MISO. Minnesota Power and SWL&P take and provide transmission service under the MISO open access transmission tariff. MISO continues its efforts to standardize rates, terms, and

conditions of transmission service over its region, which encompasses all or parts of 11 states and the Canadian province of Manitoba, and over 100,000 MW of generating capacity.

North American Electric Reliability Corporation (NERC). The NERC has been certified by the FERC as the national electric reliability organization. The NERC ensures the reliability and security of the North American bulk power system. The NERC oversees eight regional entities that establish requirements, approved by the FERC, for reliable operation and maintenance of power generation facilities and transmission systems. Minnesota Power is subject to these reliability requirements and can incur significant penalties for failing to comply with them.

Midwest Reliability Organization (MRO).MinnesotaPoweris a member of the MRO, one of the eight regional entities overseen by the NERC that is responsible for: (1) developing and implementing electricity reliability standards; (2) enforcing compliance with those standards; (3) providing seasonal and long-term assessments of the bulk power system’s ability to meet demand for electricity; and (4) providing an appeals and dispute resolution process.

The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, all of North Dakota, Minnesota, Nebraska and the majority of South Dakota, Iowa and Wisconsin. The region includes more than 100 organizations that are involved in the production and delivery of power to more than 20 million people. These organizations include municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown corporations, independent power producers and others who have interests in the reliability of the bulk power system.

Minnesota Legislation

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

ALLETE 2012 Form 10-K

18

Regulated Operations (Continued)

Minnesota Legislation (Continued)

Minnesota Power has taken several steps in executing its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. We have executed two long-term PPAs with an affiliate of NextEra Energy, Inc. for wind energy in North Dakota (Oliver Wind I and II). Other steps include Taconite Ridge, our 25 MW wind facility located in northeastern Minnesota, and our 292 MW Bison Wind Energy Center in North Dakota. Approximately 20 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2013.

Competition

Retail electric energy sales in Minnesota and Wisconsin are made to customers in assigned service territories. As a result, most retail electric customers in Minnesota do not have the ability to choose their electric supplier. Large energy users of 2 MW and above that are located outside of a municipality may be allowed to choose a supplier upon MPUC approval. Minnesota Power serves 10 Large Power facilities over 10 MW, none of which have engaged in a competitive rate process. No other large commercial or small industrial customers in Minnesota Power’s service territory have attempted to seek a provider outside Minnesota Power’s service territory since 1994. Retail electric and natural gas customers in Wisconsin do not have the ability to choose their energy supplier. In both states, however, electricity may compete with other forms of energy. Customers may also choose to generate their own electricity, or substitute other forms of energy for their manufacturing processes.

For the year ended December 31, 2012, 8 percent of the Company’s electric energy sales were to municipal customers in Minnesota and a private non-affiliated utility in Wisconsin by contract under a formula-based rate approved by FERC. These customers have the right to seek an energy supply from any wholesale electric service provider upon contract expiration. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

The FERC has continued with its efforts to promote a more competitive wholesale market through open-access electric transmission and other means. As a result, our electric sales to Other Power Suppliers and our purchases to supply our retail and wholesale load are made in the competitive market.

Franchises

Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 94 cities. The remaining cities, villages and towns served by us do not require a franchise to operate. SWL&P serves customers with electric, natural gas and/or water systems in 1 city and 16 villages and towns.

Investments and Other

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,100 acres of land in Minnesota, and earnings on cash and investments.

BNI Coal

BNI Coal is a supplier of lignite in North Dakota, producing about 4 million tons annually. Two electric generating cooperatives, Minnkota Power and Square Butte, presently consume virtually all of BNI Coal’s production of lignite under a cost plus fixed fee coal supply agreement extending through 2026. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 11. Commitments, Guarantees and Contingencies.) The mining process disturbs and reclaims between 200 and 250 acres per year. Laws require that the reclaimed land be at least as productive as it was prior to mining. As of December 31, 2012, BNI had a $11.0 million asset reclamation obligation ($10.3 million at December 31, 2011) included in other non-current liabilities on our Consolidated Balance Sheet. These costs are included in the cost plus fixed fee contract, for which an asset reclamation cost receivable was included in other non-current assets on our Consolidated Balance Sheet. The asset reclamation obligation is guaranteed by surety bonds and a letter of credit. (See Note 11. Commitments, Guarantees and Contingencies.) BNI Coal has lignite reserves of an estimated 650 million tons.

ALLETE 2012 Form 10-K

19

Investments and Other (Continued)

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. ALLETE does not intend to acquire additional Florida real estate.

Our two major development projects are Town Center and Palm Coast Park. Another major project, Ormond Crossings, is in the permitting stage. The City of Ormond Beach, Florida, approved a development agreement for Ormond Crossings which will facilitate development of the project as currently planned. Separately, the Lake Swamp wetland mitigation bank was permitted on land that was previously part of Ormond Crossings. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook for more information on ALLETE Properties’ land holdings.

Seller Financing. ALLETE Properties occasionally provides seller financing to certain qualified buyers. At December 31, 2012, outstanding finance receivables were $1.4 million, net of reserves, with maturities through 2014. These finance receivables accrue interest at market-based rates and are collateralized by the financed properties.

Regulation. A substantial portion of our development properties in Florida are subject to federal, state and local regulations, and restrictions that may impose significant costs or limitations on our ability to develop the properties. Much of our property is vacant land and some is located in areas where development may affect the natural habitats of various protected wildlife species or in sensitive environmental areas such as wetlands.

ALLETE Clean Energy

In June 2011, we established ALLETE Clean Energy, a wholly-owned subsidiary of ALLETE. ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. 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. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Non-Rate Base Generation

As of December 31, 2012, non-rate base generationconsists of 29 MW of generation at Rapids Energy Center. In 2012, we sold 0.1 million MWh of non-rate base generation (0.1 million in 2011 and 0.1 million in 2010).

Non-Rate Base Power Supply	Unit No.	Year Installed	Year Acquired	Net Capability (MW)
Rapids Energy Center (a)
in Grand Rapids, MN
Steam – Biomass (b)	6 & 7	1969, 1980	2000	28
Hydro – Conventional Run-of-River	4 & 5	1917, 1948	2000	1

(a) The net generation is primarily dedicated to the needs of one customer.

(b) Rapids Energy Center’s fuel supply is supplemented by coal.

On December 19, 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations (see Item 1. Business – Regulated Operations – Regulatory Matters.).

ALLETE 2012 Form 10-K

20

Environmental Matters

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

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to expected future restrictive environmental requirements imposed through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible ranges of future environmental regulations to project power supply trends and impacts on customers. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

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

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits. Resolution of the NOVs will likely result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to estimate the expenditures, or range of expenditures that may be required upon resolution. Any costs of installing additional pollution control equipment would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, which replaced the EPA’s 2005 CAIR. However, on August 21, 2012, a three judge panel of the District of Columbia Circuit Court of Appeals vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. The EPA and other parties to the case have until April 24, 2013, to request that the Supreme Court review the matter. The CSAPR would have required states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR did not directly require the installation of controls. Instead, the rule would have required facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would have been allocated to facilities from each state’s annual budget and would also have been able to be bought and sold.

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

ALLETE 2012 Form 10-K

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Environmental Matters (Continued)

Air (Continued)

Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Based on our expected generation, these emission reductions would have satisfied Minnesota Power’s SO₂ and NO_X emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2012. Minnesota Power will continue to track the EPA activity related to promulgation of a CSAPR replacement rule. We are unable to predict any additional compliance costs we might incur if the CSAPR is reinstated or if a CSAPR replacement rule is promulgated.

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

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

In December 2011, the EPA published in the Federal Register a proposal to approve the trading program in the CSAPR as an alternative to determining BART. However, as a result of the August 2012 District of Columbia Circuit Court of Appeals decision to vacate the CSAPR (See CSAPR), Minnesota Power is now evaluating whether significant additional expenditures at Taconite Harbor Unit 3 will be required to comply with BART requirements under the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation to bring Taconite Harbor Unit 3 into compliance with the Regional Haze Rule requirements. It is uncertain what controls would ultimately be required at Taconite Harbor Unit 3 under this scenario. On January 30, 2013, Minnesota Power announced “EnergyForward”, a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes retiring Taconite Harbor Unit 3 in 2015, subject to MPUC approval. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

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 on February 16, 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 they have approved Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas addressing the MATS requirements. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

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. On January 9, 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released on December 21, 2012. Major sources have three years to achieve compliance with the final rule. Minnesota Power is in the process of assessing the impact of this rule on our affected units including the Hibbard Renewable Energy Center and Rapids Energy Center. Costs for complying with the final rule cannot be estimated at this time.

ALLETE 2012 Form 10-K

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Environmental Matters (Continued)

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

Proposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with a 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 2013.

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM_2.5) standard; the annual PM_2.5 standard and the 24-hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM_2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM_2.5 standards on June 14, 2012.

On December 14, 2012, the EPA confirmed in a final rule that the current annual PM_2.5 standard, which has been in place since 1997, will be lowered, while retaining the current 24-hour PM_2.5 standard. To implement the new lower annual PM_2.5 standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects and permits must comply with the new lower standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling. To bridge the transition to the lower standard, the EPA is finalizing a grandfathering provision to ensure that projects and pending permits already underway are not unduly delayed.

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

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

In late 2011, the MPCA initiated modeling activities that included approximately 65 sources within Minnesota that emit greater than 100 tons of SO₂ per year. However, on April 12, 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.

ALLETE 2012 Form 10-K

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Environmental Matters (Continued)

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

• Expand our renewable energy supply;

• Provide energy conservation initiatives for our customers and engage in other demand side efforts;

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

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

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, at existing facilities that undergo major modifications and at 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 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.

On March 28, 2012, the EPA announced its proposed rule to apply CO₂ emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The proposed NSPS apply only to new or re-powered units and were open for public comment through June 25, 2012. It is anticipated that the EPA will issue NSPS for existing fossil fuel-fired generating units in the future. We cannot predict what CO₂ control measures, if any, may be required by such NSPS.

Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. On June 26, 2012, the United States District Court for the District of Columbia upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. Comments to the permitting guidance were submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

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

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA published in the Federal Register proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes and have a design intake flow of greater than 2 million gallons per day to limit the number of aquatic organisms that are killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011 and the EPA is obligated to finalize the rule by June 27, 2013. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

ALLETE 2012 Form 10-K

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Environmental Matters (Continued)

Water (Continued)

Steam Electric Power Generating Effluent Guidelines. In late 2009, the EPA announced that it will be reviewing and reissuing the federal effluent guidelines for steam electric stations. These are the underlying federal water discharge rules that apply to all steam electric stations. It is expected that the EPA will publish the proposed new rule in April 2013 and a final rule in 2014. As part of the review phase for this new rule, the EPA issued an Information Collection Request (ICR) in June 2010, to most thermal electric generating stations in the country, including all five of Minnesota Power’s generating stations. The ICR was completed and submitted to the EPA in September 2010, for Boswell, Laskin, Taconite Harbor, Hibbard and Rapids Energy Center. The ICR was designed to gather extensive information on the nature and extent of all water discharge and related wastewater handling at power plants. The information gathered through the ICR will form a basis for development of the eventual new rule, which could include more restrictive requirements on wastewater discharge, flue gas desulfurization and wet ash handling operations. We are unable to predict the costs we might incur to comply with potential future water discharge regulations at this time.

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

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its coal-fired electric generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. In June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash. Comments on the proposed rule were due in November 2010. It is estimated that the final rule will be published in 2013. 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.

Employees

At December 31, 2012, ALLETE had 1,361 employees, of which 1,322 were full-time.

Minnesota Power and SWL&P had an aggregate 593 employees who are members of IBEW Local 31. The current labor agreements with IBEW Local 31 expire on January 31, 2014.

BNI Coal had 162 employees, of which 117 are members of IBEW Local 1593. The current labor agreement between BNI Coal and IBEW Local 1593 expires on March 31, 2014.

Availability of Information

ALLETE makes its SEC filings, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(e) or 15(d) of the Securities Exchange Act of 1934, available free of charge on ALLETE’s website, www.allete.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC.

ALLETE 2012 Form 10-K

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Executive Officers of the Registrant

As of February 15, 2013, these are the executive officers of ALLETE:

Executive Officers	Initial Effective Date
Alan R. Hodnik, Age 53
Chairman, President and Chief Executive Officer – ALLETE	May 10, 2011
President and Chief Executive Officer – ALLETE	May 1, 2010
President – ALLETE	May 1, 2009
Chief Operating Officer – Minnesota Power	May 8, 2007
Robert J. Adams, Age 50
Vice President – Business Development and Chief Risk Officer	May 13, 2008
Vice President – Utility Business Development	February 1, 2004
Deborah A. Amberg, Age 47
Senior Vice President, General Counsel and Secretary	January 1, 2006
Steven Q. DeVinck, Age 53
Controller and Vice President – Business Support	December 5, 2009
Controller	July 12, 2006
David J. McMillan, Age 51
Senior Vice President – External Affairs – ALLETE	January 1, 2012
Senior Vice President – Marketing, Regulatory and Public Affairs – ALLETE	January 1, 2006
Executive Vice President – Minnesota Power	January 1, 2006
Mark A. Schober, Age 57
Senior Vice President and Chief Financial Officer	July 1, 2006
Donald W. Stellmaker, Age 55
Vice President, Corporate Treasurer	August 19, 2011
Treasurer	July 24, 2004

All of the executive officers have been employed by us for more than five years in executive positions.

There are no family relationships between any of the executive officers. All officers and directors are elected or appointed annually.

The present term of office of the executive officers listed above extends to the first meeting of our Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May 14, 2013.

ALLETE 2012 Form 10-K

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Item 1A. Risk Factors

The risks and uncertainties discussed below, as well as other information set forth in this Form 10-K, could materially affect our business, financial condition and results of operations and should be carefully considered by stakeholders. The risks and uncertainties in this section are not the only ones we face. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations.

Our results of operations could be negatively impacted if our Large Power Customers experience an economic downturn,incurwork stoppages or fail to compete effectively.

Our 9 Large Power Customers accounted for approximately 33 percent of our 2012 consolidated operating revenue (34 percent in 2011; 31 percent in 2010). One of these customers accounted for 12.3 percent of consolidated revenue in 2012 (12.6 percent in 2011; 12.5 percent in 2010). These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the marketplace. Many of our large power customers also have unionized workforces which put them at risk for work stoppages. In addition, the North American paper and pulp industry also faces declining demand due to the impact of electronic substitution for print and changing customer needs.

Accordingly, if our customers experience an economic downturn, incur a work stoppage (including strikes, lock-outs or other events), fail to compete effectively in the economy, or incur decreased demand for their product, there could be material adverse effects on their operations and, consequently, could have a negative impact on our results of operations if we are unable to remarket at similar prices the energy that would otherwise have been sold to such Large Power Customers.

Our utility operations are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.

We are subject to an extensive legal and regulatory framework imposed under federal and state law including regulations administered by the FERC, the MPUC, the PSCW, the NDPSC and the EPA as well as regulations administered by other organizations including the NERC. These laws and regulations relate to allowed rates of return, capital structure, financings, rate and cost structure, acquisition and disposal of assets and facilities, construction and operation of generation, transmission and distribution facilities (including the ongoing maintenance and reliable operation of such facilities), recovery of purchased power costs and capital investments, approval of integrated resource plans and present or prospective wholesale and retail competition, among other things. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. Compliance with these standards may lead to increased operating costs and capital expenditures. If we were found to not be in compliance with these mandatory reliability standards or other statutes, rules and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations.(See Item 1. Business – Regulated Operations – Regulatory Matters.)

These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary permits, licenses, approvals and certificates for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.

Our ability to obtain rate adjustments to maintain current rates of return depends upon regulatory action under applicable statutes and regulations, and we cannot provide assurance that rate adjustments will be obtained or current authorized rates of return on capital will be earned. Minnesota Power and SWL&P, from time to time, file rate cases with, or otherwise seek cost recovery authorization from, federal and state regulatory authorities. If Minnesota Power and SWL&P do not receive an adequate amount of rate relief in rate cases, including if rates are reduced, if increased rates are not approved on a timely basis or costs are otherwise unable to be recovered through rates, or if cost recovery is not achieved at the requested level, we may experience an adverse impact on our financial condition, results of operations and cash flows. We are unable to predict the impact on our business and results of operations from future legislation or regulatory activities of any of these agencies or organizations.

ALLETE 2012 Form 10-K

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Item 1A. Risk Factors (Continued)

Our operations could be adversely impacted by the physical risks associated with climate change.

The scientific community generally accepts that emissions of GHGs are linked to global climate change. Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs. An extreme weather event within our utility service areas can also directly affect our capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. These all have the potential to adversely affect our business and operations.

Our operations could be adversely impacted by initiatives designed to reduce the impact of GHG emissions such as CO₂from our generating facilities.

Proposals for voluntary initiatives to reduce GHGs such as CO₂, a by-product of burning fossil fuels, have been discussed within Minnesota, among a group of Midwestern states that includes Minnesota and in the United States Congress. Coal is currently the primary fuel source for 92 percent of the energy produced by our generating facilities.

There is significant uncertainty regarding whether new laws or regulations will be adopted to reduce GHGs and what affect any such laws or regulations would have on us. Future limits on GHG emissions would likely require us to incur significant increases in capital expenditures and operating costs, which if excessive, could result in the closure of certain coal-fired energy centers, impairment of assets, or otherwise materially adversely affect our results of operations, particularly if implementation costs are not fully recoverable from customers.

Our operations pose certain environmental risks that could adversely affect our results of operations and financial condition.

We are subject to extensive environmental laws and regulations affecting many aspects of our present and future operations, including air quality, water quality, waste management, reclamation, hazardous wastes and natural resources. These laws and regulations can result in increased capital, environmental emission allowance trading, operating and other costs, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions, coal ash and water discharge.

These laws and regulations could restrict the output of some existing facilities, limit the use of some fuels required for the production of electricity, require additional pollution control equipment, require participation in environmental emission allowance trading, and/or lead to other environmental considerations and costs, which could have a material adverse impact on our business, operations and results of operations.

These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both governmental authorities and private parties may seek to enforce applicable environmental laws and regulations. We cannot predict the financial or operational outcome of any related litigation that may arise.

Existing environmental regulations may be revised and new regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our results of operations.

We cannot predict the amount or timing of all future expenditures related to environmental matters because of the uncertainty as to applicable regulations or requirements. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Violations of certain environmental statutes, rules and regulations could expose ALLETE to third party disputes and potentially significant monetary penalties, as well as other sanctions for non-compliance.

ALLETE 2012 Form 10-K

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Item 1A. Risk Factors (Continued)

We rely on access to financing sources and capital markets. If we do not have access to sufficient capital in the amounts and at the times needed, our ability to execute our business plans, make capital expenditures or pursue other strategic actions that we may otherwise rely on for future growth could be impaired.

We rely on access to capital markets as sources of liquidity for capital requirements not satisfied by our cash flow from operations. If we are not able to access capital on satisfactory terms, the ability to implement our business plans may be adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access capital markets. Such disruptions could include a severe prolonged economic downturn, the financial distress of non-affiliated industry leaders of other electric utility companies or the financial services sector, deterioration in capital market conditions, or volatility in commodity prices.

The operation and maintenance of our generating facilities involve risks that could significantly increase the cost of doing business.

The operation of generating facilities involves many risks, including start-up operations risks, breakdown or failure of facilities, the dependence on a specific fuel source, inadequatefuel supply,or availability of fuel transportation, or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency, the occurrence of any of which could result in lost revenues, increased expenses or both. A significant portion of Minnesota Power’s facilities were constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to continue operating at peak efficiency. This equipment is also likely to require periodic upgrades and improvements due to changing environmental standards and technological advances. Minnesota Power could be subject to costs associated with any unexpected failure to produce power, including failure caused by breakdown or forced outage, as well as repairing damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events. Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs and/or the write-off of our investment in the project or improvement.

Our electrical generating operations may not have access to adequate and reliable transmission and distribution facilities necessary to deliver electricity to our customers.

Minnesota Power depends on its own transmission and distribution facilities, and facilities owned by other utilities, to deliver the electricity produced and sold to our customers, and to other energy suppliers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered. We may have to forgo sales or may have to buy more expensive wholesale electricity that is available in the capacity-constrained area. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact the satisfaction of our customers with our service, which could have a material impact on our business, operations or results of operations.

The price of electricity and fuel may be volatile.

Volatility in market prices for electricity and fuel could adversely impact our results of operations and financial condition and may result from:

• severe or unexpected weather conditions and natural disasters;

• seasonality;

• changes in electricity usage;

• transmission or transportation constraints, inoperability or inefficiencies;

• availability of competitively priced alternative energy sources;

• changes in supply and demand for energy;

• changes in power production capacity;

• outages at Minnesota Power’s generating facilities or those of our competitors;

• availability of fuel transportation;

• changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;

• wars, sabotage, terrorist acts or other catastrophic events; and

• federal, state, local and foreign energy, environmental, or other regulation and legislation.

Since fluctuations in fuel expense related to our regulated utility operations are passed on to customers through our fuel clause, risk of volatility in market prices for fuel and electricity primarily impacts our sales to Other Power Suppliers.

ALLETE 2012 Form 10-K

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Item 1A. Risk Factors (Continued)

The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have an adverse effect on our operations.

The success of our business heavily depends on the leadership of our executive officers and key employees to implement our business strategy. The inability to maintain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. Personnel costs may increase due to competitive pressures or terms of collective bargaining agreements with union employees. We believe we have good relations with our members of IBEW Local 31 and IBEW Local 1593, and have contracts in place through January 31, 2014, and March 31, 2014, respectively.

Market performance and other changes could decrease the value of pension and postretirement benefit plan assets, which may result in significant additional funding requirements and increased annual expenses.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postretirement benefit plans. We have significant obligations to these plans and the trusts hold significant assets. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected rates of return. A decline in the market value of the pension and postretirement benefit plan assets would increase the funding requirements under our benefit plans if asset returns do not recover. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements. Our pension and postretirement benefit plan costs are generally recoverable in our electric rates as allowed by our regulators. However, there is no certainty that regulators will continue to allow recovery of these rising costs in the future.

Emerging technologies may adversely affect our business operations.

While the pace of technology development has been increasing, the basic structure of energy production, sale and delivery upon which our business model is based has remained substantially unchanged. The development of new commercially viable technology in areas such as distributed generation, energy storage and energy conservation could fundamentally change demand for our current products and services.

We may be vulnerable to cyber attacks.

We could be subject to computer viruses, terrorism, theft and sabotage, which may disrupt our operations and/or adversely impactour results of operations. Our generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of cyber-terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. We operate in a highly regulated industrythat requires the continued operation of sophisticated information technology systems and network infrastructure. Our technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows.

The results from any acquisitions of assets or businesses made by us, or strategic investments that we may make, may not achieve the results that we expect or seek and may adversely affect our financial condition and results of operations.

Acquisitions are subject to uncertainties. If we are unable to successfully manage future acquisitions or strategic investments it could have an adverse impact on our results of operations. Our actual results may also differ from our expectations due to factors such as the ability to obtain timely regulatory or governmental approvals, integration and operational issues and the ability to retain management and other key personnel.

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Item 1A. Risk Factors (Continued)

We may not be able to successfully implement our strategic objectives of growing load at the utility, due to the inability of current and potential industrial customers to obtain necessary governmental permits in order to successfully implement expansion plans.

As part of our long-term strategy, we pursue new wholesale and retail loads in and around our service territory. Currently, there are several companies in northeastern Minnesota that are in the process of developing natural resource-based projects that represent long-term growth potential and load diversity for Minnesota Power. These projects may include construction of new facilities and restarts of old facilities, both of which require permitting and/or approvals to be obtained before the projects can be successfully implemented. If a project cannot be implemented due to certain governmental (including environmental) permits and approvals not being obtained, our long-term strategy and thus our results of operations could be adversely impacted.

Weak real estate market conditions in Florida may continue to adversely affect our strategy to sell our Florida real estate.

ALLETE intends to sell its Florida land assets when opportunities arise. However, if weak market conditions continue, the impact on our future operations would be the continuation of little to no sales while still incurring operating expenses such as community development district assessments and property taxes which could result in continued annual net operating losses at ALLETE Properties. The properties could also be at risk for impairment which could adversely impact our results of operations. (See Note 1. Operations and Significant Accounting Policies – Impairment of Long-Lived Assets.)

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

A discussion of our properties is included in Item 1. Business and is incorporated by reference herein.

Item 3. Legal Proceedings

A discussion of material legal and regulatory proceedings is included in Item 1. Business and is incorporated by reference herein.

United Taconite Lawsuit. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of December 31, 2012, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance coverage for potential loss.

We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Form 10-K.

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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends, without interruption, on our common stock since 1948. A quarterly dividend of $0.475 per share on our common stock is payable on March 1, 2013, to the shareholders of record on February 15, 2013.

The following table shows dividends declared per share, and the high and low prices of our common stock for the periods indicated as reported by the NYSE:

		2012				2011
	Price Range		Dividends		Price Range		Dividends
Quarter	High	Low	Declared		High	Low	Declared
First	$42.49	$39.98		$0.46	$39.36	$36.33		$0.445
Second	$41.99	$38.03	0.46		$41.43	$37.87	0.445
Third	$42.66	$40.33	0.46		$42.10	$35.51	0.445
Fourth	$42.09	$37.73	0.46		$42.54	$35.14	0.445
Annual Total				$1.84				$1.78

At February 1, 2013, there were approximately 26,000 common stock shareholders of record.

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Item 6. Selected Financial Data

	2012			2011			2010			2009			2008
Millions
Operating Revenue		$961.2			$928.2			$907.0			$759.1			$801.0
Operating Expenses	806.0			778.2			771.2			653.1			679.2
Net Income	97.1			93.6			74.8			60.7			83.0
Less: Non-Controlling Interest in Subsidiaries (a)	—			(0.2		)	(0.5		)	(0.3		)	0.5
Net Income Attributable to ALLETE	97.1			93.8			75.3			61.0			82.5
Common Stock Dividends	69.1			62.1			60.8			56.5			50.4
Earnings Retained in Business		$28.0			$31.7			$14.5			$4.5			$32.1
Shares Outstanding – Millions
Year-End	39.4			37.5			35.8			35.2			32.6
Average (b)
Basic	37.6			35.3			34.2			32.2			29.2
Diluted	37.6			35.4			34.3			32.2			29.3
Diluted Earnings Per Share		$2.58			$2.65			$2.19			$1.89			$2.82
Total Assets		$3,253.4			$2,876.0			$2,609.1			$2,393.1			$2,134.8
Long-Term Debt	933.6			857.9			771.6			695.8			588.3
Return on Common Equity	8.6		%	9.1		%	7.8		%	6.9		%	10.7		%
Common Equity Ratio	54		%	56		%	56		%	57		%	58		%
Dividends Declared per Common Share		$1.84			$1.78			$1.76			$1.76			$1.72
Dividend Payout Ratio	71		%	67		%	80		%	93		%	61		%
Book Value Per Share at Year-End		$30.50			$28.77			$27.25			$26.39			$25.37
Capital Expenditures by Segment
Regulated Operations		$418.2			$228.0			$256.4			$299.2			$317.0
Investments and Other	14.0			18.8			3.6			4.5			5.9
Total Capital Expenditures		$432.2			$246.8			$260.0			$303.7			$322.9

(a) In 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased.

(b) Excludes unallocated ESOP shares.

ALLETE 2012 Form 10-K

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our consolidated financial statements and notes to those statements and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this report 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-K under the headings: “Forward-Looking Statements” located on page 6 and “Risk Factors” located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only ones facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the concerns set forth in this Form 10-K are realized.

Overview

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,100 acres of land in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2012, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

2012 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2012, to the year ended December 31, 2011.

Consolidated net income attributable to ALLETE for 2012 was $97.1 million, or $2.58 per diluted share, compared to $93.8 million, or $2.65 per diluted share, for 2011. Net income for 2011 included the reversal of a $6.2 million, or $0.18 per share, deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. Net income for 2011 also included the recognition of a $2.9 million, or $0.08 per share, income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. Net income for 2012 reflected higher cost recovery rider revenue and renewable tax credits and increased sales to our industrial customers. These increases were partially offset by increased operation and maintenance, depreciation and interest expenses, as well as higher costs under our Square Butte PPA. Earnings per share dilution was $0.16 as a result of additional shares of common stock outstanding in 2012. (See Note 12. Common Stock and Earnings Per Share.)

Regulated Operations net income attributable to ALLETE was $96.1 million in 2012, compared to $100.4 million in 2011. Net income for 2011 included the reversal of a $6.2 million, or $0.18 per share, deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. Net income for 2011 also included the recognition of a $2.9 million, or $0.08 per share, income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. Net income for 2012 reflected higher cost recovery rider revenue and renewable tax credits, and increased sales to industrial customers. These increases were partially offset by increased operating and maintenance, depreciation and interest expenses, as well as higher costs under our Square Butte PPA.

Investments and Other reflected net income attributable to ALLETE of $1.0 million for 2012, compared to a net loss of $6.6 million in 2011. The increase in 2012 was primarily due to lower state income tax and interest expense, partially offset by increased business development expenses.

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2012 Compared to 2011

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

Regulated Operations

Operating Revenueincreased$22.5 million, or 3 percent, from 2011 primarily due to higher cost recovery rider revenue and transmission revenue, partially offset by lower fuel adjustment clause recoveries, lower revenue from our municipal customers and a 0.7 percent decrease in kilowatt-hours sold.

Cost recovery rider revenue increased $22.1 million due to higher capital expenditures related to our Bison Wind Energy Center and CapX2020 projects.

Transmission revenue increased $7.3 million primarily due to higher MISO Regional Expansion Criteria and Benefits (RECB) revenue related to our investment in CapX2020.

Fuel adjustment clause recoveries decreased $1.7 million due to lower fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.)

Revenue from our municipal customers decreased $1.6 million primarily due to period-over-period fluctuations in the true-up for actual costs provisions of the contracts. The rates included in these contracts are calculated using a cost-based formula methodology that is set at July 1 each year using estimated costs and a true-up for actual costs the following year.

Revenue from Regulated Operations decreased $1.1 million due to a 0.7 percent reduction in kilowatt-hour sales. The decrease in kilowatt-hour sales was primarily due to lower sales to residential customers and Other Power Suppliers. Residential sales, as compared to 2011, were down primarily due to unseasonably warm weather during the first four months of 2012; heating degree days in Duluth, Minnesota were approximately 22 percent lower than in the first four months of 2011. Total kilowatt-hour sales to Other Power Suppliers decreased 9.3 percent from 2011. 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. These decreases were partially offset by higher sales to our industrial customers, which increased 1.9 percent over 2011.

Kilowatt-hours Sold	2012	2011	Quantity Variance		% Variance
Millions
Regulated Utility
Retail and Municipals
Residential	1,132	1,159	(27	)	(2.3	)
Commercial	1,436	1,433	3		0.2
Industrial	7,502	7,365	137		1.9
Municipals	1,020	1,013	7		0.7
Total Retail and Municipals	11,090	10,970	120		1.1
Other Power Suppliers	1,999	2,205	(206	)	(9.3	)
Total Regulated Utility Kilowatt-hours Sold	13,089	13,175	(86	)	(0.7	)

Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2012 (26 percent in 2011). Revenue from electric sales to paper, pulp and wood product customers accounted for 9 percent of consolidated operating revenue in 2012 (9 percent in 2011). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2012 (7 percent in 2011).

Operating Expenses increased $19.1 million, or 3 percent, from 2011.

Fuel and Purchased Power Expenseincreased$2.1 million, or 1 percent, from 2011 primarily due to a $3.2 million increase in the capacity component of our Square Butte PPA; the capacity component is not recovered through our fuel adjustment clause. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause (see Operating Revenue).

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2012 Compared to 2011 (Continued)

Regulated Operations (Continued)

Operating and Maintenance Expenseincreased$8.5 million, or 3 percent, from 2011 primarily due to increased salary, benefit, and transmission expenses. Benefit expenses increased primarily due to higher pension expense resulting from lower discount rates. Transmission expenses increased primarily due to higher MISO RECB expense. These increases were partially offset by lower plant outage and maintenance expenses in 2012.

Depreciation Expenseincreased$8.5 million, or 10 percent, from 2011 reflecting additional property, plant and equipment in service.

Interest Expenseincreased$4.0 million, or 11 percent, from 2011 primarily due to higher average long-term debt balances, partially offset by higher AFUDC - Debt.

Income Tax Expenseincreased$7.2 million, or 17 percent, from 2011 primarily due to the non-recurring tax benefits recorded in 2011 for the reversal of a $6.2 million deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and the recognition of a $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. The 2012 income tax expense was impacted by increased renewable tax credits over 2011.

Investments and Other

Operating Revenueincreased$10.5 million, or 14 percent, from 2011 primarily due to a $10.8 million increase in revenue at BNI Coal. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher revenue as a result of higher expenses in 2012. (See Operating Expenses.)

ALLETE Properties	2012			2011
Revenue and Sales Activity	Acres (a)	Amount		Acres (a)	Amount
Dollars in Millions
Revenue from Land Sales	—	—		3		$0.4
Other Revenue (b)			$2.1		0.9
Total ALLETE Properties Revenue			$2.1			$1.3

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

(b) For the year ended December 31, 2012, Other Revenue includes wetland mitigation bank credit sales of $1.1million. For the year ended December 31, 2011, Other Revenue includes a $0.4 million forfeited deposit due to the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables.

Operating Expenses increased $8.7 million, or 10 percent, from 2011 reflecting higher expenses at BNI Coal of $8.4 million primarily due to higher repairs, fuel costs and new equipment leases; these costs are recovered through the cost plus fixed fee contract. (See Operating Revenue.) The remaining increase was primarily due to higher business development expenses. These increases were partially offset by a $1.7 million pretax impairment charge taken at ALLETE Properties in 2011.

Interest Expense decreased $2.1 million, or 27 percent, from 2011 primarily due to an increase in the proportion of ALLETE interest expense allocated to Minnesota Power. We record interest expense for our Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the remaining balance to Investments and Other. Interest expense also decreased due to the reversal of interest accrued in previous years related to our uncertain tax positions.

Income Tax Benefits increased $4.8 million, or 63 percent, from 2011 due to lower state tax expense. State income tax expense was lower in 2012 primarily due to North Dakota income tax credits attributable to our North Dakota capital investment, and recognized as a result of ALLETE’s expected generation of future taxable income in excess of that generated by our Regulated Operations.

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2012 Compared to 2011 (Continued)

Income Taxes – Consolidated

For the year ended December 31, 2012, the effective tax rate was 28.1 percent (27.6 percent for the year ended December 31, 2011; the effective tax rate for the year ended December 31, 2011, was lowered by 4.8 percentage points due to the non-recurring reversal of the deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, and by 2.2 percentage points due to the non-recurring income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA). The increase in the effective tax rate from the year ended December 31, 2011, was primarily due to the 2011 non-recurring items above, which were offset by increased renewable tax credits in 2012. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, renewable tax credits and depletion, and in 2011, for the non-recurring items discussed above. (See Note 14. Income Tax Expense.)

2011 Compared to 2010

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

Regulated Operations

Operating Revenue increased $16.4 million, or 2 percent, from 2010 primarily due to increased sales to our retail and municipal customers, increased cost recovery rider revenue, higher fuel clause recoveries, increased financial incentives under the Minnesota Conservation Improvement Program, and implementation of final retail rates. These increases were partially offset by lower sales to Other Power Suppliers.

Revenue and kilowatt-hour sales to retail and municipal customers increased $21.5 million and 5.6 percent, respectively, from 2010 primarily due to a 8.2 percent increase in kilowatt-hour sales to our industrial customers and the implementation of final retail rates. Increased revenue from those sales was offset by a $30.5 million and a 19.7 percent decrease in revenue and kilowatt-hour sales, respectively, 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.

Kilowatt-hours Sold	2011	2010	Quantity Variance		% Variance
Millions
Regulated Utility
Retail and Municipals
Residential	1,159	1,150	9		0.8
Commercial	1,433	1,433	—		—
Industrial	7,365	6,804	561		8.2
Municipals	1,013	1,006	7		0.7
Total Retail and Municipals	10,970	10,393	577		5.6
Other Power Suppliers	2,205	2,745	(540	)	(19.7	)
Total Regulated Utility Kilowatt-hours Sold	13,175	13,138	37		0.3

Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2011 (24 percent in 2010). Revenue from electric sales to paper, pulp and wood product customers accounted for 9 percent of consolidated operating revenue in 2011 (9 percent in 2010). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2011 (6 percent in 2010).

Cost recovery rider revenue increased $12.2 million due to higher capital expenditures primarily related to our Bison 1 and CapX2020 projects.

Fuel adjustment clause recoveries increased $6.3 million, or 8 percent, from 2010 due to an increase in kilowatt-hour sales and higher fuel and purchased power costs attributable to our retail and municipal customers.

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2011 Compared to 2010 (Continued)

Regulated Operations (Continued)

Financial incentives under the Minnesota Conservation Improvement Program increased $5.9 million reflecting a shared savings model to recognize utility progress toward meeting the energy-saving goal of 1.5 percent established in the Next Generation Energy Act of 2007.

Wholesale rate revenue increased $5.6 million reflecting higher rates.

Operating Expenses were consistent with 2010 overall.

Fuel and Purchased Power Expense decreased $18.5 million, or 6 percent, from 2010 primarily due to a 23 percent reduction in MWhs purchased and lower purchased power prices. In 2010, additional purchased power was required to meet planned major outages at Boswell and Square Butte. Also included in 2010 was a $5.4 million charge for the write-off of a deferred fuel clause regulatory asset related to the 2008 rate case. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause (see Operating Revenue) and increased due to higher kilowatt-hour sales to these customers.

Operating and Maintenance Expense increased $9.2 million, or 3 percent, from 2010 primarily reflecting increased property tax and benefit expense. Property tax expense increased $5.5 million due to more taxable plant and higher rates while benefits increased $4.0 primarily due to increased pension costs as a result of lower discount rates.

Depreciation Expense increased $9.3 million, or 12 percent, from 2010 reflecting additional property, plant and equipment in service.

Interest Expense increased $3.5 million, or 11 percent, from 2010 primarily due to higher long-term debt balances.

Income Tax Expense decreased $8.4 million, or 16 percent, from 2010 primarily due to the reversal of a $6.2 million deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, increased renewable tax credits of $3.2 million and the recognition of a non-recurring $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. Also contributing to the decrease was a non-recurring income tax charge of $3.6 million resulting from the PPACA in the first quarter of 2010. (See Note 5. Regulatory Matters.)

Investments and Other

Operating Revenue increased $4.8 million, or 7 percent, from 2010 reflecting a $5.6 million increase in revenue at BNI Coal, partially offset by a $0.9 million decrease in revenue at ALLETE Properties. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher sales revenue as a result of higher expenses in 2011. (See Operating Expense.)

ALLETE Properties	2011			2010
Revenue and Sales Activity	Acres (a)	Amount		Acres (a)	Amount
Dollars in Millions
Revenue from Land Sales	3		$0.4	—	—
Other Revenue (b)		0.9				$2.2
Total ALLETE Properties Revenue			$1.3			$2.2

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

(b) For the year ended December 31, 2011, Other Revenue included a $0.4 million forfeited deposit due to the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables. For the year ended December 31, 2010, Other Revenue included a $0.7 million pretax gain due to the return of seller-financed property from an entity which filed for Chapter 11 bankruptcy in June 2009. Also included in 2010 were $0.3 million of forfeited deposits and $0.3 million related to a lawsuit settlement.

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2011 Compared to 2010 (Continued)

Investments and Other (Continued)

Operating Expenses increased $7.0 million, or 9 percent, from 2010 reflecting higher expenses at BNI Coal of $5.1 million primarily due to higher fuel costs; these costs were recovered through the cost plus fixed fee contract. (See Operating Revenue.) The remaining increase in 2011 was primarily attributable to higher business development, interest and investment-related expenses. Also contributing to the increased expenses was a $1.7 million pretax impairment charge taken at ALLETE Properties. In the fourth quarter of 2011, an impairment analysis of estimated future undiscounted cash flows was conducted and indicated that the cash flows were not adequate to recover the carrying basis of certain properties not strategic to our three major development projects. These increases were partially offset by a reduction in operating expenses at ALLETE Properties.

Income Taxes – Consolidated

For the year ended December 31, 2011, the effective tax rate was 27.6 percent (37.2 percent for the year ended December 31, 2010). The effective tax rate for the year ended December 31, 2011, was lowered by 4.8 percentage points due to the non-recurring reversal of the deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, and by 2.2 percentage points due to the income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. The decrease in the effective tax rate from the year ended December 31, 2010, was due to the 2011 non-recurring items above, and an increase in renewable tax credits. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for depletion, investment tax credits, and renewable tax credits. (See Note 14. Income Tax Expense.)

Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires management to make various estimates and assumptions that affect amounts reported in the consolidated financial statements. These estimates and assumptions may be revised, which may have a material effect on the consolidated financial statements. Actual results may differ from these estimates and assumptions. These policies are discussed with the Audit Committee of our Board of Directors on a regular basis. The following represent the policies we believe are most critical to our business and the understanding of our results of operations.

Regulatory Accounting. Our regulated utility operations are accounted for in accordance with the accounting standards for the effects of certain types of regulation. These standards require us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. This assessment considers factors such as, but not limited to, changes in the regulatory environment and recent rate orders to other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the assets and liabilities would be recognized in current period net income or other comprehensive income. (See Note 5. Regulatory Matters.)

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39

Critical Accounting Policies (Continued)

Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and postretirement benefit obligations in accordance with the accounting standards for defined benefit pension and other postretirement plans. These standards require the use of several important assumptions, including the expected long-term rate of return on plan assets and the discount rate, among others, in determining our obligations and the annual cost of our pension and postretirement benefits. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return. Our pension asset allocation at December 31, 2012, was approximately 54 percent equity securities, 28 percent debt, 13 percent private equity, and 5 percent real estate. Our postretirement health and life asset allocation at December 31, 2012, was approximately 56 percent equity securities, 35 percent debt, and 9 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2012 we used expected long-term rates of return of 8.25 percent in our actuarial determination of our pension expense and 6.60 percent to 8.25 percent in our actuarial determination of our other postretirement expense. The actuarial determination uses an asset smoothing methodology for actual returns to reduce the volatility of varying investment performance over time. We review our expected long-term rate of return assumption annually and will adjust it to respond to changing market conditions. A one-quarter percent decrease in the expected long-term rate of return would increase the annual expense for pension and other postretirement benefits by approximately $1.4 million, pretax.

The discount rate is computed using a yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality, long-term corporate bond rates at the valuation date. In 2012, we used discount rates of 4.54 percent and 4.56 percent in our actuarial determination of our pension and other postretirement expense, respectively. We review our discount rate annually and will adjust it to respond to changing market conditions. A one-quarter percent decrease in the discount rate would increase the annual expense for pension and other postretirement benefits by approximately $2.2 million, pretax. (See Note 15. Pension and Other Postretirement Benefit Plans.)

Impairment of Long-Lived Assets. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipmenton a quarterly basis.

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels into bulk sales, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to management’s best estimate of future sales prices, the holding period and timing of sales, the method of disposition and the future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to, and may vary among, each land parcel or bulk sale. If the excess of undiscounted cash flows over the carrying value of a property is small, there is a greater risk of future impairment in the event of such changes and any resulting impairment charges could be material.

Taxation. We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate and sales/use taxes. Judgments related to income taxes require the recognition in our financial statements of the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit. Tax positions that do not meet the “more-likely-than-not” criteria are reflected as a tax liability in accordance with the accounting standards for uncertainty in income taxes. We record a valuation allowance against our deferred tax assets to the extent it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

We are subject to income taxes in various jurisdictions. We make assumptions and judgments each reporting period to estimate our income tax assets, liabilities, benefits, and expenses. Judgments and assumptions are supported by historical data and reasonable projections. Our assumptions and judgments include projections of our future federal and state taxable income, and state apportionment, to determine our ability to utilize NOL and credit carryforwards prior to their expiration. Significant changes in assumptions regarding future federal and state taxable income could require valuation allowances which could result in a material impact on our results of operations.

ALLETE 2012 Form 10-K

40

Outlook

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

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

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

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

Regulated Operations. Minnesota Power’s long-term strategy is to be the leading electric energy provider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable requirements. Keeping the cost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain the viability of its customers. As part of maintaining cost competitiveness, Minnesota Power intends to reduce its exposure to possible future carbon and GHG legislation by reshaping its generation portfolio, over time, to reduce its reliance on coal. We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with legislators and regulators to earn a fair rate of return. We project that our Regulated Operations will not earn its allowed rate of return in 2013.

Regulatory Matters. Entities within our Regulated Operations segment are under the jurisdiction of the MPUC, the FERC or the PSCW. See Item 1. Business – Regulated Operations – Regulatory Matters for discussion of regulatory matters within our Minnesota, FERC, Wisconsin and North Dakota jurisdictions.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and wood products, and pipeline industries. In 2012, 57 percent (56 percent in 2011) of our Regulated Utility kilowatt-hour sales were made to our industrial customers in these industries.

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

ALLETE 2012 Form 10-K

41

Outlook (Continued)

Industrial Customers (Continued)

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The World Steel Association, an association of approximately 170 steel producers, national and regional steel industry associations, and steel research institutes representing around 85 percent of world steel production, projected U.S. steel consumption in 2013 will be similar to 2012. The American Iron and Steel Institute (AISI), an association of North American steel producers, reported that U.S. raw steel production operated at approximately 75 percent of capacity in 2012 (75 percent in 2011, 70 percent in 2010). Based on these projections, 2013 taconite production levels in Minnesota are expected to be similar to 2012. The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years.

Minnesota Power Taconite Customer Production
Year	Tons (Millions)
2012*	39
2011	39
2010	35
2009	17
2008	39
2007	38
2006	39
2005	40
2004	39
2003	34
Source: Minnesota Department of Revenue December 2012 Mining Tax Guide for years 2003 - 2011.
* Preliminary data from the Minnesota Department of Revenue.

Our taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We estimate that a one million ton change in our taconite customers’ production would change our annual earnings per share by approximately $0.03, net of power marketing sales at 2012 year-end prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Long-term reductions in production or a permanent shut down of a taconite customer may lead us to file a rate case to recover lost revenues.

Similar to our taconite customers, Minnesota Power’s four major paper mills ran at, or very near, full capacity for the majority of 2012. Similar levels are expected in 2013.

Northshore Mining Company. In November 2012, Cliffs Natural Resources Inc. announced an idling of two small production lines for all of 2013 at its Northshore Mining Company (Northshore) facility in Silver Bay, Minnesota. Northshore has on-site generation supplying most of its power needs at the Silver Bay facility and therefore, the production idling at Northshore will not have an adverse effect on Minnesota Power’s sales to taconite customers.

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 PolyMet, Mesabi Nugget, USS Corporation’s expansion at its Keewatin taconite facility, Essar Steel Limited Minnesota (Essar), and Magnetation. We cannot predict the outcome of these projects, but if these projects are constructed, Minnesota Power could serve up to approximately 600 MW of new retail or wholesale load.

ALLETE 2012 Form 10-K

42

Outlook (Continued)

Industrial Customers (Continued)

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 will address environmental issues, including those dealing with a land exchange between PolyMet and the U.S. Forest Service (USFS), which is critical to the mine site development. The EPA and the USFS joined as lead agencies in the SDEIS process. Release of the SDEIS is expected in the first half of 2013, to be followed by a public review and comment period. Assuming successful completion of the SDEIS process and subsequent issuance of permits, Minnesota Power could begin to supply between 45 MW and 70 MW of load as early as 2015 through a 10-year power supply contract that would begin upon start-up of the mining operations.

Mesabi Nugget. The construction of the initial Mesabi Nugget facility is complete and production began in January 2010. Mesabi Nugget continues to pursue permits for taconite mining activities on lands formerly mined by Erie Mining Company and LTV Steel Mining Company near Hoyt Lakes, Minnesota. Upon receipt of permits to mine, Mesabi Nugget could mine and self-supply its own iron ore concentrate about a year later, which would result in increased electrical loads above our current 20 MW long-term power supply contract with Mesabi Nugget which lasts at least through 2017. In the meantime, Mesabi Nugget will receive iron ore concentrate from a new Mining Resources, LLC facility located near Chisholm, Minnesota.

Keewatin Taconite. In February 2008, USS Corporation announced its intent to restart a pellet line at its Keewatin Taconite (Keetac) processing facility. If restarted, this pellet line, which has been idle since 1980, could bring 3.6 million tons of additional pellet making capability to northeastern Minnesota and could result in over 60 MW of additional load for Minnesota Power. Project permits have been received and should the project be approved by USS Corporation’s Board of Directors, construction activities could commence immediately thereafter with production expected to begin approximately two to three years later.

City of Nashwauk. On May 1, 2012, the Company entered into a new formula-based wholesale electric sales agreement with the City of Nashwauk for all of the City’s electric service requirements, effective April 1, 2013 through June 30, 2024. A new Essar taconite facility is currently under construction in the city of Nashwauk, Minnesota. This facility will result in approximately 110 MW of additional load for Minnesota Power. Essar has indicated plans for start-up in mid-2013, with pellet production beginning during the second half of the year, resulting in a minimal impact on our results of operations until late 2013. ALLETE believes Essar will move towards full production capacity levels during 2014. Under the terms of a facilities construction agreement, Minnesota Power is constructing a 230 kV transmission system upgrade to serve the Essar load. This upgrade is expected to cost approximately $35 million and is scheduled to be in service in April 2013, at which time the City of Nashwauk will begin to provide electric service for Essar’s new taconite facility. Expansions for additional pellet production, production of direct reduced iron and production of steel slabs are also being considered for future years. In addition, on February 11, 2013, Essar announced a ten year iron ore pellet off-take agreement with ArcelorMittal. Under terms of the agreement Essar will supply 3.5 million tons of pellets annually to ArcelorMittal, which is expected to begin in late 2013.

Magnetation. In December 2011, the MPUC approved Minnesota Power’s electric service agreement with Magnetation. Magnetation, a company in northeastern Minnesota, 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 with equipment additions currently underway at the facility.

In October 2011, Magnetation and integrated steelmaker, AK Steel Corporation (AK Steel), announced a joint venture, Magnetation LLC, under which construction activities for two new facilities, near Calumet and Coleraine, Minnesota, are expected to commence in 2013. The Calumet facility could come on line in late 2014 and the Coleraine facility shortly thereafter to supply iron ore concentrate to Magnetation’s new pellet plant that is under construction in Reynolds, Indiana. Construction of these new iron ore concentrate facilities could result in approximately 20 MW of additional load for Minnesota Power.

ALLETE 2012 Form 10-K

43

Outlook (Continued)

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

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

• Planned installation of approximately $350 to $400 million in emissions control technology at our Boswell Unit 4 to further reduce emissions of SO₂, particulates and mercury. (See Item 1. Business – Regulated Operations – Regulatory Matters – Boswell Mercury Emissions Reduction Plan.)

• Planning for the proposed Great Northern Transmission Line to deliver hydroelectric power from northern Manitoba by 2020. (See Item 1. Business – Regulated Operations – Transmission and Distribution.)

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

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

Our “EnergyForward” initiatives are subject to regulatory approval, and will be included in Minnesota Power’s Integrated Resource Plan to be filed with the MPUC on March 1, 2013 (see Item 1. Business – Regulated Operations – Regulatory Matters).

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction and the Federal MATS rule. On August 31, 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 and are estimated to be between $350 million and $400 million. The MPCA has 180 days to comment on the mercury emissions reduction plan, which then is reviewed by the MPUC for a decision. We expect a decision by the MPUC on the plan in the third quarter of 2013. After approval by the MPUC we anticipate filing a petition to include investments and expenditures in customer billing rates.

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

Minnesota Power has taken several steps in executing its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. We have executed two long-term PPAs with an affiliate of NextEra Energy, Inc., for wind energy in North Dakota (Oliver Wind I and II). Other steps include Taconite Ridge, our 25 MW wind facility located in northeastern Minnesota, and our 292 MW Bison Wind Energy Center in North Dakota. Approximately 20 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2013.

North Dakota Wind Development. Minnesota Power uses our 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.

Our Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity. The 82 MW Bison 1 wind facility was completed in two phases; the first phase in 2010 and the second phase in January 2012. The 105 MW Bison 2 and 105 MW Bison 3 wind facilities were completed in December 2012. Total project costs for our Bison Wind Energy Center were $473.3 million through December 31, 2012. In September 2011, and November 2011, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively.

ALLETE 2012 Form 10-K

44

Outlook (Continued)

Renewable Energy (Continued)

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated with our Bison Wind Energy Center through that period. We anticipate filing a cost recovery petition with the MPUC in the first half of 2013 to update customer billing rates for subsequent investments and expenditures since 2011.

Our current capital expenditures plan includes additional wind energy investments in North Dakota in 2016 and 2017 to meet Minnesota’s 25 percent renewable energy mandate by 2025 (see Liquidity and Capital Resources – Capital Requirements). On January 2, 2013, The American Taxpayer Relief Act of 2012 extended the availability of the production tax credit for renewable energy facilities that commence construction by December 31, 2013. As a result, we are evaluating the acceleration of these investments so that construction would commence in 2013.

Manitoba Hydro. Minnesota Power has a long-term PPA with Manitoba Hydro for the purchase of 50 MW of capacity and energy associated with that capacity, which expires in April 2015. In addition, Minnesota Power signed a separate PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only transaction 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 with Manitoba Hydro, Minnesota Power will be purchasing 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 calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for a change in a governmental inflationary index and a natural gas index, as well as market prices. The agreement is subject to construction of additional transmission capacity between Manitoba and Minnesota’s Iron Range. In addition, we are exploring other regional grid enhancements that would allow for the movement of more renewable energy in the Upper Midwest while at the same time strengthening electric reliability in the region.

Integrated Resource Plan. In May 2011, the MPUC issued its final order approving our 2010 Integrated Resource Plan. As a condition of the final order, a required baseload diversification study evaluating the impact of additional environmental regulations over the next two decades was filed on February 6, 2012. Minnesota Power’s Integrated Resource Plan to be filed on March 1, 2013, will detail our “EnergyForward” strategic plan (see EnergyForward), and will include an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class.

Transmission. We plan to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. This includes the Great Northern Transmission Line and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. See also Item 1. Business – Regulated Operations.

Hydro Operations. On June 19 and 20, 2012, record rainfall and flooding occurred near Duluth, Minnesota and surrounding areas. The flooding impacted Minnesota Power’s hydro system, particularly the Thomson Energy Center, which is currently off-line due to damage to the forebay canal and flooding at the facility.

The Company has property insurance coverage of $100 million per occurrence and a deductible of $500,000 per event, providing coverage for water damage, equipment damage, and other structural damage at covered facilities. Damage to covered facilities, which includes significant electrical, mechanical and facility infrastructure damage at the Thomson facility, is estimated to be approximately $10 million, net of insurance.

The policy does not cover damage to land and earthen structures, which includes the majority of the damage to the forebay canal at the Thomson facility. Minnesota Power is continuing to assess options for rebuilding the forebay canal and is in close contact with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs. Until that assessment is complete, we are not able to fully estimate the capital cost and schedule for rebuilding the forebay canal and resuming generation; however, based on a preliminary evaluation, the capital rebuild cost is estimated to be approximately $15 million to $25 million. Any expenditures to rebuild the forebay canal would be capitalized. Minnesota Power is working towards returning to partial generation from the Thomson Energy Center by the end of 2013 and to full generation by the end of 2014.

ALLETE 2012 Form 10-K

45

Outlook (Continued)

Hydro Operations (Continued)

The Thomson facility represents approximately 5 percent of total company electric generation capability. Additional purchased power expense required due to the Thomson facility outage will be recovered through our fuel adjustment clause. We do not believe that this event will have a material impact on our financial position or results of operations.

Investments and Other

BNI Coal.In 2012, BNI Coal sold 4.4 million tons of coal (4.3 million tons in 2011) and anticipates 2013 sales will be similar to 2012. BNI continues to operate under a cost plus fixed fee agreement extending through 2026.

ALLETE Properties.ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. If weak market conditions continue for an extended period of time, the impact on our future operations would be the continuation of little or no sales while still incurring operating expenses and carrying costs such as community development district assessments and property taxes, or impairments. ALLETE does not intend to acquire additional Florida real estate.

Our two major development projects are Town Center and Palm Coast Park. Another major project, Ormond Crossings, is in the permitting stage. The City of Ormond Beach, Florida, approved a development agreement for Ormond Crossings which will facilitate development of the project as currently planned. Separately, the Lake Swamp wetland mitigation bank was permitted on land that was previously part of Ormond Crossings.

Summary of Development Projects (100% Owned)		Residential	Non-residential
Land Available-for-Sale	Acres (a)	Units (b)	Sq. Ft. (b,c)
Current Development Projects
Town Center	965	2,485	2,246,200
Palm Coast Park	3,888	3,554	3,096,800
Total Current Development Projects	4,853	6,039	5,343,000
Planned Development Project
Ormond Crossings	2,914	2,950	3,215,000
Other
Lake Swamp Wetland Mitigation Project	3,044	(d)	(d)
Total of Development Projects	10,811	8,989	8,558,000

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

(b) Units and square footage are estimated. Density at build out may differ from these estimates.

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

(d) The Lake Swamp wetland mitigation bank is a permitted, regionally significant wetlands mitigation bank. Wetland mitigation credits will be used at Ormond Crossings and are available-for-sale to developers of other projects that are located in the bank’s service area.

In addition to the three development projects and the mitigation bank, ALLETE Properties has 1,960 acres of other land available-for-sale.

ALLETE Clean Energy. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. On July 23, 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

ALLETE 2012 Form 10-K

46

Outlook (Continued)

Income Taxes. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2012. On an ongoing basis, ALLETE has certain tax credits and other tax adjustments that reduce the statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, renewable tax credits, AFUDC-Equity, domestic manufacturer’s deduction, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income from operations before 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 renewable tax credits as a result of additional wind generation, we expect our effective tax rate to be approximately 20 percent for 2013. We also expect that our effective tax rate will be lower than the statutory rate over the next ten years due to production tax credits attributable to our wind generation.

Liquidity and Capital Resources

Liquidity Position. ALLETE is well-positioned to meet the Company’s liquidity needs. As of December 31, 2012, we had cash and cash equivalents of $80.8 million, $406.4 million in available consolidated lines of credit and a debt-to-capital ratio of 46 percent.

Capital Structure. ALLETE’s capital structure for each of the last three years is as follows:

Year Ended December 31	2012		%	2011		%	2010		%
Millions
Common Equity		$1,201.0	54		$1,079.3	56		$976.0	55
Non-Controlling Interest	—		—	—		—	9.0		1
Long-Term Debt (Including Current Maturities)	1,018.1		46	863.3		44	785.0		44
Short-Term Debt	—		—	1.1		—	1.0		—
		$2,219.1	100		$1,943.7	100		$1,771.0	100

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

Year Ended December 31	2012			2011			2010
Millions
Cash and Cash Equivalents at Beginning of Period		$101.1			$44.9			$25.7
Cash Flows from (for)
Operating Activities	239.6			241.7			228.7
Investing Activities	(420.1		)	(240.9		)	(250.9		)
Financing Activities	160.2			55.4			41.4
Change in Cash and Cash Equivalents	(20.3		)	56.2			19.2
Cash and Cash Equivalents at End of Period		$80.8			$101.1			$44.9

Operating Activities. Cash from operating activities was $239.6 million for 2012 ($241.7 million for 2011; $228.7 million for 2010). Cash from operating activities was similar to 2011 as lower cash contributions to pension and other postretirement benefit plans ($8.8 million in 2012 and $24.7 million in 2011) were offset by higher cost recovery rider receivables in 2012 and income tax refunds received in 2011.

Cash from operating activities was higher in 2011 than 2010 primarily due to higher 2011 net income primarily from our Regulated Operations segment, decreased cash contributions to our pension and other postretirement employee benefit plans ($24.7 million in 2011 and $39.3 million in 2010), and increased customer deposits, partially offset by a decrease in accounts payable and higher inventory balances.

Investing Activities. Cash used for investing activities was $420.1 million for 2012 ($240.9 million for 2011; $250.9 million for 2010). The increase in cash used for investing activities was primarily due to higher capital expenditures in 2012 primarily related to our Bison Wind Energy Center.

ALLETE 2012 Form 10-K

47

Liquidity and Capital Resources (Continued)

Investing Activities (Continued)

Cash used for investing activities in 2011 was lower than 2010 primarily due to lower capital expenditures in 2011 and the redemption of ARS for $6.7 million in January 2011.

Financing Activities. Cash from financing activities was $160.2 million for 2012 ($55.4 million for 2011; $41.4 million for 2010). The increase in cash from financing activities in 2012 was primarily due to increased proceeds from long-term debt and common stock issuances.

Cash from financing activities was higher in 2011 compared to 2010 primarily due to increased proceeds from the issuances of common stock, partially offset by lower net proceeds of long-term debt in 2011.

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 December 31, 2012, we had available consolidated bank lines of credit aggregating $406.4 million, of which $150.0 million expires in January 2014, and $250.0 million expires in June 2015. In addition, we have 0.9 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 4.5 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.

Securities. We entered into a distribution agreement with KCCI, Inc., in February 2008, as amended most recently on August 3, 2012, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 4.5 million remain available for issuance. For the quarter ended December 31, 2012, 0.4 million shares of common stock were issued under this agreement, resulting in net proceeds of $17.9 million (for the quarter ended December 31, 2011, no shares were issued). For the year ended December 31, 2012, 1.3 million shares of common stock were issued under this agreement, resulting in net proceeds of $53.1 million (0.4 million shares for net proceeds of $16.0 million for the year ended December 31, 2011). The shares issued in 2012 were, and the remaining shares may be, offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement Nos. 333-170289.

For the year ended December 31, 2012, we issued a total of 0.5 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 $23.9 million. These shares of common stock were registered under Registration Statement Nos. 333-166515, 333-105225, 333-183051 and 333-162890, respectively.

On July 2, 2012, we issued $160.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in two series. (See Note 10. Short-Term and Long-Term Debt.) On July 16, 2012, we used a portion of the proceeds from the sale of the Bonds to redeem $6.0 million of 6.50 percent Industrial Development Revenue Bonds and to repay outstanding borrowings of $14.0 million on our $150.0 million line of credit. The remaining proceeds were used to fund utility capital expenditures and for general corporate purposes.

Financial Covenants. See Note 10. Short-Term and Long-Term Debt for information regarding our financial covenants.

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 11. Commitments, Guarantees and Contingencies.

Contractual Obligations and Commercial Commitments. ALLETE has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Following is a summarized table of contractual obligations and other commercial commitments at December 31, 2012.

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	Payments Due by Period
Contractual Obligations			Less than		1 to 3		4 to 5		After
As of December 31, 2012	Total		1 Year		Years		Years		5 Years
Millions
Long-Term Debt		$1,613.0		$129.8		$258.2		$127.6		$1,097.4
Pension	202.8		31.2		99.8		71.8		—
Other Postretirement Benefit Plans	53.9		7.6		26.6		19.7		—
Operating Lease Obligations	87.4		11.5		32.4		15.7		27.8
Uncertain Tax Positions (a)	—		—		—		—		—
Unconditional Purchase Obligations (b)	576.7		125.3		179.3		82.8		189.3
		$2,533.8		$305.4		$596.3		$317.6		$1,314.5

(a) Excludes $2.7 million of non-current unrecognized tax benefits due to uncertainty regarding the timing of future cash payments related to uncertain tax positions.

(b) Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only. Also excludes the agreement with Manitoba Hydro expiring in 2035, as our obligation under this contract is subject to the construction of a hydro generation facility by Manitoba Hydro and additional transmission capacity. Also, excludes Oliver I and II, as we only pay for energy as it is delivered to us. (See Item 1. Business – Regulated Operations – Power Supply.)

Long-Term Debt. Our long-term debt obligations, including long-term debt due within one year, represent the principal amount of bonds, notes and loans which are recorded on our Consolidated Balance Sheet, plus interest. The table above assumes that the interest rates in effect at December 31, 2012, remain constant through the remaining term. (See Note 10. Short-Term and Long-Term Debt.)

Pension and Other Postretirement Benefit Plans. Our pension and other postretirement benefit plan obligations represent our current estimate of employer contributions. Pension contributions will be dependent on several factors including realized asset performance, future discount rate and other actuarial assumptions, IRS and other regulatory requirements, and contributions required to avoid benefit restrictions for the pension plans. Funding for the other postretirement benefit plans is impacted by realized asset performance, future discount rate and other actuarial assumptions, and utility regulatory requirements. These amounts are estimates and will change based on actual market performance, changes in interest rates and any changes in governmental regulations. (See Note 15. Pension and Other Postretirement Benefit Plans.)

Unconditional Purchase Obligations. Unconditional purchase obligations represent our Square Butte, Manitoba Hydro and Minnkota Power, minimum purchase commitments under coal and rail contracts, and purchase obligations for certain capital expenditure projects. (See Note 11. Commitments, Guarantees and Contingencies.)

Under Minnesota Power’s PPA with Square Butte that extends through 2026, we are obligated to pay our pro rata share of Square Butte’s costs based on our entitlement to the output of Square Butte’s 455 MW coal-fired generating unit near Center, North Dakota. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s fixed costs consist primarily of debt service. The table above reflects our share of future debt service based on our output entitlement of 50 percent. (See Note 11. Commitments, Guarantees and Contingencies.)

We have a PPA with Manitoba Hydro that expires in April 2015. Under this agreement, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

On December 12, 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity over the term June 1, 2016 through May 31, 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

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Liquidity and Capital Resources (Continued)

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

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

(a) Includes collateralized pollution control bonds.

Common Stock Dividends. ALLETE is committed to providing a competitive dividend to its shareholders while at the same time funding its growth. The Company’s long-term objective is to maintain a dividend payout ratio similar to our peers and provide for future dividend increases. In 2012, we paid out 71 percent (67 percent in 2011; 80 percent in 2010) of our per share earnings in dividends. On January 23, 2013, our Board of Directors declared a dividend of $0.475 per share, which is payable on March 1, 2013, to shareholders of record at the close of business on February 15, 2013.

Capital Requirements

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

Capital Expenditures		2013		2014		2015		2016		2017		Total
Millions
Regulated Utility Operations
	Base and Other		$171		$168		$147		$155		$138		$779
	Cost Recovery (a)
	Environmental (b)	93		133		87		3		—		316
	Renewable (c)	2		8		—		68		158		236
	Transmission (d)	30		28		11		3		40		112
	Total Cost Recovery	125		169		98		74		198		664
Regulated Utility Capital Expenditures		296		337		245		229		336		1,443
Other		14		25		11		9		3		62
Total Capital Expenditures			$310		$362		$256		$238		$339		$1,505

(a) Estimated current capital expenditures recoverable outside of a rate case.

(b) Environmental capital expenditures primarily relate to compliance with the MATS rule for Boswell Unit 4. (See Note 11. Commitments, Guarantees and Contingencies.) Boswell Unit 4 capital expenditures included above reflect Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4. (See Note 4. Jointly-Owned Facilities.)

(c) Includes a total of $226 million in 2016 and 2017 related to additional wind generation of 100 MW. On January 2, 2013, the American Taxpayer Relief Act of 2012 extended the availability of the production tax credit for renewable energy facilities that commence construction by December 31, 2013. As a result, we are evaluating the acceleration of these investments so that construction would commence in 2013.

(d) Transmission capital expenditures related to CapX2020 are estimated at approximately $50 million over the 2013 to 2015 period. Capital expenditures of $38 million are included related to commencement of construction of the Great Northern Transmission Line. (See Item 1. Business – Regulated Operations – Transmission and Distribution.)

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Liquidity and Capital Resources (Continued)

Capital Requirements (Continued)

We intend to finance capital expenditures from a combination of internally generated funds and incremental debt and equity proceeds. Based on our anticipated capital expenditures reflected above, we project our rate base to grow by approximately 35 percent through 2017. Other proposed environmental regulations could result in future capital expenditures that are not included in the table above. Currently, future CapX2020 projects are under discussion and Minnesota Power may elect to participate on a project by project basis.

Environmental and Other Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Due to future restrictive environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. We are unable to predict the outcome of the issues discussed in Note 11. Commitments, Guarantees and Contingencies. (See Item 1. Business – Environmental Matters.)

Market Risk

Securities Investments

Available-for-Sale Securities. At December 31, 2012, our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits. (See Note 7. Investments.)

Interest Rate Risk. We are exposed to risks resulting from changes in interest rates as a result of our issuance of variable rate debt. We manage our interest rate risk by varying the issuance and maturity dates of our fixed rate debt, limiting the amount of variable rate debt, and continually monitoring the effects of market changes in interest rates. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. The table below presents the long-term debt obligations and the corresponding weighted average interest rate at December 31, 2012.

	Expected Maturity Date
Interest Rate Sensitive															Fair
Financial Instruments	2013		2014		2015		2016		2017		Thereafter		Total		Value
Dollars in Millions
Long-Term Debt
Fixed Rate		$72.2		$19.8		$1.7		$21.7		$51.2		$707.2		$873.8		$999.4
Average Interest Rate – %	5.2		6.6		3.2		7.3		5.9		5.2		5.3
Variable Rate		$12.3		$75.0		$15.7	—		—			$41.3		$144.3		$144.3
Average Interest Rate – % (a)	3.6		1.2		0.2		—		—		0.2		1.0

(a) Assumes rates in effect at December 31, 2012 remain constant through remaining term. The $75 million term loan maturing in 2014 has an effective fixed rate of 1.825% due to an interest rate swap.

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 December 31, 2012, and assuming no other changes to our financial structure, an increase of 100 basis points in interest rates would impact the amount of pretax interest expense by $0.7 million. This amount was determined by considering the impact of a hypothetical 100 basis point increase to the average variable interest rate on the variable rate debt outstanding as of December 31, 2012.

Commodity Price Risk. Our regulated utility operations incur costs for power and fuel (primarily coal and related transportation) in Minnesota and power and natural gas purchased for resale in our regulated service territory in Wisconsin. Our Minnesota regulated utility’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates. Conversely, costs below those in base rates result in a credit to our ratepayers. We seek to prudently manage our customers’ exposure to price risk by entering into contracts of various durations and terms for the purchase of power and coal and related transportation costs (Minnesota Power) and natural gas (SWL&P).

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Market Risk (Continued)

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

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

Recently Adopted Accounting Standards.

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

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk for information related to quantitative and qualitative disclosure about market risk.

Item 8. Financial Statements and Supplementary Data

See our consolidated financial statements as of December 31, 2012 and 2011, and for each of the three years in the period ended December 31, 2012, and supplementary data, which are indexed in Item 15(a).

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, as of December 31, 2012, we conducted an evaluation of the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures (as defined in Rules 13a-15(e) or 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, as of December 31, 2012, 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.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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Item 9A. Controls and Procedures (Continued)

Changes in Internal Controls

There has been no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other

Not applicable.

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Part III

Item 10. Directors, Executive Officers and Corporate Governance

Unless otherwise stated, the information required by this Item is incorporated by reference herein from our Proxy Statement for the 2013 Annual Meeting of Shareholders (2013 Proxy Statement) under the following headings:

• Directors. The information regarding directors will be included in the “Election of Directors” section;

• Audit Committee Financial Expert. The information regarding the Audit Committee financial expert will be included in the “Audit Committee Report” section;

• Audit Committee Members. The identity of the Audit Committee members will be included in the “Audit Committee Report” section;

• Executive Officers. The information regarding executive officers is included in Part I of this Form 10-K; and

• Section 16(a) Compliance. The information regarding Section 16(a) compliance will be included in the “Ownership of ALLETE Common Stock – Section 16(a) Beneficial Ownership Reporting Compliance” section.

Our 2013 Proxy Statement will be filed with the SEC within 120 days after the end of our 2012 fiscal year.

Code of Ethics. We have adopted a written Code of Ethics that applies to all of our employees, including our chief executive officer, chief financial officer and controller. A copy of our Code of Ethics is available on our website at www.allete.com and print copies are available without charge upon request to ALLETE, Inc., Attention: Secretary, 30 West Superior St., Duluth, Minnesota 55802. Any amendment to the Code of Ethics or any waiver of the Code of Ethics will be disclosed on our website at www.allete.com promptly following the date of such amendment or waiver.

Corporate Governance. The following documents are available on our website at www.allete.com and print copies are available upon request:

• Corporate Governance Guidelines;

• Audit Committee Charter;

• Executive Compensation Committee Charter; and

• Corporate Governance and Nominating Committee Charter.

Any amendment to these documents will be disclosed on our website at www.allete.com promptly following the date of such amendment.

Item 11. Executive Compensation

The information required for this Item is incorporated by reference herein from the “Compensation Discussion and Analysis,” the “Compensation of Directors and Executive Officers,” the “Executive Compensation Committee Report” and the “Director Compensation 2012” sections in our 2013 Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required for this Item is incorporated by reference herein from the “Ownership of ALLETE Common Stock – Securities Owned by Certain Beneficial Owners,” the “Ownership of ALLETE Common Stock – Securities Owned by Directors and Management” and the “Equity Compensation Plan Information” sections in our 2013 Proxy Statement.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required for this Item is incorporated by reference herein from the “Corporate Governance” section in our 2013 Proxy Statement.

We have adopted a Related Person Transaction Policy which is available on our website at www.allete.com. Print copies are available without charge, upon request. Any amendment to this policy will be disclosed on our website at www.allete.com promptly following the date of such amendment.

Item 14. Principal Accounting Fees and Services

The information required for this Item is incorporated by reference herein from the “Audit Committee Report” section in our 2013 Proxy Statement.

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Part IV

Item 15.     Exhibits and Financial Statement Schedules

(a)	Certain Documents Filed as Part of this Form 10-K.
(1)	Financial Statements	Page
	ALLETE
	Report of Independent Registered Public Accounting Firm	64
	Consolidated Balance Sheet at December 31, 2012 and 2011	65
	For the Three Years Ended December 31, 2012
	Consolidated Statement of Income	66
	Consolidated Statement of Comprehensive Income	67
	Consolidated Statement of Cash Flows	68
	Consolidated Statement of Shareholders’ Equity	69
	Notes to Consolidated Financial Statements	70
(2)	Financial Statement Schedules
	Schedule II – ALLETE Valuation and Qualifying Accounts and Reserves	113
	All other schedules have been omitted either because the information is not required to be reported by ALLETE or because the information is included in the consolidated financial statements or the notes.
(3)	Exhibits including those incorporated by reference.

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Exhibit Number
*3(a)1	—	Articles of Incorporation amended and restated as of May 8, 2001 (filed as Exhibit 3(b) to the March 31, 2001, Form 10-Q, File No. 1-3548).
*3(a)2	—	Amendment to Articles of Incorporation, dated as of May 12, 2009 (filed as Exhibit 3 to the June 30, 2009, Form 10-Q, File No. 1-3548).
*3(a)3	—	Amendment to Articles of Incorporation, dated as of May 19, 2010 (filed as Exhibit 3(a) to the May 14, 2010, Form 8-K, File No. 1-3548).
*3(a)4	—	Amendment to Certificate of Assumed Name, filed with the Minnesota Secretary of State on May 8, 2001 (filed as Exhibit 3(a) to the March 31, 2001, Form 10-Q, File No. 1-3548).
*3(b)	—	Bylaws, as amended effective May 11, 2010 (filed as Exhibit 3(b) to the May 14, 2010, Form 8-K, File No. 1-3548).
*4(a)1	—	Mortgage and Deed of Trust, dated as of September 1, 1945, between Minnesota Power & Light Company (now ALLETE) and The Bank of New York Mellon (formerly Irving Trust Company) and Philip L. Watson (successor to Richard H. West), Trustees (filed as Exhibit 7(c), File No. 2-5865).
*4(a)2	—	Supplemental Indentures to ALLETE’s Mortgage and Deed of Trust:
		Number	Dated as of	Reference File	Exhibit
		First	March 1, 1949	2-7826	7(b)
		Second	July 1, 1951	2-9036	7(c)
		Third	March 1, 1957	2-13075	2(c)
		Fourth	January 1, 1968	2-27794	2(c)
		Fifth	April 1, 1971	2-39537	2(c)
		Sixth	August 1, 1975	2-54116	2(c)
		Seventh	September 1, 1976	2-57014	2(c)
		Eighth	September 1, 1977	2-59690	2(c)
		Ninth	April 1, 1978	2-60866	2(c)
		Tenth	August 1, 1978	2-62852	2(d)2
		Eleventh	December 1, 1982	2-56649	4(a)3
		Twelfth	April 1, 1987	33-30224	4(a)3
		Thirteenth	March 1, 1992	33-47438	4(b)
		Fourteenth	June 1, 1992	33-55240	4(b)
		Fifteenth	July 1, 1992	33-55240	4(c)
		Sixteenth	July 1, 1992	33-55240	4(d)
		Seventeenth	February 1, 1993	33-50143	4(b)
		Eighteenth	July 1, 1993	33-50143	4(c)
		Nineteenth	February 1, 1997	1-3548 (1996 Form 10-K)	4(a)3
		Twentieth	November 1, 1997	1-3548 (1997 Form 10-K)	4(a)3
		Twenty-first	October 1, 2000	333-54330	4(c)3
		Twenty-second	July 1, 2003	1-3548 (June 30, 2003 Form 10-Q)	4
		Twenty-third	August 1, 2004	1-3548 (Sept. 30, 2004 Form 10-Q)	4(a)
		Twenty-fourth	March 1, 2005	1-3548 (March 31, 2005 Form 10-Q)	4
		Twenty-fifth	December 1, 2005	1-3548 (March 31, 2006 Form 10-Q)	4
		Twenty-sixth	October 1, 2006	1-3548 (2006 Form 10-K)	4
		Twenty-seventh	February 1, 2008	1-3548 (2007 Form 10-K)	4(a)3
		Twenty-eighth	May 1, 2008	1-3548 (June 30, 2008 Form 10-Q)	4
		Twenty-ninth	November 1, 2008	1-3548 (2008 Form 10-K)	4(a)3
		Thirtieth	January 1, 2009	1-3548 (2008 Form 10-K)	4(a)4
		Thirty-first	February 1, 2010	1-3548 (March 31, 2010 Form 10-Q)	4
		Thirty-second	August 1, 2010	1-3548 (Sept. 30, 2010 Form 10-Q)	4
		Thirty-third	July 1, 2012	1-3548 (July 2, 2012 Form 8-K)	4

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Exhibit Number
*4(b)1	—	Indenture of Trust, dated as of August 1, 2004, between the City of Cohasset, Minnesota and U.S. Bank National Association, as Trustee relating to $111 Million Collateralized Pollution Control Refunding Revenue Bonds (filed as Exhibit 4(b) to the September 30, 2004, Form 10-Q, File No. 1-3548).
*4(b)2	—	Loan Agreement, dated as of August 1, 2004, between the City of Cohasset, Minnesota and ALLETE relating to $111 Million Collateralized Pollution Control Refunding Revenue Bonds (filed as Exhibit 4(c) to the September 30, 2004, Form 10-Q, File No. 1-3548).
*4(c)1	—	Mortgage and Deed of Trust, dated as of March 1, 1943, between Superior Water, Light and Power Company and Chemical Bank & Trust Company and Howard B. Smith, as Trustees, both succeeded by U.S. Bank National Association, as Trustee (filed as Exhibit 7(c), File No. 2-8668).
*4(c)2	—	Supplemental Indentures to Superior Water, Light and Power Company’s Mortgage and Deed of Trust:
		Number	Dated as of	Reference File	Exhibit
		First	March 1, 1951	2-59690	2(d)(1)
		Second	March 1, 1962	2-27794	2(d)1
		Third	July 1, 1976	2-57478	2(e)1
		Fourth	March 1, 1985	2-78641	4(b)
		Fifth	December 1, 1992	1-3548 (1992 Form 10-K)	4(b)1
		Sixth	March 24, 1994	1-3548 (1996 Form 10-K)	4(b)1
		Seventh	November 1, 1994	1-3548 (1996 Form 10-K)	4(b)2
		Eighth	January 1, 1997	1-3548 (1996 Form 10-K)	4(b)3
		Ninth	October 1, 2007	1-3548 (2007 Form 10-K)	4(c)3
		Tenth	October 1, 2007	1-3548 (2007 Form 10-K)	4(c)4
		Eleventh	December 1, 2008	1-3548 (2008 Form 10-K)	4(c)3
*4(d)	—	Note Purchase Agreement, dated as of June 8, 2007, between ALLETE and Thrivent Financial for Lutherans and The Northwestern Mutual Life Insurance Company (filed as Exhibit 10(a) to the June 30, 2007, Form 10-Q, File No. 1-3548).
*4(e)	—	Term Loan Agreement, dated as of August 25, 2011, between ALLETE, Inc. and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4 to the August 31, 2011, Form 8-K, File No. 1-3548).
*10(a)	—	Power Purchase and Sale Agreement, dated as of May 29, 1998, between Minnesota Power, Inc. (now ALLETE) and Square Butte Electric Cooperative (filed as Exhibit 10 to the June 30, 1998, Form 10-Q, File No. 1-3548).
*10(b)	—	Credit Agreement, dated as of May 25, 2011, among ALLETE, Inc., as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and JPMorgan Securities LLC, as Sole Lead Arranger and Sole Book Runner (filed as Exhibit 99 to the May 27, 2011, Form 8-K, File No. 1-3548).
*10(c)	—	Credit Agreement, dated as of February 1, 2012, among ALLETE, Inc., as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and JPMorgan Securities LLC, as Sole Lead Arranger and Sole Book Runner (filed as Exhibit 10 to the February 6, 2012, Form 8-K, File No. 1-3548).
*10(d)1	—	Financing Agreement between Collier County Industrial Development Authority and ALLETE dated as of July 1, 2006 (filed as Exhibit 10(b)1 to the June 30, 2006, Form 10-Q, File No. 1-3548).
*10(d)2	—	Amended and Restated Letter of Credit Agreement, dated as of June 3, 2011, among ALLETE, the participating banks and Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (filed as Exhibit 10(b) to the June 30, 2011, Form 10-Q, File No. 1-3548).
*10(e)	—	Agreement dated December 16, 2005, among ALLETE, Wisconsin Public Service Corporation and WPS Investments, LLC (filed as Exhibit 10(g) to the 2009 Form 10-K, File No. 1-3548).
+*10(f)1	—	ALLETE Executive Annual Incentive Plan, as amended and restated, effective January 1, 2011 (filed as Exhibit 10(h)1 to the 2010 Form 10-K, File No. 1-3548).
+*10(f)2	—	ALLETE Executive Annual Incentive Plan Form of Awards Effective 2010 (filed as Exhibit 10(h)3 to the 2009 Form 10-K, File No. 1-3548).
+*10(f)3	—	ALLETE Executive Annual Incentive Plan Form of Awards Effective 2011 (filed as Exhibit 10(h)4 to the 2010 Form 10-K, File No. 1-3548).
+*10(f)4	—	ALLETE Executive Annual Incentive Plan Form of Awards Effective 2012 (filed as Exhibit 10(h)4 to the 2011 Form 10-K, File No. 1-3548).
+10(f)5	—	ALLETE Executive Annual Incentive Plan Form of Awards Effective 2013.
+*10(g)1	—	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), as amended and restated, effective January 1, 2009 (filed as Exhibit 10(i)4 to the 2008 Form 10-K, File No. 1-3548).
+*10(g)2	—	Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), effective January 1, 2011 (filed as Exhibit 10(i)2 to the 2010 Form 10-K, File No. 1-3548).
+*10(g)3	—	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2011 (filed as Exhibit 10(i)3 to the 2010 Form 10-K, File No. 1-3548).

ALLETE 2012 Form 10-K

58

Exhibit Number
+*10(h)1	—	Minnesota Power and Affiliated Companies Executive Investment Plan I, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(c) to the 1988 Form 10-K, File No. 1-3548).
+*10(h)2	—	Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(v)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(h)3	—	July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(b) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(h)4	—	August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(b) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(i)1	—	Minnesota Power and Affiliated Companies Executive Investment Plan II, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(d) to the 1988 Form 10-K, File No. 1-3548).
+*10(i)2	—	Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(w)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(i)3	—	July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(c) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(i)4	—	August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(c) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+10(j)	—	ALLETE Deferred Compensation Trust Agreement, as amended and restated, effective December 15, 2012.
+*10(k)1	—	ALLETE Executive Long-Term Incentive Compensation Plan as amended and restated effective January 1, 2006 (filed as Exhibit 10 to the May 16, 2005, Form 8-K, File No. 1-3548).
+*10(k)2	—	Amendment to the ALLETE Executive Long-Term Incentive Compensation Plan, effective January 1, 2011 (filed as Exhibit 10(m)2 to the 2010 Form 10-K, File No. 1-3548).
+*10(k)3	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Nonqualified Stock Option Grant Effective 2007 (filed as Exhibit 10(m)6 to the 2006 Form 10-K, File No. 1-3548).
+*10(k)4	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2007 (filed as Exhibit 10(m)7 to the 2006 Form 10-K, File No. 1-3548).
+*10(k)5	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2008 (filed as Exhibit 10(m)10 to the 2007 Form 10-K, File No. 1-3548).
+*10(k)6	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2009 (filed as Exhibit 10(m)11 to the 2008 Form 10-K, File No. 1-3548).
+*10(k)7	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2009 (filed as Exhibit 10(m)12 to the 2008 Form 10-K, File No. 1-3548).
+*10(k)8	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2010 (filed as Exhibit 10(m)8 to the 2009 Form 10-K, File No. 1-3548).
+*10(k)9	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2010 (filed as Exhibit 10(m)9 to the 2009 Form 10-K, File No. 1-3548).
+*10(k)10	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2011 (filed as Exhibit 10(m)11 to the 2010 Form 10-K, File No. 1-3548).
+*10(k)11	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2011 (filed as Exhibit 10(m)12 to the 2010 Form 10-K, File No. 1-3548).
+*10(k)12	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2012 (filed as Exhibit 10(m)12 to the 2011 Form 10-K, File No. 1-3548).
+*10(k)13	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2012 (filed as Exhibit 10(m)13 to the 2011 Form 10-K, File No. 1-3548).
+10(k)14	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2013.
+10(k)15	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2013.
+*10(l)1	—	Minnesota Power (now ALLETE) Director Stock Plan, effective May 9, 1995 (filed as Exhibit 10 to the March 31, 1995, Form 10-Q, File No. 1-3548).
+*10(l)2	—	Amendments through December 2003 to the Minnesota Power (now ALLETE) Director Stock Plan (filed as Exhibit 10(z)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(l)3	—	July 2004 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(e) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(l)4	—	January 2007 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(n)4 to the 2006 Form 10-K, File No. 1-3548).
+*10(l)5	—	May 2009 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(b) to the June 30, 2009, Form 10-Q, File No. 1-3548).
+*10(l)6	—	May 2010 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(a) to the June 30, 2010, Form 10-Q, File No. 1-3548).

ALLETE 2012 Form 10-K

59

Exhibit Number
+*10(l)7	—	October 2010 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10 to the September 30, 2010, Form 10-Q, File No. 1-3548).
+*10(m)1	—	ALLETE Non-Management Director Compensation Summary Effective May 1, 2010 (filed as Exhibit 10(b) to the March 31, 2010, Form 10-Q, File No. 1-3548).
+*10(m)2	—	ALLETE Non-Management Director Compensation Summary effective January 19, 2011 (filed as Exhibit 10(n)9 to the 2010 Form 10-K, File No. 1-3548).
+*10(m)3	—	ALLETE Non-Management Director Compensation Summary effective January 19, 2012 (filed as Exhibit 10(n)10 to the 2011 Form 10-K, File No. 1-3548).
+*10(n)1	—	Minnesota Power (now ALLETE) Director Compensation Deferral Plan Amended and Restated, effective January 1, 1990 (filed as Exhibit 10(ac) to the 2002 Form 10-K, File No. 1-3548).
+*10(n)2	—	October 2003 Amendment to the Minnesota Power (now ALLETE) Director Compensation Deferral Plan (filed as Exhibit 10(aa)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(n)3	—	January 2005 Amendment to the ALLETE Director Compensation Deferral Plan (filed as Exhibit 10(c) to the March 31, 2005, Form 10-Q, File No. 1-3548).
+*10(n)4	—	October 2006 Amendment to the ALLETE Director Compensation Deferral Plan (filed as Exhibit 10(d) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+10(n)5	—	July 2012 Amendment to the ALLETE Director Compensation Deferral Plan.
+*10(o)1	—	ALLETE Non-Employee Director Compensation Deferral Plan II, effective May 1, 2009 (filed as Exhibit 10(a) to the June 30, 2009, Form 10-Q, File No. 1-3548).
+10(o)2	—	ALLETE Non-Employee Director Compensation Deferral Plan II, as amended and restated, effective July 24, 2012.
+*10(p)1	—	ALLETE Director Compensation Trust Agreement, effective October 11, 2004 (filed as Exhibit 10(a) to the September 30, 2004, Form 10-Q, File No. 1-3548).
+10(p)2	—	ALLETE Director Compensation Trust Agreement, as amended and restated, effective December 15, 2012.
+*10(q)	—	ALLETE and Affiliated Companies Change in Control Severance Plan, as amended and restated, effective January 19, 2011 (filed as Exhibit 10(q) to the 2010 Form 10-K, File No. 1-3548).
12	—	Computation of Ratios of Earnings to Fixed Charges.
21	—	Subsidiaries of the Registrant.
23	—	Consent of Independent Registered Public Accounting Firm.
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 Annual Report by the Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95	—	Mine Safety.
99	—	ALLETE News Release dated February 15, 2013, announcing earnings for the year ended December 31, 2012. (This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.)
101.INS	—	XBRL Instance
101.SCH	—	XBRL Schema
101.CAL	—	XBRL Calculation
101.DEF	—	XBRL Definition
101.LAB	—	XBRL Label
101.PRE	—	XBRL Presentation

ALLETE 2012 Form 10-K

60

ALLETE or its subsidiaries are obligors under various long-term debt instruments, including but not limited to, (1) $38,995,000 original principal amount, of City of Cohasset, Minnesota, Variable Rate Demand Revenue Refunding Bonds (ALLETE, formerly Minnesota Power & Light Company, Project) Series 1997A, Series 1997B and Series 1997C ($27,455,000 remaining principal balance) that, pursuant to Regulation S-K, Item 601(b)(4)(iii), (2) $6,370,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Refunding Bonds Series 2007A and $6,130,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Bonds Series 2007B; and (3) other long-term debt instruments that, pursuant to Regulation S-K, Item 601(b)(4)(iii), are not filed as exhibits because the total amount of debt authorized under each of these omitted instruments does not exceed 10 percent of our total consolidated assets. We will furnish copies of these instruments to the SEC upon its request.

*	Incorporated herein by reference as indicated.
+	Management contract or compensatory plan or arrangement pursuant to Item 15(b).

ALLETE 2012 Form 10-K

61

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

			ALLETE, Inc.
Dated:	February 15, 2013	By	/s/ Alan R. Hodnik
			Alan R. Hodnik
			Chairman, President, Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Alan R. Hodnik	Chairman, President, Chief Executive Officer and Director	February 15, 2013
Alan R. Hodnik	(Principal Executive Officer)
/s/ Mark A. Schober	Senior Vice President and Chief Financial Officer	February 15, 2013
Mark A. Schober	(Principal Financial Officer)
/s/ Steven Q. DeVinck	Controller and Vice President – Business Support	February 15, 2013
Steven Q. DeVinck	(Principal Accounting Officer)

ALLETE 2012 Form 10-K

62

Signatures (Continued)

Signature	Title	Date
/s/ Kathleen A. Brekken	Director	February 15, 2013
Kathleen A. Brekken
/s/ Kathryn W. Dindo	Director	February 15, 2013
Kathryn W. Dindo
/s/ Heidi J. Eddins	Director	February 15, 2013
Heidi J. Eddins
/s/ Sidney W. Emery, Jr.	Director	February 15, 2013
Sidney W. Emery, Jr.
/s/ George G. Goldfarb	Director	February 15, 2013
George G. Goldfarb
/s/ James S. Haines, Jr.	Director	February 15, 2013
James S. Haines, Jr.
/s/ James J. Hoolihan	Director	February 15, 2013
James J. Hoolihan
/s/ Madeleine W. Ludlow	Director	February 15, 2013
Madeleine W. Ludlow
/s/ Douglas C. Neve	Director	February 15, 2013
Douglas C. Neve
/s/ Leonard C. Rodman	Director	February 15, 2013
Leonard C. Rodman
/s/ Bruce W. Stender	Director	February 15, 2013
Bruce W. Stender

ALLETE 2012 Form 10-K

63

Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholders of ALLETE, Inc:

In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of ALLETE, Inc. and its subsidiaries (the Company) at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the indexappearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Minneapolis, Minnesota

February 15, 2013

ALLETE 2012 Form 10-K

64

CONSOLIDATED FINANCIAL STATEMENTS

ALLETE Consolidated Balance Sheet

As of December 31	2012			2011
Millions
Assets
Current Assets
Cash and Cash Equivalents		$80.8			$101.1
Accounts Receivable (Less Allowance of $1.0 and $0.9)	89.0			79.7
Inventories	69.8			69.1
Prepayments and Other	33.6			27.1
Total Current Assets	273.2			277.0
Property, Plant and Equipment – Net	2,347.6			1,982.7
Regulatory Assets	340.3			345.9
Investment in ATC	107.3			98.9
Other Investments	143.5			132.3
Other Non-Current Assets	41.5			39.2
Total Assets		$3,253.4			$2,876.0
Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable		$90.5			$71.8
Accrued Taxes	30.2			26.4
Accrued Interest	15.6			12.8
Long-Term Debt Due Within One Year	84.5			5.4
Notes Payable	—			1.1
Other	62.6			45.6
Total Current Liabilities	283.4			163.1
Long-Term Debt	933.6			857.9
Deferred Income Taxes	423.8			373.6
Regulatory Liabilities	60.1			43.5
Defined Benefit Pension and Other Postretirement Benefit Plans	228.2			253.5
Other Non-Current Liabilities	123.3			105.1
Total Liabilities	2,052.4			1,796.7
Commitments and Contingencies (Note 11)
Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 39.4 and 37.5
Shares Outstanding	784.7			705.6
Unearned ESOP Shares	(21.3		)	(29.0		)
Accumulated Other Comprehensive Loss	(22.0		)	(28.9		)
Retained Earnings	459.6			431.6
Total Equity	1,201.0			1,079.3
Total Liabilities and Equity		$3,253.4			$2,876.0

The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K

65

ALLETE Consolidated Statement of Income

Year Ended December 31	2012			2011			2010
Millions Except Per Share Amounts
Operating Revenue		$961.2			$928.2			$907.0
Operating Expenses
Fuel and Purchased Power	308.7			306.6			325.1
Operating and Maintenance	397.1			381.2			365.6
Depreciation	100.2			90.4			80.5
Total Operating Expenses	806.0			778.2			771.2
Operating Income	155.2			150.0			135.8
Other Income (Expense)
Interest Expense	(45.5		)	(43.6		)	(39.2		)
Equity Earnings in ATC	19.4			18.4			17.9
Other	6.0			4.4			4.6
Total Other Expense	(20.1		)	(20.8		)	(16.7		)
Income Before Non-Controlling Interest and Income Taxes	135.1			129.2			119.1
Income Tax Expense	38.0			35.6			44.3
Net Income	97.1			93.6			74.8
Less: Non-Controlling Interest in Subsidiaries	—			(0.2		)	(0.5		)
Net Income Attributable to ALLETE		$97.1			$93.8			$75.3
Average Shares of Common Stock
Basic	37.6			35.3			34.2
Diluted	37.6			35.4			34.3
Basic Earnings Per Share of Common Stock		$2.59			$2.66			$2.20
Diluted Earnings Per Share of Common Stock		$2.58			$2.65			$2.19
Dividends Per Share of Common Stock		$1.84			$1.78			$1.76

The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K

66

ALLETE Consolidated Statement of Comprehensive Income

Comprehensive Income (Loss)	2012			2011			2010
Millions
Net Income		$97.1			$93.6			$74.8
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Securities
Net of Income Taxes of $0.8, $(0.1) and $0.6	1.2			(0.3		)	0.8
Unrealized Loss on Derivatives
Net of Income Taxes of $(0.1), $(0.2) and $—	(0.2		)	(0.3		)	—
Defined Benefit Pension and Other Postretirement Benefit Plans
Net of Income Taxes of $3.9, $(3.6), and $—	5.9			(5.1		)	—
Total Other Comprehensive Income (Loss)	6.9			(5.7		)	0.8
Total Comprehensive Income		$104.0			$87.9			$75.6
Less: Non-Controlling Interest in Subsidiaries	—			(0.2		)	(0.5		)
Comprehensive Income Attributable to ALLETE		$104.0			$88.1			$76.1

The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K

67

ALLETE Consolidated Statement of Cash Flows

Year Ended December 31	2012			2011			2010
Millions
Operating Activities
Net Income		$97.1			$93.6			$74.8
Allowance for Funds Used During Construction – Equity	(5.1		)	(2.5		)	(4.2		)
Income from Equity Investments, Net of Dividends	(3.7		)	(3.2		)	(3.1		)
Gain on Real Estate Foreclosure	—			(0.5		)	(0.7		)
Loss (Gain) on Sale of Assets	0.2			(0.9		)	—
Loss on Impairment of Assets	—			1.7			—
Depreciation Expense	100.2			90.4			80.5
Amortization of Debt Issuance Costs	1.0			0.9			0.9
Deferred Income Tax Expense	37.5			35.8			66.0
Share-Based Compensation Expense	2.1			1.6			2.2
ESOP Compensation Expense	7.7			7.4			7.1
Defined Benefit Pension and Other Postretirement Benefit Expense	27.5			23.6			18.0
Bad Debt Expense	1.0			1.2			1.1
Changes in Operating Assets and Liabilities
Accounts Receivable	(10.1		)	18.6			17.9
Inventories	(0.7		)	(9.1		)	(3.0		)
Prepayments and Other	(6.5		)	1.5			(4.3		)
Accounts Payable	(1.5		)	(9.5		)	5.8
Other Current Liabilities	21.8			15.4			5.2
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans	(8.8		)	(24.7		)	(39.3		)
Changes in Regulatory and Other Non-Current Assets	(20.9		)	(7.5		)	4.2
Changes in Regulatory and Other Non-Current Liabilities	0.8			7.9			(0.4		)
Cash from Operating Activities	239.6			241.7			228.7
Investing Activities
Proceeds from Sale of Available-for-sale Securities	1.5			7.8			0.6
Payments for Purchase of Available-for-sale Securities	(1.8		)	(2.3		)	(2.3		)
Investment in ATC	(4.7		)	(2.0		)	(1.6		)
Changes to Other Investments	(9.6		)	(7.4		)	1.3
Additions to Property, Plant and Equipment	(405.8		)	(239.2		)	(248.9		)
Proceeds from Sale of Assets	0.3			2.2			—
Cash for Investing Activities	(420.1		)	(240.9		)	(250.9		)
Financing Activities
Proceeds from Issuance of Common Stock	77.0			39.1			20.5
Proceeds from Issuance of Long-Term Debt	180.6			81.4			155.0
Changes in Notes Payable	(1.1		)	0.1			(0.9		)
Reductions of Long-Term Debt	(25.9		)	(3.1		)	(71.0		)
Debt Issuance Costs	(1.3		)	—			(1.4		)
Dividends on Common Stock	(69.1		)	(62.1		)	(60.8		)
Cash from Financing Activities	160.2			55.4			41.4
Change in Cash and Cash Equivalents	(20.3		)	56.2			19.2
Cash and Cash Equivalents at Beginning of Period	101.1			44.9			25.7
Cash and Cash Equivalents at End of Period		$80.8			$101.1			$44.9

`

The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K

68

ALLETE Consolidated Statement of Shareholders’ Equity

	Total Shareholders’ Equity			Retained Earnings			Accumulated Other Comprehensive Income (Loss)		Unearned ESOP Shares		Common Stock
Millions
Balance as of December 31, 2009		$929.5			$385.4		$(24.0)		$(45.3)			$613.4
Comprehensive Income
Net Income	74.8			74.8
Other Comprehensive Income – Net of Tax
Unrealized Gain on Securities – Net	0.8						0.8
Total Comprehensive Income	75.6
Non-Controlling Interest in Subsidiaries	0.5			0.5
Comprehensive Income Attributable to ALLETE	76.1
Common Stock Issued – Net	22.7										22.7
Dividends Declared	(60.8		)	(60.8		)
ESOP Shares Earned	8.5								8.5
Balance as of December 31, 2010	976.0			399.9			(23.2	)	(36.8	)	636.1
Comprehensive Income
Net Income	93.6			93.6
Other Comprehensive Income – Net of Tax
Unrealized Loss on Securities – Net	(0.3		)				(0.3	)
Unrealized Loss on Derivatives – Net	(0.3		)				(0.3	)
Defined Benefit Pension and Other Postretirement Plans – Net	(5.1		)				(5.1	)
Total Comprehensive Income	87.9
Non-Controlling Interest in Subsidiaries	0.2			0.2
Comprehensive Income Attributable to ALLETE	88.1
Common Stock Issued – Net	69.5										69.5
Dividends Declared	(62.1		)	(62.1		)
ESOP Shares Earned	7.8								7.8
Balance as of December 31, 2011	1,079.3			431.6			(28.9	)	(29.0	)	705.6
Comprehensive Income
Net Income	97.1			97.1
Other Comprehensive Income – Net of Tax
Unrealized Gain on Securities – Net	1.2						1.2
Unrealized Loss on Derivatives – Net	(0.2		)				(0.2	)
Defined Benefit Pension and Other Postretirement Plans – Net	5.9						5.9
Total Comprehensive Income Attributable to ALLETE	104.0
Common Stock Issued – Net	79.1										79.1
Dividends Declared	(69.1		)	(69.1		)
ESOP Shares Earned	7.7								7.7
Balance as of December 31, 2012		$1,201.0			$459.6		$(22.0)		$(21.3)			$784.7

The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Preparation. References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue, and expenses. Actual results could differ from those estimates.

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

Principles of Consolidation. Our consolidated financial statements include the accounts of ALLETE and all of our majority-owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.

Business Segments. Our Regulated Operations and Investments and Other segments were determined in accordance with the guidance on segment reporting. Segmentation is based on the manner in which we operate, assess, and allocate resources to the business. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,100 acres of land in Minnesota, and earnings on cash and investments.

BNI Coal, a wholly-owned subsidiary, mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2012, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under a long-term contract. (See Note 11. Commitments, Guarantees and Contingencies.) Coal sales are recognized when delivered at the cost of production plus a specified profit per ton of coal delivered.

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. ALLETE does not intend to acquire additional Florida real estate.

Full profit recognition is recorded on sales upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. In certain cases, where there are obligations to perform significant development activities after the date of sale, we recognize profit on a percentage-of-completion basis. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

In certain cases, we pay fees or construct improvements to mitigate offsite traffic impacts. In return, we receive traffic impact fee credits as a result of some of these expenditures. We recognize revenue from the sale of traffic impact fee credits when payment is received.

ALLETE 2012 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Land inventories are accounted for in accordance with the accounting standards for property, plant and equipment, and are included in Other Investments on our Consolidated Balance Sheet. Real estate costs include the cost of land acquired, subsequent development costs and costs of improvements, capitalized development period interest, real estate taxes and payroll costs of certain employees devoted directly to the development effort. These real estate costs incurred are capitalized to the cost of real estate parcels based upon the relative sales value of parcels within each development project in accordance with the accounting standards for real estate. The cost of real estate sold includes the actual costs incurred and the estimate of future completion costs allocated to the real estate sold based upon the relative sales value method. Whenever events or circumstances indicate that the carrying value of the real estate may not be recoverable, impairments are recorded and the related assets are adjusted to their estimated fair value. (See Note 7. Investments.)

ALLETE Clean Energy, a wholly-owned subsidiary of ALLETE, operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. 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.

Non-Controlling Interest in Subsidiaries. In August 2011, ALLETE purchased the remaining shares of the ALLETE Properties non-controlling interest at book value for $8.8 million by issuing 0.2 million shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or comprehensive income.

Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.

Supplemental Statement of Cash Flow Information

Consolidated Statement of Cash Flows
Year Ended December 31	2012		2011		2010
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$42.7		$43.2		$35.7
Cash Received During the Period for Income Taxes (a)	—		$(11.4)		$(54.2)
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$20.2		$5.9	$7.5
Capitalized Asset Retirement Costs		$17.1		$0.3		$2.8
AFUDC – Equity		$5.1		$2.5		$4.2
ALLETE Common Stock Contributed to the Pension Plan	—		$(20.0)		—

(a) Due to bonus depreciation provisions in 2009 and 2010 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and refunds were received from NOL carrybacks against prior years’ taxable income.

Accounts Receivable. Accounts receivable are reported on the balance sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses.

Accounts Receivable
As of December 31	2012		2011
Millions
Trade Accounts Receivable
Billed		$70.4		$63.7
Unbilled	17.4		15.6
Less: Allowance for Doubtful Accounts	1.0		0.9
Total Trade Accounts Receivable	86.8		78.4
Income Taxes Receivable	2.2		1.3
Total Accounts Receivable - Net		$89.0		$79.7

ALLETE 2012 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Concentration of Credit Risk. Financial instruments that subject us to concentrations of credit risk consist primarily of accounts receivable. Minnesota Power sells electricity to 9 Large Power Customers. Receivables from these customers totaled $11.6 million at December 31, 2012 ($9.3 million at December 31, 2011). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, our taconite-producing Large Power Customers, which are a part of our Regulated Operations segment, are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 12.3 percent of consolidated revenue in 2012 (12.8 percent in 2011; 12.5 percent in 2010). In the third quarter of 2011, one of Minnesota Power’s Large Power Customers, NewPage Corporation (NewPage), filed for Chapter 11 bankruptcy protection. In September 2012, NewPage submitted a motion to the bankruptcy court to approve amended and restated service agreements and payment of the pre-petition amount, which was approved on October 16, 2012. The agreement was subsequently approved by the MPUC in a December 10, 2012 order, which resulted in the pre-petition receivable of $3.2 million being paid as of December 31, 2012. Throughout the bankruptcy proceedings this customer’s operations continued without interruption and we continued to provide electric and steam service to this customer.

Long-Term Finance Receivables. Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals. (See Note 7. Investments.)

Available-for-Sale Securities. Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as the share price trends and the impact of overall market conditions. (See Note 7. Investments.)

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

Inventories
As of December 31	2012		2011
Millions
Fuel		$28.0		$28.6
Materials and Supplies	41.8		40.5
Total Inventories		$69.8		$69.1

Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the balance sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on non-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for Regulated Operations. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. The MPUC has approved cost recovery for several large capital projects recently, at which time the recognition of AFUDC ceases. (See Note 3. Property, Plant and Equipment.)

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed for the recovery of the remaining basis of retired plant assets. In January 2013 we announced the retirement of Taconite Harbor Unit 3 and conversion of Laskin Energy Center to natural gas in 2015, which is subject to MPUC approval. Accordingly, we do not expect any loss as a result of the retirement of Taconite Harbor Unit 3 or conversion of Laskin Energy Center.

Impairment of Long-Lived Assets. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.

ALLETE 2012 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels into bulk sales, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, and may vary among each land parcel or bulk sale.If the excess of undiscounted cash flows over the carrying value of a property is small, there is a greater risk of future impairment in the event of such changes and any resulting impairment charges could be material.

Weak market conditions for real estate in Florida have required us to review our land inventories for impairment. Our undiscounted cash flow analysis was estimated using management’s current intent for disposition of each property, which is an estimated selling period of five to ten years based on a December 2011 asset management and disposition plan (“Plan”). The Plan is reviewed annually for adjustment or modification and we have concluded that the estimates and assumptions remain appropriate in 2012. As such, we continue to utilize the Plan when evaluating our land inventory for impairment. Future selling prices have been estimated through management’s best estimate of future sales prices in collaboration and consultation with outside advisors, and based on the best use of the properties over the expected period of sale. The undiscounted cash flow analysis assumes two scenarios: retail land sales followed by project bulk sales over a five year period and retail land sales over a ten year period. Our analysis assumes the most likely case of retail land sales followed by project bulk sales over a five year period; however, under both scenarios, except as noted below, the undiscounted cash flows exceeded carrying values. If our major development projects are sold in one bulk sale or if the properties are sold differently than anticipated in the Plan, the actual results could be materially different from our undiscounted cash flow analysis.

The results of the impairment analysis are particularly dependent on the estimated future sales prices, method of disposition, and holding period for each property. The estimated holding period is based on management’s current intent for the use and disposition of each property, which could be subject to change in future periods if the intentions of the Company as set by management and approved by the Board of Directors were to change.

In the event that projected future undiscounted cash flows are not adequate to recover the carrying value of an asset, impairment is indicated and may require a write down to the asset’s fair value. Fair value is determined based on best available evidence including comparable sales, current appraised values, property tax assessed values, and discounted cash flow analysis. If fair value is less than cost, the carrying value of our investments is reduced and an impairment charge is recorded in the current period. In 2012, impairment analysis’ of estimated future undiscounted cash flows were conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. As a result, there was no impairment recorded for the year ended December 31, 2012. For the year ended December 31, 2011, a $1.7 million impairment charge was recorded.

Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage interest rate risk related to certain variable-rate borrowings.

Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 16. Employee Stock and Incentive Plans.)

Prepayments and Other Current Assets
As of December 31	2012		2011
Millions
Deferred Fuel Adjustment Clause		$22.5		$17.5
Other	11.1		9.6
Total Prepayments and Other Current Assets		$33.6		$27.1

ALLETE 2012 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Current Liabilities
As of December 31	2012		2011
Millions
Customer Deposits (a)		$28.8		$16.3
Other	33.8		29.3
Total Other Current Liabilities		$62.6		$45.6

(a) Customer deposits were higher in 2012 primarily due to customer security deposits for capital expenditures relating to a transmission project.

Other Non-Current Liabilities
As of December 31	2012		2011
Millions
Asset Retirement Obligation		$77.9		$57.0
Other	45.4		48.1
Total Other Non-Current Liabilities		$123.3		$105.1

Environmental Liabilities. We review environmental matters for disclosure on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the 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 operating expense unless recoverable in rates from customers. (See Note 11. Commitments, Guarantees and Contingencies.)

Revenue Recognition. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for service provided but not billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. BNI recognizes revenue when coal is delivered.

Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue and net purchases in Fuel and Purchased Power Expense on our Consolidated Statement of Income. The revenues and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.

Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using the straight-line method which approximates the effective interest method.

Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return and combined and separate state income tax returns. We account for income taxes using the liability method in accordance with the accounting standards for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with the accounting standards for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than 50 percent likely. (See Note 14. Income Tax Expense.)

ALLETE 2012 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Excise Taxes. We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.

New Accounting Standards.

There are no recently issued accounting standard updates applicable for our adoption in future periods.

NOTE 2. BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,100 acres of land in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.

	Consolidated			Regulated Operations			Investments and Other
Millions
2012
Operating Revenue		$961.2			$874.4			$86.8
Fuel and Purchased Power Expense	308.7			308.7			—
Operating and Maintenance Expense	397.1			310.0			87.1
Depreciation Expense	100.2			93.9			6.3
Operating Income (Loss)	155.2			161.8			(6.6		)
Interest Expense	(45.5		)	(39.8		)	(5.7		)
Equity Earnings in ATC	19.4			19.4			—
Other Income	6.0			5.1			0.9
Income (Loss) Before Non-Controlling Interest and Income Taxes	135.1			146.5			(11.4		)
Income Tax Expense (Benefit)	38.0			50.4			(12.4		)
Net Income	97.1			96.1			1.0
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE		$97.1			$96.1			$1.0
Total Assets		$3,253.4			$2,962.4			$291.0
Capital Additions		$432.2			$418.2			$14.0

ALLETE 2012 Form 10-K

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NOTE 2. BUSINESS SEGMENTS (Continued)

	Consolidated			Regulated Operations			Investments and Other
Millions
2011
Operating Revenue		$928.2			$851.9			$76.3
Fuel and Purchased Power Expense	306.6			306.6			—
Operating and Maintenance Expense	381.2			301.5			79.7
Depreciation Expense	90.4			85.4			5.0
Operating Income (Loss)	150.0			158.4			(8.4		)
Interest Expense	(43.6		)	(35.8		)	(7.8		)
Equity Earnings in ATC	18.4			18.4			—
Other Income	4.4			2.6			1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	129.2			143.6			(14.4		)
Income Tax Expense (Benefit)	35.6			43.2			(7.6		)
Net Income (Loss)	93.6			100.4			(6.8		)
Less: Non-Controlling Interest in Subsidiaries	(0.2		)	—			(0.2		)
Net Income (Loss) Attributable to ALLETE		$93.8			$100.4		$(6.6)
Total Assets		$2,876.0			$2,579.8			$296.2
Capital Additions		$246.8			$228.0			$18.8

	Consolidated			Regulated Operations			Investments and Other
Millions
2010
Operating Revenue		$907.0			$835.5			$71.5
Fuel and Purchased Power Expense	325.1			325.1			—
Operating and Maintenance Expense	365.6			292.3			73.3
Depreciation Expense	80.5			76.1			4.4
Operating Income (Loss)	135.8			142.0			(6.2		)
Interest Expense	(39.2		)	(32.3		)	(6.9		)
Equity Earnings in ATC	17.9			17.9			—
Other Income	4.6			3.8			0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	119.1			131.4			(12.3		)
Income Tax Expense (Benefit)	44.3			51.6			(7.3		)
Net Income (Loss)	74.8			79.8			(5.0		)
Less: Non-Controlling Interest in Subsidiaries	(0.5		)	—			(0.5		)
Net Income (Loss) Attributable to ALLETE		$75.3			$79.8		$(4.5)
Total Assets		$2,609.1			$2,375.4			$233.7
Capital Additions		$260.0			$256.4			$3.6

ALLETE 2012 Form 10-K

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NOTE 3. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
As of December 31	2012			2011
Millions
Regulated Utility		$3,232.9			$2,794.8
Construction Work in Progress	151.8			155.0
Accumulated Depreciation	(1,102.8		)	(1,024.6		)
Regulated Utility Plant - Net	2,281.9			1,925.2
Non-Rate Base Energy Operations	118.0			106.4
Construction Work in Progress	4.2			2.3
Accumulated Depreciation	(56.7		)	(51.4		)
Non-Rate Base Energy Operations Plant - Net	65.5			57.3
Other Plant - Net	0.2			0.2
Property, Plant and Equipment - Net		$2,347.6			$1,982.7

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.

Estimated Useful Lives of Property, Plant and Equipment
Regulated Utility –	Generation	3 to 35 years	Non-Rate Base Operations	3 to 61 years
	Transmission	42 to 61 years	Other Plant	5 to 25 years
	Distribution	14 to 65 years

Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction or development and/or normal operation of the asset. Asset retirement obligations (ARO) relate primarily to the decommissioning of our coal-fired and wind generating facilities and land reclamation at BNI Coal, and are included in other non-current liabilities on our Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.

Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, removal costs have not been recognized because they are considered immaterial to our consolidated financial statements.

Long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-ARO obligations. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with the guidance for AROs. (See Note 5. Regulatory Matters.)

Asset Retirement Obligation
Millions
Obligation as of December 31, 2010		$50.3
Accretion Expense	6.4
Additional Liabilities Incurred in 2011	0.3
Obligation as of December 31, 2011	57.0
Accretion Expense	3.8
Additional Liabilities Incurred in 2012	17.1
Obligation as of December 31, 2012		$77.9

ALLETE 2012 Form 10-K

77

NOTE 4. JOINTLY-OWNED FACILITIES

Following are our investments in jointly-owned facilities and the related ownership percentages as of December 31, 2012:

Regulated Utility Plant	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
Boswell Unit 4		$413.1		$188.1		$25.0	80
CapX2020	22.8		0.4		25.4		9.3 - 14.7
Total		$435.9		$188.5		$50.4

We own 80 percent of the 585 MW Boswell Unit 4. While we operate the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which we and WPPI Energy, the owner of the remaining 20 percent of Boswell Unit 4, have equal representation and voting rights. Each of us must provide our own financing and is obligated to pay our ownership share of operating costs. Our share of direct operating expenses of Boswell Unit 4 is included in operating expense on our Consolidated Statement of Income. We are a participant in the CapX2020 initiative to ensure reliable electric transmission and distribution in the region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and investor-owned utilities. We are currently participating in three CapX2020 projects with varying ownership percentages.

NOTE 5. REGULATORY MATTERS

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

2010 Minnesota Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). On February 14, 2012, the Court granted the petition for review and oral arguments were held before the Court on October 9, 2012. A decision is expected in early 2013; however, we cannot predict the outcome at this time.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. Minnesota Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July 1, 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 City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on December 31, 2011, this customer submitted a cancellation notice with termination effective on December 31, 2013. The 17 MW of average monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in 2014.

2012 Wisconsin Rate Case.During 2012, SWL&P’s retail rates were based on a 2010 PSCW retail rate order, which was effective January 1, 2011. SWL&P’s 2013 retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, and allows for a 10.9 percent return on common equity. The new rates reflect an average overall increase of 2.4 percent for retail customers (a 13.8 percent increase in water rates, a 1.2 percent increase in electric rates, and a 2.0 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $1.7 million in additional revenue.

ALLETE 2012 Form 10-K

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NOTE 5. REGULATORY MATTERS (Continued)

Rapids Energy Center. On December 19, 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill (Blandin). Minnesota Power and Blandin entered into a new electric service agreement in September 2012 which is also subject to MPUC approval. We expect a decision from the MPUC on these filings in mid-2013.

ALLETE Clean Energy. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships between the parties, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. On July 23, 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction and the Federal MATS rule. On August 31, 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be between $350 million and $400 million. The MPCA has 180 days to comment on the mercury emissions reduction plan, which then is reviewed by the MPUC for a decision. We expect a decision by the MPUC on the plan in the third quarter of 2013. After approval by the MPUC we anticipate filing a petition to include investments and expenditures in customer billing rates.

The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, the PPACA was signed into law. One of the provisions changed the tax treatment for retiree prescription drug expenses by eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, beginning January 1, 2013. Based on this provision, we are subject to additional taxes in the future and were required to reverse previously recorded tax benefits which resulted in a non-recurring charge to net income of $4.0 million in 2010. In October 2010, we submitted a filing with the MPUC requesting deferral of the retail portion of the tax charge taken in 2010 resulting from the PPACA. In May 2011, the MPUC approved our request for deferral until the next rate case and as a result we recorded an income tax benefit of $2.9 million and a related regulatory asset of $5.0 million in the second quarter of 2011.

Pension. In December 2011, the Company filed a petition with the MPUC requesting a mechanism to recover the cost of capital associated with the prepaid pension asset (or liability) created by the required contributions under the pension plan in excess of (or less than) annual pension expense. The Company further requested a mechanism to defer pension expenses in excess of (or less than) those currently being recovered in base rates. On February 14, 2013, the MPUC denied the Company's petition for recovery of the pension asset and deferral of expenses outside of a general rate case. The MPUC decision does not impact the results of operations for the year ended December 31, 2012.

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 liabilitiesrepresent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.

ALLETE 2012 Form 10-K

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NOTE 5. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities
As of December 31	2012		2011
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.5		$17.5
Total Current Regulatory Assets	22.5		17.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans	260.7		292.8
Income Taxes	36.0		28.6
Asset Retirement Obligation	12.1		9.8
Cost Recovery Riders (b)	18.5		0.7
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	4.3		4.6
Other	3.7		4.4
Total Non-Current Regulatory Assets	340.3		345.9
Total Regulatory Assets		$362.8		$363.4
Non-Current Regulatory Liabilities
Income Taxes		$19.5		$21.9
Plant Removal Obligations	18.1		15.0
Wholesale and Retail Contra AFUDC	15.5		1.5
Other	7.0		5.1
Total Non-Current Regulatory Liabilities		$60.1		$43.5

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

(b) The increase in cost recovery rider regulatory assets in 2012 is primarily due to revenues related to our Bison Wind Energy Center.

NOTE 6. INVESTMENT IN ATC

Investment in ATC. Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATC rates are FERC-approved and are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, 2012, our equity investment in ATC was $107.3 million ($98.9 million at December 31, 2011). On January 30, 2013, we invested an additional $0.4 million in ATC. In total, we expect to invest approximately $2.0 million throughout 2013.

ALLETE’s Interest in ATC
Year Ended December 31	2012			2011
Millions
Equity Investment Beginning Balance		$98.9			$93.3
Cash Investments	4.7			2.0
Equity in ATC Earnings	19.4			18.4
Distributed ATC Earnings	(15.7		)	(14.8		)
Equity Investment Ending Balance		$107.3			$98.9

ALLETE 2012 Form 10-K

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NOTE 6. INVESTMENT IN ATC (Continued)

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2012		2011
Millions
Current Assets		$63.1		$58.7
Non-Current Assets	3,274.7		3,053.7
Total Assets		$3,337.8		$3,112.4
Current Liabilities		$251.5		$298.5
Long-Term Debt	1,550.0		1,400.0
Other Non-Current Liabilities	95.8		82.6
Members’ Equity	1,440.5		1,331.3
Total Liabilities and Members’ Equity		$3,337.8		$3,112.4

Income Statement Data
Year Ended December 31	2012		2011		2010
Millions
Revenue		$603.2		$567.2		$556.7
Operating Expense	281.0		261.6		251.1
Other Expense	84.8		81.7		85.9
Net Income		$237.4		$223.9		$219.7
ALLETE’s Equity in Net Income		$19.4		$18.4		$17.9

NOTE 7. INVESTMENTS

Investments. At December 31, 2012, our long-term investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits, and other assets consisting primarily of cash equivalents and land in Minnesota.

Investments
As of December 31	2012		2011
Millions
ALLETE Properties		$91.1		$91.3
Available-for-sale Securities	26.8		24.7
Other	25.6		16.3
Total Investments		$143.5		$132.3

ALLETE 2012 Form 10-K

81

NOTE 7. INVESTMENTS (Continued)

ALLETE Properties
As of December 31	2012			2011
Millions
Land Inventory Beginning Balance		$86.0			$86.0
Deeds to Collateralized Property	0.5			1.8
Land Impairment	—			(1.7		)
Cost of Sales	(0.2		)	(0.3		)
Capitalized Improvements and Other	0.2			0.2
Land Inventory Ending Balance	86.5			86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4			2.0
Other	3.2			3.3
Total Real Estate Assets		$91.1			$91.3

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. In 2012, impairment analysis’ of estimated future undiscounted cash flows was conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. Consequently, there was no impairment recorded for the year ended December 31, 2012. For the year ended December 31, 2011, a 1.7 million impairment charge was recorded.

Long-Term Finance Receivables. As of December 31, 2012, long-term finance receivables were $1.4 million net of allowance ($2.0 million net of allowance as of December 31, 2011). The decrease is primarily the result of the transfer of properties back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term finance receivables. 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 December 31, 2012, we had allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2011).

If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. Contract purchasers may incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they may have substantially more at risk than the deposit.

Available-for-Sale Investments.We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities. Our auction rate securities of $6.7 million were redeemed at carrying value on January 5, 2011.

Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	(Loss)	Fair Value
2012	$27.4	$0.5	$(1.1)	$26.8
2011	$27.3	$0.1	$(2.7)	$24.7
2010	$27.4	$0.2	$(2.4)	$25.2

	Net	Gross Realized		Net Unrealized Gain (Loss) in Other
Year Ended December 31	Proceeds	Gain	(Loss)	Comprehensive Income
2012	$1.5	—	—	$1.2
2011	$7.8	—	—	$(0.3)
2010	$0.6	—	—	$0.8

ALLETE 2012 Form 10-K

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NOTE 8. DERIVATIVES

During the third quarter of 2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 8 percent of the Company’s outstanding long-term debt as of December 31, 2012. (See Note 10. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting with respect to that derivative. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in value of the Swap designated as the hedging instrument will be deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the year ended December 31, 2012. The mark-to-market fluctuation on the cash flow hedge was recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. As of December 31, 2012, the fair value of the swap was a $0.7 million liability (a $0.4 million liability as of December 31, 2011) and is included in other non-current liabilities on the Consolidated Balance Sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.

NOTE 9. FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

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

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

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 December 31, 2012 and December 31, 2011. 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, which may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the tables below.

ALLETE 2012 Form 10-K

83

NOTE 9. FAIR VALUE (Continued)

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$18.0	—		—		$18.0
Available-for-sale Securities – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5
Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

There was no activity in Level 3 during the year ended December 31, 2012.

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$17.6	—		—		$17.6
Available-for-sale Securities – Corporate Debt Securities	—			$8.2	—	8.2
Cash Equivalents	11.4		—		—	11.4
Total Fair Value of Assets		$29.0		$8.2	—		$37.2
Liabilities:
Deferred Compensation	—			$12.8	—		$12.8
Derivatives – Interest Rate Swap	—			$0.4	—		$0.4
Total Fair Value of Liabilities	—			$13.2	—		$13.2
Total Net Fair Value of Assets (Liabilities)		$29.0	$(5.0)		—		$24.0

Recurring Fair Value Measures Activity in Level 3	Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2010		$6.7
Redeemed During the Period (a)	(6.7		)
Balance as of December 31, 2011		$—

(a) The ARS were redeemed at carrying value on January 5, 2011.

The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. For the years ended December 31, 2012 and 2011, there were no transfers in or out of Levels 1, 2 or 3.

ALLETE 2012 Form 10-K

84

NOTE 9. FAIR VALUE (Continued)

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

Financial Instruments	Carrying Amount		Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2012		$1,018.1		$1,143.7
December 31, 2011		$863.3		$966.4

NOTE 10. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. Total short-term debt outstanding as of December 31, 2012, was $84.5 million ($6.5 million at December 31, 2011) and consisted of long-term debt due within one year and notes payable. As of December 31, 2012, short-term debt increased from December 31, 2011, primarily due to $60.0 million of long-term debt maturing in April 2013.

As of December 31, 2012, we had bank lines of credit aggregating $406.4 million ($256.4 million at December 31, 2011), of which $150.0 million expires in January 2014, and $250.0 million expires in June 2015. These bank lines of credit are available to provide short-term bank loans and liquidity support for ALLETE’s commercial paper program and to issue up to $50.0 million in letters of credit. We had no outstanding draws on our lines of credit as of December 31, 2012 ($1.1 million at December 31, 2011).

On February 1, 2012, ALLETE entered into a $150.0 million credit agreement (Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and several other lenders that are parties thereto. The Agreement is unsecured and has a maturity date of January 31, 2014, which may be extended for one year, subject to bank approvals. Advances under the Agreement may be used for general corporate purposes, to provide liquidity support for ALLETE’s commercial paper program and to issue up to $10.0 million in letters of credit.

Long-Term Debt. Total long-term debt outstanding as of December 31, 2012, was $933.6 million ($857.9 million at December 31, 2011). The aggregate amount of long-term debt maturing during 2013 is $84.5 million ($94.8 million in 2014; $17.4 million in 2015; $21.7 million in 2016; $51.2 million in 2017; and $748.5 million thereafter). Substantially all of our electric plant is subject to the lien of the mortgage collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

On July 2, 2012, we issued $160.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in two series as follows:

Issue Date	Maturity Date	Principal Amount	Interest Rate
July 2, 2012	July 15, 2026	$75 Million	3.20%
July 2, 2012	July 15, 2042	$85 Million	4.08%

We have the option to prepay all or a portion of the 3.20 percent Bonds at our discretion at any time prior to January 15, 2026, subject to a make-whole provision, and at any time on or after January 15, 2026, at par, including, in each case, accrued and unpaid interest. We also have the option to prepay all or a portion of the 4.08 percent Bonds at our discretion at any time prior to January 15, 2042, subject to a make-whole provision, and at any time on or after January 15, 2042, at par, including, in each case, accrued and unpaid interest. The Bonds are subject to the additional terms and conditions of our utility mortgage. In July 2012, we used a portion of the proceeds from the sale of the Bonds to redeem $6.0 million of our 6.50 percent Industrial Development Revenue Bonds and to repay $14.0 million in outstanding borrowings on our $150.0 million line of credit. The remaining proceeds were used to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to certain institutional accredited investors.

ALLETE 2012 Form 10-K

85

NOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt
As of December 31	2012		2011
Millions
First Mortgage Bonds
4.86% Series Due 2013		$60.0		$60.0
6.94% Series Due 2014	18.0		18.0
7.70% Series Due 2016	20.0		20.0
8.17% Series Due 2019	42.0		42.0
5.28% Series Due 2020	35.0		35.0
4.85% Series Due 2021	15.0		15.0
4.95% Pollution Control Series F Due 2022	111.0		111.0
6.02% Series Due 2023	75.0		75.0
4.90% Series Due 2025	30.0		30.0
5.10% Series Due 2025	30.0		30.0
3.20% Series Due 2026	75.0		—
5.99% Series Due 2027	60.0		60.0
5.69% Series Due 2036	50.0		50.0
6.00% Series Due 2040	35.0		35.0
5.82% Series Due 2040	45.0		45.0
4.08% Series Due 2042	85.0		—
SWL&P First Mortgage Bonds 7.25% Series Due 2013	10.0		10.0
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013 – 2020	27.5		28.2
Industrial Development Revenue Bonds 6.5% Due 2025	—		6.0
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025	27.8		27.8
Unsecured Term Loan Variable Rate Due 2014	75.0		75.0
Other Long-Term Debt, 1.0% – 8.0% Due 2013 – 2037	41.8		40.3
Total Long-Term Debt	1,018.1		863.3
Less: Due Within One Year	84.5		5.4
Net Long-Term Debt		$933.6		$857.9

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 covenant requires ALLETE to maintain a ratio of its 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 December 31, 2012, our ratio was approximately 0.46 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of December 31, 2012, ALLETE was in compliance with its financial covenants.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

ALLETE 2012 Form 10-K

86

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

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 December 31, 2012, Square Butte had total debt outstanding of $416.9 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the next five years, 2013 through 2017, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during 2012 was $67.1 million ($61.2 million in 2011; $55.2 million in 2010). 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 $11.1 million in 2012 ($11.1 million in 2011; $10.2 million in 2010). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

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

No power will be sold under the 2009 agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late 2013. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, which in turn will enable Minnesota Power the ability to transmit additional wind generation on the existing DC transmission line.

Minnkota Power PPA. On December 12, 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity over the term June 1, 2016 through May 31, 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

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

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in April 2015. Under this agreement Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

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

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Power Purchase Agreements (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and is subject to construction of additional transmission capacity between Manitoba and 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.

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

North Dakota Wind Development. 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.

Our Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity. Bison 1 is an 82 MW wind facility in North Dakota, which was completed in two phases. The first phase was completed in 2010, and the second phase was completed in January 2012. The project also included construction of a 22-mile, 230 kV transmission line. Bison 1 had a total project cost of $174.9 million through December 31, 2012, including additional costs related to land restoration and completion of remaining associated upgrades to the 250 kV DC transmission line.

The 105 MW Bison 2 and 105 MW Bison 3 wind facilities in North Dakota were completed in December 2012. Total project costs for Bison 2 and Bison 3 were $148.6 million and $149.8 million, respectively, through December 31, 2012. In September 2011 and November 2011, the MPUC approved Minnesota Power’s petitions seeking cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively.

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated with Bison 1. We anticipate filing a cost recovery petition with the MPUC in the first half of 2013 to update customer billing rates for Bison 1 and to include investments and expenditures associated with Bison 2 and Bison 3.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through 2014. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements is $51.4 million for 2013 and $0.8 million for 2014. Our minimum annual payment obligation will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is $11.5 million in 2013, $11.7 million in 2014, $11.4 million in 2015, $9.3 million in 2016, $8.5 million in 2017 and $35.0 million thereafter. Total rent and lease expense was $11.5 million in 2012 ($9.4 million in 2011; $9.4 million in 2010).

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

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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

Transmission Investments. We have an approved cost recovery rider in place for certain transmission investments and expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In June 2011, we filed an updated billing factor that includes additional transmission expenditures, which we expect to be approved in the first quarter of 2013.

CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region’s transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

Minnesota Power is participating in three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. The 28-mile 345 kV line between Monticello and St. Cloud was placed into service in December 2011 and the 70-mile 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process was completed on August 12, 2012. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.

Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between $100 million and $110 million in the CapX2020 initiative through 2015. A total of $48.2 million was spent through December 31, 2012, of which $37.3 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($27.8 million as of December 31, 2011 of which $20.4 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $7.4 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Environmental Matters

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

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

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information becomes 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 heavily regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses and low NO_X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.

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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits. Resolution of the NOVs could result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to estimate the expenditures, or range of expenditures that may be required upon resolution. Any costs of installing additional pollution control equipment would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, which replaced the EPA’s 2005 CAIR. However, on August 21, 2012, a three judge panel of the District of Columbia Circuit Court of Appeals vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. The EPA and other parties to the case have until April 24, 2013, to request that the Supreme Court review the matter. The CSAPR would have required states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR did not directly require the installation of controls. Instead, the rule would have required facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would have been allocated to facilities from each state’s annual budget and would also have been able to be bought and sold.

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

Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Based on our expected generation, these emission reductions would have satisfied Minnesota Power’s SO₂ and NO_X emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2012. Minnesota Power will continue to track the EPA activity related to promulgation of a CSAPR replacement rule. We are unable to predict any additional compliance costs we might incur if the CSAPR is reinstated or if a CSAPR replacement rule is promulgated.

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

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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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 on February 16, 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 they have approved Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas addressing the MATS requirements.

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. On January 9, 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released on December 21, 2012. Major sources have three years to achieve compliance with the final rule. Minnesota Power is in the process of assessing the impact of this rule on our affected units including the Hibbard Renewable Energy Center and Rapids Energy Center. Costs for complying with the final rule cannot be estimated at this time.

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

Proposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with a 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 2013.

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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM_2.5) standard; the annual PM_2.5 standard and the 24-hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM_2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM_2.5 standards on June 14, 2012.

On December 14, 2012, the EPA confirmed in a final rule that the current annual PM_2.5 standard, which has been in place since 1997, will be lowered, while retaining the current 24-hour PM_2.5 standard. To implement the new lower annual PM_2.5 standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects and permits must comply with the new lower standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling. To bridge the transition to the lower standard, the EPA is finalizing a grandfathering provision to ensure that projects and pending permits already underway are not unduly delayed.

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

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

In late 2011, the MPCA initiated modeling activities that included approximately 65 sources within Minnesota that emit greater than 100 tons of SO₂ per year. However, on April 12, 2012, the MPCA notified Minnesota Power that such modeling had been suspended as a result of the EPA’s announcement that the June 2013 SIP submittals would no longer require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The MPCA is awaiting updated EPA guidance and will communicate with affected sources once the MPCA has more information on how the state will meet the EPA’s SIP requirements. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.

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

• Expand our renewable energy supply;

• Provide energy conservation initiatives for our customers and engage in other demand side efforts;

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

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

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, at existing facilities that undergo major modifications and at 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.

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Environmental Matters (Continued)

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 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.

On March 28, 2012, the EPA announced its proposed rule to apply CO₂ emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The proposed NSPS apply only to new or re-powered units and were open for public comment through June 25, 2012. It is anticipated that the EPA will issue NSPS for existing fossil fuel-fired generating units in the future. We cannot predict what CO₂ control measures, if any, may be required by such NSPS.

Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. On June 26, 2012, the United States District Court for the District of Columbia upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. Comments to the permitting guidance were submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

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

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA published in the Federal Register proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes and have a design intake flow of greater than 2 million gallons per day to limit the number of aquatic organisms that are killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011 and the EPA is obligated to finalize the rule by June 27, 2013. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Steam Electric Power Generating Effluent Guidelines. In late 2009, the EPA announced that it will be reviewing and reissuing the federal effluent guidelines for steam electric stations. These are the underlying federal water discharge rules that apply to all steam electric stations. It is expected that the EPA will publish the proposed new rule in April 2013 and a final rule in 2014. As part of the review phase for this new rule, the EPA issued an Information Collection Request (ICR) in June 2010, to most thermal electric generating stations in the country, including all five of Minnesota Power’s generating stations. The ICR was completed and submitted to the EPA in September 2010, for Boswell, Laskin, Taconite Harbor, Hibbard and Rapids Energy Center. The ICR was designed to gather extensive information on the nature and extent of all water discharge and related wastewater handling at power plants. The information gathered through the ICR will form a basis for development of the eventual new rule, which could include more restrictive requirements on wastewater discharge, flue gas desulfurization, and wet ash handling operations. We are unable to predict the costs we might incur to comply with potential future water discharge regulations at this time.

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

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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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. Comments on the proposed rule were due in November 2010. It is estimated that the final rule will be published in 2013. We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Other Matters

BNI Coal. As of December 31, 2012, BNI Coal had surety bonds outstanding of $29.8 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit with CoBANK ACB for an additional $2.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $32.4 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 December 31, 2012, 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, of which $0.6 million is the contractual obligation of land purchasers. 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 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 December 31, 2012, we owned 73 percent of the assessable land in the Town Center District (73 percent at December 31, 2011) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2011). At these ownership levels, our annual assessments are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20.0 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of December 31, 2012, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance coverage for any potential loss.

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

ALLETE 2012 Form 10-K

94

NOTE 12. COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2009	35,221		$613.4
Employee Stock Purchase Program	19	0.6
Invest Direct	346	11.7
Options and Stock Awards	51	4.4
Equity Issuance Program	180	6.0
Balance as of December 31, 2010	35,817		$636.1
Employee Stock Purchase Program	20	0.8
Invest Direct	437	17.2
Options and Stock Awards	109	6.7
Equity Issuance Program	400	16.0
Purchase of Non-Controlling Interest	222	8.8
Contributions to Pension	508	20.0
Balance as of December 31, 2011	37,513		$705.6
Employee Stock Purchase Program	20	0.8
Invest Direct	474	19.2
Options and Stock Awards	95	6.0
Equity Issuance Program	1,275	53.1
Balance as of December 31, 2012	39,377		$784.7

Equity Issuance Program. We entered into a distribution agreement with KCCI, Inc., in February 2008, as amended most recently on August 3, 2012, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 4.5 million remain available for issuance. For the year ended December 31, 2012, 1.3 million shares of common stock were issued under this agreement resulting in net proceeds of $53.1 million. During 2011, 0.4 million shares of common stock were issued for net proceeds of $16.0 million. The shares issued in 2012 and 2011 were, and the remaining shares may be, offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-170289.

Earnings Per Share. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock, and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. In 2012, in accordance with accounting standards for earnings per share, 0.2 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive (0.3 million shares were excluded in 2011 and 0.5 million in 2010).

Purchase of Non-Controlling Interest. In 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased at book value for $8.8 million by issuing 0.2 million unregistered shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss is recognized in net income or comprehensive income.

Contributions to Pension. In 2011, ALLETE contributed approximately 0.5 million shares of ALLETE common stock to its pension plan. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933 and had an aggregate value of $20.0 million when contributed.

ALLETE 2012 Form 10-K

95

NOTE 12. COMMON STOCK AND EARNINGS PER SHARE (Continued)

Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2012
Net Income Attributable to ALLETE		$97.1			$97.1
Average Common Shares	37.6		—	37.6
Earnings Per Share		$2.59			$2.58
2011
Net Income Attributable to ALLETE		$93.8			$93.8
Average Common Shares	35.3		0.1	35.4
Earnings Per Share		$2.66			$2.65
2010
Net Income Attributable to ALLETE		$75.3			$75.3
Average Common Shares	34.2		0.1	34.3
Earnings Per Share		$2.20			$2.19

NOTE 13. OTHER INCOME (EXPENSE)

Year Ended December 31	2012		2011		2010
Millions
AFUDC – Equity		$5.1		$2.5		$4.2
Investment and Other Income	0.9		1.9		0.4
Total Other Income		$6.0		$4.4		$4.6

ALLETE 2012 Form 10-K

96

NOTE 14. INCOME TAX EXPENSE

Income Tax Expense
Year Ended December 31	2012			2011			2010
Millions
Current Tax Expense (Benefit)
Federal (a)	—			$1.4			$(23.0)
State (a)	$0.5			(1.6		)	1.3
Total Current Tax Expense (Benefit)	0.5			(0.2		)	(21.7		)
Deferred Tax Expense
Federal (b)	38.1			27.3			61.4
State (b)	(1.7		)	9.5			5.3
Change in Valuation Allowance (c)	2.0			(0.1		)	0.2
Investment Tax Credit Amortization	(0.9		)	(0.9		)	(0.9		)
Total Deferred Tax Expense	37.5			35.8			66.0
Total Income Tax Expense		$38.0			$35.6			$44.3

(a) For the years ended December 31, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, a federal current tax benefit was recorded as a result of tax planning initiatives and the bonus depreciation provision in the Small Business Jobs Act of 2010. The 2010 federal NOL was partially utilized by carrying it back against prior years’ income with the remainder carried forward to offset future years’ income.

(b) For the year ended December 31, 2012, the state deferred tax benefit of $1.7 million is due to state renewable tax credits earned which will be carried forward to offset future state income tax expense. The year ended December 31, 2011, included an income tax benefit for the reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and a benefit of $2.9 million related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. Included in the year ended December 31, 2010, was a charge of $4.0 million as a result of the PPACA. (See Note 5. Regulatory Matters.)

(c) For the year ending December 31, 2012, the change in the valuation allowance is due to state renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2012			2011			2010
Millions
Income Before Non-Controlling Interest and Income Taxes		$135.1			$129.2			$119.1
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$47.3			$45.2			$41.7
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	1.2			6.0			4.5
Impact of the PPACA	—			—			4.0
Deferred Accounting for Retail Portion of the PPACA	—			(2.9		)	—
2010 Rate Case Stipulation Agreement - Deferred Tax Reversal	—			(6.2		)	—
Regulatory Differences for Utility Plant	(2.2		)	(1.2		)	(2.0		)
Production Tax Credits	(7.6		)	(4.3		)	(1.6		)
Other	(0.7		)	(1.0		)	(2.3		)
Total Income Tax Expense		$38.0			$35.6			$44.3

ALLETE 2012 Form 10-K

97

NOTE 14. INCOME TAX EXPENSE (Continued)

The effective tax rate on income was 28.1 percent for 2012 (27.6 percent for 2011; 37.2 percent for 2010). The 2012 effective rate was primarily impacted by renewable tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above). The 2011 effective tax rate was primarily impacted by the deduction for AFUDC-Equity, the reversal of a deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, renewable tax credits, and the MPUC’s approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. The 2010 effective tax rate was primarily impacted by the PPACA eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, the deduction for AFUDC-Equity, and renewable tax credits.

Deferred Tax Assets and Liabilities
As of December 31	2012			2011
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$120.2			$132.7
Property Related	59.8			56.4
NOL Carryforwards	90.8			61.7
Tax Credit Carryforwards	28.3			12.2
Other	24.6			20.4
Gross Deferred Tax Assets	323.7			283.4
Deferred Tax Asset Valuation Allowance	(2.4		)	(0.4		)
Total Deferred Tax Assets		$321.3			$283.0
Deferred Tax Liabilities
Property Related		$577.1			$482.7
Regulatory Asset for Benefit Obligations	104.3			117.9
Unamortized Investment Tax Credits	11.9			12.8
Partnership Basis Differences	28.6			24.4
Other	30.1			24.0
Total Deferred Tax Liabilities		$752.0			$661.8
Net Deferred Income Taxes		$430.7			$378.8
Recorded as:
Net Current Deferred Tax Liabilities (a)		$6.9			$5.2
Net Long-Term Deferred Tax Liabilities	423.8			373.6
Net Deferred Income Taxes		$430.7			$378.8

(a) Included in Other Current Liabilities.

NOL and Tax Credit Carryforwards
Year Ended December 31	2012		2011
Millions
Federal NOL carryforwards (a)		$244.1		$162.0
Federal tax credit carryforwards	$16.0		$8.4
State NOL carryforwards (a) (b)	$90.6		$73.1
State tax credit carryforwards (c)	$10.3		$3.8

(a) Pretax amounts

(b) Net of $0.4 million valuation allowance.

(c) Net of $2.0 million valuation allowance.

ALLETE 2012 Form 10-K

98

NOTE 14. INCOME TAX EXPENSE (Continued)

In 2012, we generated federal and various state NOLs and tax credit carryforwards primarily due to the bonus depreciation provisions of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 federal NOL will be utilized by carrying it forward to offset future years’ income. The federal NOL and tax credit carryforward periods expire between 2019 and 2032; included in the federal NOL carryforward are charitable contribution carryforwards which expire between 2014 and 2016. We expect to fully utilize the federal NOL, charitable contributions, and federal tax credit carryforwards; therefore no valuation allowance has been recognized as of December 31, 2012.

The state NOLs and tax credits will be carried forward to future tax years. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration. The state NOL and tax credit carryforward periods expire between 2024 and 2032; included in the state NOL carryforwards are charitable contribution carryforwards which expire between 2014 and 2016.

Gross Unrecognized Income Tax Benefits	2012			2011			2010
Millions
Balance at January 1		$11.4			$12.3			$9.5
Reductions for Tax Positions Related to the Current Year	—			—			(0.2		)
Additions for Tax Positions Related to Prior Years	—			—			4.4
Reductions for Tax Positions Related to Prior Years	(8.7		)	(0.9		)	—
Reductions for Settlements	—			—			(0.3		)
Reductions for Expired Statute of Limitations	—			—			(1.1		)
Balance as of December 31		$2.7			$11.4			$12.3

Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The gross unrecognized tax benefits as of December 31, 2012, includes $0.5 million of net unrecognized tax benefits that, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $8.7 million in 2012 was due to the removal of our uncertain tax position for our tax accounting method change for deductible repairs. During 2012, the IRS issued a directive from its Large Business and International Division to its local examination teams that led to the removal of the repairs uncertain tax position in 2012.

As of December 31, 2012, we had $0.5 million ($1.1 million for 2011 and $0.7 million for 2010) of accrued interest related to unrecognized tax benefits included in our Consolidated Balance Sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in our Consolidated Statement of Income. In 2012, we recognized a $0.6 million decrease in interest expense (interest expense of $0.4 million for 2011 and a reduction of interest expense of $0.2 million for 2010). There were no penalties recognized in 2012, 2011 or 2010.

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE is currently under examination by the IRS for the tax years 2005 through 2009. ALLETE is no longer subject to federal or state examination for years before 2005.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $2.5 million due to statute expirations and anticipated audit settlements. This amount is primarily due to temporary tax positions.

ALLETE 2012 Form 10-K

99

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. In 2012, we made total contributions of $7.3 million ($33.8 million in 2011, of which $20.0 million was contributed in shares of ALLETE common stock). We also have a defined contribution pension plan covering substantially all employees. The 2012 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $7.7 million ($7.3 million for the 2011 plan year.) (See Note 12. Common Stock and Earnings Per Share and Note 16. Employee Stock and Incentive Plans).

In 2006, the non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and to close the plan to new participants. In conjunction with those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.

We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to age 55 with 10 years of participation in the plan. The postretirement health plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and an irrevocable grantor trust. In 2012, $1.5 million was contributed to the VEBAs. In 2011, we contributed $10.9 million to the VEBAs. There were no contributions made to the grantor trust in 2012 and 2011.

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 pension plans. Contributions are based on estimates and assumptions which are subject to change. We do not expect to make any contributions to the defined benefit pension plan in 2013. In January 2013, we contributed $4.8 million to the defined benefit postretirement health and life plan, of which $2.0 million was contributed to an irrevocable grantor trust and $2.8 million was contributed to the VEBAs. We do not expect to make any additional contributions to the defined benefit postretirement health and life plan in 2013.

Accounting for defined benefit pension and postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their Consolidated Balance Sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

The defined benefit pension and postretirement health and life benefit costs recognized annually by our regulated companies are expected to be recovered through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset on our Consolidated Balance Sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit costs associated with our other non-rate base operations are recognized in accumulated other comprehensive income.

ALLETE 2012 Form 10-K

100

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Obligation and Funded Status
Year Ended December 31	2012			2011
Millions
Accumulated Benefit Obligation		$598.7			$550.6
Change in Benefit Obligation
Obligation, Beginning of Year		$597.5			$525.6
Service Cost	9.1			7.6
Interest Cost	26.4			27.4
Actuarial Loss	38.5			54.6
Benefits Paid	(30.9		)	(28.6		)
Participant Contributions	11.5			10.9
Obligation, End of Year		$652.1			$597.5
Change in Plan Assets
Fair Value, Beginning of Year		$432.4			$382.0
Actual Return on Plan Assets	38.7			33.2
Employer Contribution	19.9			45.8
Benefits Paid	(30.9		)	(28.6		)
Fair Value, End of Year		$460.1			$432.4
Funded Status, End of Year	$(192.0)			$(165.1)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(190.9)			$(164.0)

The pension costs that are reported as a component within our Consolidated Balance Sheet, reflected in long-term regulatory assets and accumulated other comprehensive income, consist of the following:

Unrecognized Pension Costs
Year Ended December 31	2012		2011
Millions
Net Loss		$286.8		$269.0
Prior Service Cost	0.7		1.1
Total Unrecognized Pension Costs		$287.5		$270.1

Components of Net Periodic Pension Expense
Year Ended December 31	2012			2011			2010
Millions
Service Cost		$9.1			$7.6			$6.2
Interest Cost	26.4			27.4			26.2
Expected Return on Plan Assets	(35.4		)	(34.6		)	(33.7		)
Amortization of Loss	17.5			12.1			6.6
Amortization of Prior Service Cost	0.3			0.3			0.5
Net Pension Expense		$17.9			$12.8			$5.8

ALLETE 2012 Form 10-K

101

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2012			2011
Millions
Net Loss		$35.2			$56.1
Amortization of Prior Service Cost	(0.3		)	(0.3		)
Amortization of Loss	(17.5		)	(12.2		)
Total Recognized in Other Comprehensive Income and Regulatory Assets		$17.4			$43.6

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 31	2012		2011
Millions
Projected Benefit Obligation		$652.1		$597.5
Accumulated Benefit Obligation		$598.7		$550.6
Fair Value of Plan Assets		$460.1		$432.4

Postretirement Health and Life Obligation and Funded Status
Year Ended December 31	2012			2011
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$210.6			$204.1
Service Cost	4.2			3.8
Interest Cost	9.4			10.8
Actuarial Gain	(43.2		)	(2.9		)
Participant Contributions	2.6			2.5
Plan Amendments	(5.3		)	—
Benefits Paid	(9.5		)	(7.7		)
Obligation, End of Year		$168.8			$210.6
Change in Plan Assets
Fair Value, Beginning of Year		$121.0			$114.7
Actual Return on Plan Assets	14.3			—
Employer Contribution	2.3			11.4
Participant Contributions	2.5			2.5
Benefits Paid	(9.1		)	(7.6		)
Fair Value, End of Year		$131.0			$121.0
Funded Status, End of Year	$(37.8)			$(89.6)
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(0.8)			$(0.9)
Non-Current Liabilities	$(37.0)			$(88.7)

According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the above table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $22.1 million in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at December 31, 2012 ($20.3 million at December 31, 2011).

ALLETE 2012 Form 10-K

102

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

The postretirement health and life costs that are reported as a component within our Consolidated Balance Sheet, reflected in regulatory long-term assets and accumulated other comprehensive income, consist of the following:

Unrecognized Postretirement Health and Life Costs
Year Ended December 31	2012			2011
Millions
Net Loss		$23.5			$78.5
Prior Service Credit	(13.1		)	(9.5		)
Transition Obligation	—			0.1
Total Unrecognized Postretirement Health and Life Costs		$10.4			$69.1

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2012			2011			2010
Millions
Service Cost		$4.2			$3.8			$4.8
Interest Cost	9.4			10.8			10.9
Expected Return on Plan Assets	(9.9		)	(9.7		)	(9.5		)
Amortization of Prior Service Credit	(1.7		)	(1.7		)	(0.1		)
Amortization of Loss	7.5			8.5			4.8
Amortization of Transition Obligation	0.1			0.1			2.5
Net Postretirement Health and Life Expense		$9.6			$11.8			$13.4

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2012		2011
Millions
Net (Gain) Loss	$(47.5)			$6.9
Prior Service Credit Arising During the Period	(5.3	)	—
Amortization of Prior Service Credit	1.7		1.7
Amortization of Transition Obligation	(0.1	)	(0.1		)
Amortization of Loss	(7.5	)	(8.5		)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(58.7)		—

Estimated Future Benefit Payments
			Postretirement
	Pension		Health and Life
Millions
2013		$31.2		$7.6
2014		$32.1		$8.2
2015		$33.2		$8.9
2016		$34.4		$9.4
2017		$35.5		$9.7
Years 2018 – 2022		$189.4		$52.0

ALLETE 2012 Form 10-K

103

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

The pension and postretirement health and life costs recorded in regulatory long-term assets and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2013, are as follows:

	Pension		Postretirement Health and Life
Millions
Net Loss		$21.4		$1.6
Prior Service Cost (Credit)	0.3		(2.5		)
Total Pension and Postretirement Health and Life Cost (Credit)		$21.7	$(0.9)

Weighted-Average Assumptions Used to Determine Benefit Obligation
As of December 31	2012	2011
Discount Rate
Pension	4.10%	4.54%
Postretirement Health and Life	4.13%	4.56%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%
Health Care Trend Rates
Trend Rate	9.25%	10%
Ultimate Trend Rate	5%	5%
Year Ultimate Trend Rate Effective	2019	2018

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2012	2011	2010
Discount Rate	4.54 - 4.56%	5.36 - 5.40%	5.81%
Expected Long-Term Return on Plan Assets
Pension	8.25%	8.5%	8.5%
Postretirement Health and Life	6.6 - 8.25%	6.8 - 8.5%	6.8 - 8.5%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%	4.3 - 4.6%

In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return.

The discount rate is computed using a yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension obligation.

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent		One Percent
	Increase		Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$2.0	$(1.6)
Effect on Postretirement Health and Life Obligation		$18.2	$(15.1)

ALLETE 2012 Form 10-K

104

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Actual Plan Asset Allocations
	Pension				Postretirement Health and Life (a)
	2012		2011		2012		2011
Equity Securities	54	%	52	%	56	%	51	%
Debt Securities	28	%	27	%	35	%	39	%
Private Equity	13	%	16	%	9	%	10	%
Real Estate	5	%	5	%	—		—
	100	%	100	%	100	%	100	%

(a) Includes VEBAs and irrevocable grantor trusts.

There were no shares of ALLETE common stock included in pension plan equity securities at December 31, 2012 ($20.0 million, approximately 0.5 million shares, in 2011).

To achieve strong returns within managed risk, we diversify our asset portfolio to approximate the target allocations in the table below. Equity securities are diversified among domestic companies with large, mid and small market capitalizations, as well as investments in international companies. The majority of debt securities are made up of investment grade bonds.

Plan Asset Target Allocations
			Postretirement
	Pension		Health and Life (a)
Equity Securities	52	%	48	%
Debt Securities	30	%	34	%
Real Estate	9	%	9	%
Private Equity	9	%	9	%
	100	%	100	%

(a) Includes VEBAs and irrevocable grantor trusts.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes various U.S. equity securities, public mutual funds, and futures. These instruments are valued using the closing price from the applicable exchange or whose value is quoted and readily traded daily.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs. This category includes various bonds and non-public funds whose underlying investments may be level 1 or level 2 securities.

ALLETE 2012 Form 10-K

105

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.

Pension Fair Value

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$43.0		$36.0	—			$79.0
U.S. Mid-cap Growth (a)	18.3		15.3		—		33.6
U.S. Small-cap (a)	18.3		15.3		—		33.6
International	50.5		45.9		—		96.4
Debt Securities:
Mutual Funds	72.5		—		—		72.5
Fixed Income	10.4		50.8		—		61.2
Other Types of Investments:
Private Equity Funds	—		—			$58.9	58.9
Real Estate	—		—		24.9		24.9
Total Fair Value of Assets		$213.0		$163.3		$83.8		$460.1

(a) The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2011		$69.0			$21.7
Actual Return on Plan Assets	(9.7		)	3.4
Purchases, sales, and settlements, net	(0.4		)	(0.2		)
Balance as of December 31, 2012		$58.9			$24.9

ALLETE 2012 Form 10-K

106

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$37.3	—			$69.4
U.S. Mid-cap Growth (a)	13.5		15.8		—		29.3
U.S. Small-cap (a)	13.1		15.2		—		28.3
International	—		75.1		—		75.1
ALLETE	21.3		—		—		21.3
Debt Securities:
Mutual Funds	72.8		—		—		72.8
Fixed Income	—		45.5		—		45.5
Other Types of Investments:
Private Equity Funds	—		—			$69.0	69.0
Real Estate	—		—		21.7		21.7
Total Fair Value of Assets		$152.8		$188.9		$90.7		$432.4

(a) The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

Recurring Fair Value Measures
Activity in Level 3	Equity Securities (ARS)			Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2010		$6.7			$50.7			$20.1
Actual Return on Plan Assets	—			30.9			3.5
Purchases, sales, and settlements, net	(6.7		)	(12.6		)	(1.9		)
Balance as of December 31, 2011	—				$69.0			$21.7

ALLETE 2012 Form 10-K

107

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Postretirement Health and Life Fair Value

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$16.7	—		—			$16.7
U.S. Mid-cap Growth (a)	13.2		—		—		13.2
U.S. Small-cap (a)	13.3		—		—		13.3
International	30.3		—		—		30.3
Debt Securities:
Mutual Funds	25.5		—		—		25.5
Fixed Income	0.2			$18.3	—		18.5
Other Types of Investments:
Private Equity Funds	—		—			$13.5	13.5
Total Fair Value of Assets		$99.2		$18.3		$13.5		$131.0

(a) The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2011		$14.0
Actual Return on Plan Assets	0.2
Purchases, sales, and settlements, net	(0.7		)
Balance as of December 31, 2012		$13.5

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$15.9	—		—			$15.9
U.S. Mid-cap Growth (a)	11.5		—		—		11.5
U.S. Small-cap (a)	11.2		—		—		11.2
International	25.1		—		—		25.1
Debt Securities:
Mutual Funds	24.1		—		—		24.1
Fixed Income	0.3			$18.9	—		19.2
Other Types of Investments:
Private Equity Funds	—		—			$14.0	14.0
Total Fair Value of Assets		$88.1		$18.9		$14.0		$121.0

(a) The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

ALLETE 2012 Form 10-K

108

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2010		$12.4
Actual Return on Plan Assets	1.1
Purchases, sales, and settlements, net	0.5
Balance as of December 31, 2011		$14.0

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health benefit, including a prescription drug benefit, which qualifies us for a federal subsidy under the Act. The federal subsidy is reflected in the premiums charged to us by the insurance company.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor a leveraged ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire. In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our newly issued common stock. The note was refinanced in 2006 at 6 percent. We make annual contributions to the ESOP equal to the ESOP’s debt service less available dividends received by the ESOP. The majority of dividends received by the ESOP are used to pay debt service, with the balance distributed to participants. The ESOP shares were initially pledged as collateral for the debt. As the debt is repaid, shares are released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares are released from collateral, we report compensation expense equal to the current market price of the shares less dividends on allocated shares. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings; available dividends on unallocated ESOP shares are recorded as a reduction of debt and accrued interest. ESOP compensation expense was $7.7 million in 2012 ($7.4 million in 2011; $7.1 million in 2010).

According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.

Year Ended December 31	2012		2011		2010
Millions
ESOP Shares
Allocated	2.2		2.2		2.2
Unallocated	0.7		1.0		1.3
Total	2.9		3.2		3.5
Fair Value of Unallocated Shares		$28.7		$42.0		$48.4

Stock-Based Compensation.Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, stock appreciation rights and other awards. There are 1.2 million shares of common stock reserved for issuance under the Executive Plan, with 0.6 million of these shares available for issuance as of December 31, 2012.

We had a Director Long-Term Stock Incentive Plan (Director Plan) which expired on January 1, 2006. No grants have been made since 2003 under the Director Plan. The 1,293 remaining options outstanding at December 31, 2011, were exercised during 2012. There were no options outstanding under the Director Plan at December 31, 2012.

ALLETE 2012 Form 10-K

109

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

We currently have the following types of share-based awards outstanding:

Non-Qualified Stock Options. These options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to three months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are canceled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is retirement eligible. Stock options have not been granted under our Executive Plan since 2008.

The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the grant date. Expected volatility is estimated based on the historic volatility of our stock and the stock of our peer group companies. We utilize historical option exercise and employee pre-vesting termination data to estimate the option life. The dividend growth rate is based upon historical growth rates in our dividends.

Performance Shares. Under the performance share awards plan, the number of shares earned is contingent upon attaining specific market goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies. In the case of qualified retirement, death or disability during a performance period, a pro rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is determined by the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients.

Restricted Stock Units. Under the restricted stock units plan, shares for retirement eligible participants vest monthly over a three-year period. For non-retirement eligible participants, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients.

Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price. Because the discount is not greater than 5 percent, we are not required to apply fair value accounting to these awards.

RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.

The following share-based compensation expense amounts were recognized in our Consolidated Statement of Income for the periods presented.

Share-Based Compensation Expense
Year Ended December 31	2012		2011		2010
Millions
Stock Options	—		—			$0.1
Performance Shares		$1.4		$1.1	1.5
Restricted Stock Units	0.7		0.5		0.6
Total Share-Based Compensation Expense		$2.1		$1.6		$2.2
Income Tax Benefit		$0.9		$0.7		$0.9

ALLETE 2012 Form 10-K

110

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized stock-based compensation costs at December 31, 2012, 2011, or 2010.

As of December 31, 2012, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $1.3 million and $0.6 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years for performance share awards and 1.7 years for restricted stock units.

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options as of December 31, 2012.

	2012			2011			2010
	Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price
Outstanding as of January 1,	460,234		$41.68	560,887		$40.69	646,235		$40.05
Granted (a)	—	—		—	—		—	—
Exercised	49,075		$35.84	80,798		$34.25	40,769		$27.76
Forfeited	15,481		$44.86	19,855		$43.96	44,579		$43.16
Outstanding as of December 31,	395,678		$42.28	460,234		$41.68	560,887		$40.69
Exercisable as of December 31,	395,678		$41.71	460,234		$41.59	523,491		$39.76

(a) Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Cash received from non-qualified stock options exercised was less than $0.1 million in 2012. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.3 million during 2012 ($0.5 million in 2011; $0.3 million in 2010).

	Range of Exercise Price
As of December 31, 2012	$23.79 to $26.91		$37.76 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	1,340		236,052		158,286
Weighted Average Remaining Contractual Life (Years)	0.1		3.5		3.6
Weighted Average Exercise Price		$23.79		$39.64		$46.38

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2012.

	2012				2011				2010
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Non-vested as of January 1,	128,333			$36.54	122,489			$38.15	121,825			$41.96
Granted (a)	38,764			$44.70	39,312			$41.00	49,302			$35.44
Awarded	(41,009	)		$34.25	(32,368	)		$48.10	—		—
Unearned Grant Award	(17,575	)		$34.25	—		—		(22,909	)		$54.50
Forfeited	(614	)		$34.49	(1,100	)		$34.35	(25,729	)		$36.45
Non-vested as of December 31,	107,899			$40.73	128,333			$36.54	122,489			$38.15

(a)    Shares granted includes accrued dividends.

ALLETE 2012 Form 10-K

111

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were 33,525 and 41,332 performance shares granted in January 2012 and 2013, for the three-year performance periods ending in 2014 and 2015, respectively. The ultimate issuance is contingent upon the attainment of certain future market goals of ALLETE during the performance periods. The grant date fair value of the performance shares granted was $1.5 million and $2.2 million, respectively.

There were 41,009 and 18,605 performance shares awarded in February 2012 and 2013, for the three-year performance periods ending in 2011 and 2012, respectively. The grant date fair value of the shares awarded was $1.4 million and $0.7 million, respectively.

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2012.

	2012				2011				2010
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Available as of January 1,	63,464			$32.57	43,803			$30.61	28,983			$29.41
Granted (a)	18,162			$40.83	20,136			$36.74	26,589			$31.83
Awarded	(24,707	)		$29.43	(215	)		$30.30	(3,091	)		$29.75
Forfeited	(504	)		$31.80	(260	)		$29.41	(8,678	)		$30.62
Available as of December 31,	56,415			$36.61	63,464			$32.57	43,803			$30.61

(a)    Shares granted includes accrued dividends.

There were 16,355 and 19,193 restricted stock units granted in January 2012 and 2013, for the vesting periods ending in 2014 and 2015, respectively. The grant date fair value of the restricted stock units granted was $0.7 million and $0.8 million, respectively.

There were 24,707 restricted stock units awarded in 2012. The grant date fair value of the shares awarded was $0.7 million.

There were 20,939 restricted stock units awarded in February 2013. The grant date fair value of the shares awarded was $0.7 million.

NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)

Information for any one quarterly period is not necessarily indicative of the results which may be expected for the year.

Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
2012
Operating Revenue		$240.0		$216.4		$248.8		$256.0
Operating Income		$38.4		$23.3		$45.6		$47.9
Net Income Attributable to ALLETE		$24.4		$14.4		$29.4		$28.9
Earnings Per Share of Common Stock
Basic		$0.66		$0.39		$0.78		$0.76
Diluted		$0.66		$0.39		$0.78		$0.75
2011
Operating Revenue		$242.2		$219.9		$226.9		$239.2
Operating Income		$50.8		$26.1		$38.9		$34.2
Net Income Attributable to ALLETE		$37.2		$17.0		$20.5		$19.1
Earnings Per Share of Common Stock
Basic		$1.07		$0.49		$0.57		$0.53
Diluted		$1.07		$0.48		$0.57		$0.53

ALLETE 2012 Form 10-K

112

Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves

	Balance at Beginning of Period		Additions			Deductions from Reserves (a)		Balance at End of Period
			Charged to Income		Other Charges
Millions
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2010 Trade Accounts Receivable		$0.9		$1.1	—		$1.1		$0.9
Finance Receivables – Long-Term		$0.4		$0.8	—		$0.4		$0.8
2011 Trade Accounts Receivable		$0.9		$1.3	—		$1.3		$0.9
Finance Receivables – Long-Term		$0.8		$0.1	—		$0.3		$0.6
2012 Trade Accounts Receivable		$0.9		$1.0	—		$0.9		$1.0
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
Deferred Asset Valuation Allowance
2010 Deferred Tax Assets		$0.3	$0.2		—	—			$0.5
2011 Deferred Tax Assets		$0.5	$(0.1)		—	—			$0.4
2012 Deferred Tax Assets		$0.4		$2.0	—	—			$2.4

(a) Includes uncollectible accounts written off.

ALLETE 2012 Form 10-K

113

EX-10.(F)5

Exhibit 10(f)5

ALLETE Executive Annual Incentive Plan

Form of Award

Effective 2013

[Eligible Executive Employees]

Target Award Opportunity

Base Salary	$
Times
Award Opportunity (percent of base salary)	%
Equals
Target Award	$

Performance Levels and Award Amounts

Goal Performance Level	Payout as Percent of Target Award	Award Amount
Superior	200%	$
Target	100%	$
Threshold	37.5%	$
Below Threshold	—%	$

Goals

		Goal
		Weighting
Financial Goals
	Net Income	50%
	Cash from Operating Activities	25%
Strategic & Operational Positioning Goals		25%
		100%

Compensation Subject to Compensation Recovery Policy

Annual Incentive Plan Compensation is subject to recoupment as defined in the Compensation Recovery policy.

EX-10.(J)

Exhibit 10(j)

ALLETE, INC. AMENDED AND RESTATED

DEFERRED COMPENSATION TRUST AGREEMENT

Effective December 15, 2012

ALLETE, INC. AMENDED AND RESTATED

DEFERRED COMPENSATION TRUST AGREEMENT

This Grantor Trust Agreement (the “Trust Agreement”) is made this 15^th day of December, 2012 by and between ALLETE, INC. (“the Company”) and WELLS FARGO BANK, NATIONAL ASSOCIATION (“the Trustee”) and hereby amends and restates the Minnesota Power and Affiliated Companies Deferred Compensation Trust Agreement (the “Original Trust Agreement”), effective January 1, 1990, for the participants under such agreement who have consented to this amended and restated Trust Agreement (“Consenting Participants”). The Original Trust Agreement will continue to be effective for the participants in the Arrangements to whom benefit payments are owed at the time the Trust Agreement is adopted who have not consented to this amended and restated Trust Agreement (“Non-consenting Participants”).

Recitals

(a) WHEREAS, the Company has adopted the nonqualified deferred compensation plans and agreements (the “Arrangements”) attached hereto as Attachment A, which may be amended from time to time;

(b) WHEREAS, the Company has incurred or expects to incur liability under the terms of such Arrangements with respect to the individuals participating in such Arrangements or beneficiaries designated by such participants who are entitled to receive benefits under the terms of such arrangements as the result of the death of the participant (collectively, the “Participants”);

(c) WHEREAS, the Company hereby establishes a Trust (the “Trust”) and shall contribute to the Trust assets that shall be held therein, subject to the claims of the Company's creditors in the event of the Company's Insolvency, as herein defined, until paid to Participants in such manner and at such times as specified in the Arrangements and in this Trust Agreement;

(d) WHEREAS, it is the intention of the parties that this Trust shall constitute an unfunded arrangement and shall not affect the status of the Arrangements as an unfunded plan maintained for the purpose of providing deferred compensation for a select group of management or highly compensated employees for purposes of Title I of the Employee Retirement Income Security Act of 1974;

2

(e) WHEREAS, it is the intention of the parties that this Trust shall be interpreted in all respects to comply with Internal Revenue Code Section 409A (IRC Section 409A) and applicable authorities promulgated thereunder as may change from time to time; and

(f) WHEREAS, it is the intention of the Company to make contributions to the Trust to provide itself with a source of funds (“the Fund”) to assist it in satisfying its liabilities under the Arrangements.

NOW, THEREFORE, the parties do hereby establish the Trust and agree that the Trust shall be comprised, held and disposed of as follows:

Section 1.Establishment of The Trust

(a) The Trust is intended to be a Grantor Trust, of which the Company is the Grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended, and shall be construed accordingly.

(b) The Company shall be considered a Grantor for the purposes of the Trust.

(c) Subject to Section 1(i), the Trust hereby established is irrevocable.

(d) The Company hereby deposits with the Trustee those assets previously held under the Original Trust Agreement attributable to the Consenting Participants, which assets are listed in Attachment B hereto (the “Initial Contribution”) which shall become the principal of this Trust to be held, administered and disposed of by the Trustee as provided in this Trust Agreement.

(e) The principal of the Trust, and any earnings thereon shall be held separate and apart from other funds of the Company and shall be used exclusively for the uses and purposes of Participants and general creditors as herein set forth. Participants shall have no preferred claim on, or any beneficial ownership interest in, any assets of the Trust. Any rights created under the Arrangements and this Trust Agreement shall be unsecured contractual rights of Participants against the Company. Any assets held by the Trust will be subject to the claims of the general creditors of the Company under federal and state law in the event the Company is Insolvent, as defined in Section 3(a) herein.

(f) The Company, in its sole discretion, may at any time, or from time to time, make additional deposits of cash or other property acceptable to the Trustee in the Trust to augment the principal to be held, administered and disposed of by the Trustee as provided in this Trust Agreement. Prior to a Change in Control (as defined in Section 15) or, if earlier, a Potential Change in Control (as defined in Section 15) (a “Triggering Event,” as such term is more fully defined in Section 15), neither the Trustee nor any Participant shall have any right to compel additional deposits.

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(g) In addition to the Initial Contribution, the Company shall make such other contributions as shall from time to time be authorized by due corporate action. Any such payments made by the Company may be in cash, by letter of credit or, prior to the date as of which a Triggering Event, occurs, in such property (including, without limitation, securities issued by the Company) as the Company may determine. The Company shall keep accurate books and records with respect to the interest of each Executive in any Arrangement and shall provide copies of such books and records to the Trustee at any time as the Trustee shall request.

(h) Upon a Triggering Event, the Company shall, as soon as possible, but in no event longer than thirty (30) days following the occurrence of the Triggering Event, make a contribution to the Trust in an amount that is sufficient (taking into account the Trust assets, if any, resulting from prior contributions) to fund the Trust in an amount equal to no less than 100% of the Required Funding and the Expense Reserve. The Required Funding shall be equal to the amount necessary to pay each Participant the benefits to which Participants would be entitled pursuant to the terms of the Arrangements as of the date on which the Triggering Event occurred. The Expense Reserve shall be equal to the greater of: 1) the estimated trustee and record-keeper expenses and fees for one year or 2) fifty thousand dollars ($50,000). Annually, the Company shall recalculate the Required Funding and the Expense Reserve as of December 31 of the preceding year and, if the assets of the trust are less than the sum of the Required Funding and the Expense Reserve, the Company shall make a contribution to the Trust in an amount equal to no less than 100% of the Required Funding and the Expense Reserve.

(i) In the event a Change in Control does not occur within two years of a Potential Change in Control or, earlier if, within such two year period, the Chief Executive Officer of the Company determines that the Potential Change in Control no longer exists in accordance with Section 15(b), the Company shall have the right to recover any amounts contributed to and remaining on hand in the Trust pursuant to a payment made upon the occurrence of a Potential Change in Control in accordance with Section 1(h).

(j) At the direction of the Company, the Trustee shall establish separate subtrusts for separate Arrangements or groups of Participants covered by the Trust. At the discretion of the Company, such subtrusts may reflect a segregation of particular assets or may reflect an undivided interest in the assets of the Trust, not requiring any segregation of assets. If a Triggering Event occurs, the Trustee shall establish a separate subtrust for all then-existing Participants in the Arrangement (or, at the written direction of either the Company or the Employee Benefit Plans Committee (the “Committee”), for each Participant in the Arrangement who is covered by the Trust). The subtrust established for all then-existing Participants upon a Triggering Event shall require segregation of particular assets. However, individual subtrusts established for each Participant may reflect an undivided interest in the assets of the subtrust for all then-existing Participants and shall not require segregation of particular assets among particular individual subtrusts. Whenever separate subtrusts are established, the then-existing assets of the Trust or affected portion thereof shall be allocated, as directed by the Committee, in proportion to the vested accrued benefits, and, then, if

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any assets remain, the unvested (if any) accrued benefits of the Participants affected thereby, in both instances as of the end of the month immediately preceding such allocation. With respect to any new contributions to the Trust by the Company after separate subtrusts have been established, the Company shall designate the subtrust for which such contributions are made. Except as provided in Section 5(b) herein, after separate subtrusts are established, assets allocated to one subtrust may not be utilized to provide benefits under any other subtrust until all benefits payable under such subtrust have been paid in full. Payments to general creditors in the event of the Company becoming Insolvent shall be charged against the subtrusts in proportion to their account balances, except that payment of benefits to a Participant as a general creditor shall be charged against the subtrust for that Participant.

(k) Notwithstanding the foregoing provisions or any other provision of the Arrangements, no contribution shall be required or made if such contribution would violate the provisions of IRC Section 409A and any applicable authorities promulgated thereunder.

Section 2. Payments to Participants

(a) Prior to a Triggering Event, any distributions from the Trust shall be made by the Trustee to Participants at the direction of the Company. Prior to a Triggering Event, the entitlement of a Participant to benefits under the Arrangements shall be determined by the Committee, and any claim for such benefits shall be considered and reviewed under the procedures set out in the Arrangements. Prior to a Triggering Event, the Company may appoint a third-party administrator (“TPA”) to direct the Trustee with respect to the amount and timing of such payments. After a Triggering Event, the TPA previously appointed by the Company shall continue unless and until the Trustee shall appoint a new TPA to act on its behalf in directing the Trustee with respect to the amount and timing of payments from the Trust.

(b) The Company may direct the Trustee to make payments of benefits to Participants, or the Company may make payments of benefits directly to Participants as they become due under the terms of the Arrangements and may obtain full or partial reimbursement for such benefit payments from the Trust (or offset required contributions to the Trust) within twelve (12) months following the date such payments are made. In addition, if the principal of the Trust, and any earnings thereon, are not sufficient to make payments of benefits in accordance with the terms of the Arrangements, the Company shall make the balance of each such payment as it falls due in accordance with the Arrangements. The Trustee shall notify the Company when principal and earnings are not sufficient to make payments the Trustee has been directed to make by the Company, the Committee, or the TPA. Nothing in this Agreement shall relieve the Company of its liabilities to pay benefits due under the Arrangements except to the extent such liabilities are met by application of assets of the Trust.

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(c) The Company shall deliver to the Trustee a schedule of benefits, to include state and federal tax withholding guidelines, due under the Arrangements on an annual basis. Immediately, as soon as administratively practicable, after a Potential Change in Control and before a Change in Control, the Company shall deliver to the Trustee an updated schedule of benefits due under the Arrangements.

After a Triggering Event, the Trustee shall pay benefits (unless Company pays pursuant to Section 2(b)) due in accordance with such schedule. After a Triggering Event, the TPA shall make the determination of benefits due to Participants and shall provide the Trustee with an updated schedule, to include state and federal tax withholding guidelines, of benefits due; provided however, a Participant may make application to the Trustee for an independent decision as to the amount or form of their benefits due under the Arrangements. In making any determination required or permitted to be made by the Trustee under this Section, the Trustee shall, in each such case, reach its own independent determination, in its absolute and sole discretion, as to the Participant's entitlement to a payment hereunder. In making its determination, the Trustee may consult with and make such inquiries of such persons, including the Participant, the Company, legal counsel, actuaries or other persons, as the Trustee may reasonably deem necessary. Any reasonable costs incurred by the Trustee in arriving at its determination shall be reimbursed by the Company and, to the extent not paid by the Company within a reasonable time, shall be charged to the Trust. The Company waives any right to contest any amount paid over by the Trustee hereunder pursuant to a good faith determination made by the Trustee notwithstanding any claim by or on behalf of the Company (absent a legal violation or manifest abuse of discretion by the Trustee) that such payments should not be made.

(d) The Trustee agrees that it will not itself institute any action at law or at equity, whether in the nature of an accounting, interpleading action, request for a declaratory judgment or otherwise, requesting a court or administrative or quasi-judicial body to make the determination required to be made by the Trustee under this Section 2 in the place and stead of the Trustee. The Trustee may (and, if necessary or appropriate, shall) institute an action to collect a contribution due the Trust following a Triggering Event or in the event that the Trust should ever experience a short-fall in the amount of assets necessary to make payments pursuant to the terms of the Arrangements.

Section 3. Trustee Responsibility Regarding Payments

To The Trust Beneficiary When The Company Is Insolvent

(a) The Trustee shall cease payment of benefits to Participants if the Company is Insolvent. The Company shall be considered “Insolvent” for purposes of this Trust Agreement if (i) the Company is unable to pay its debts as they become due, or (ii) the Company is subject to a pending proceeding as a debtor under the United States Bankruptcy Code.

(b) At all times during the continuance of this Trust, the principal and income of the Trust shall be subject to claims of general unsecured creditors of the Company under federal and state law as set forth below.

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(1) The Board of Directors and the Chief Executive Officer of the Company shall have the duty to inform the Trustee in writing that the Company is Insolvent. If a person claiming to be a creditor of the Company alleges in writing to the Trustee that the Company has become Insolvent, the Trustee shall determine whether the Company

is Insolvent and, pending such determination, the Trustee shall discontinue payment of benefits to Participants.

(2) Unless the Trustee has actual knowledge that the Company is Insolvent, or has received notice from the Company or a person claiming to be a creditor alleging that the Company is Insolvent, the Trustee shall have no duty to inquire whether the Company is Insolvent. The Trustee may in all events rely on such evidence concerning the Company's solvency as may be furnished to the Trustee and that provides the Trustee with a reasonable basis for making a determination concerning the Company's solvency.

(3) If at any time the Trustee has determined that the Company is Insolvent, the Trustee shall discontinue payments to Participants and shall hold the assets of the Trust for the benefit of the Company's general creditors. Nothing in this Trust Agreement shall in any way diminish any rights of Participants to pursue their rights as general creditors of the Company with respect to benefits due under the Arrangements or otherwise.

(4) The Trustee shall resume the payment of benefits to Participants in accordance with Section 2 of this Trust Agreement only after the Trustee has determined that the Company is not Insolvent (or is no longer Insolvent).

(c) Provided that there are sufficient assets, if the Trustee discontinues the payment of benefits from the Trust pursuant to Section 3(b) hereof and subsequently resumes such payments, the first payment following such discontinuance shall include the aggregate amount of all payments due to Participants under the terms of the Arrangements for the period of such discontinuance, less the aggregate amount of any payments made to Participants by the Company in lieu of the payments provided for hereunder during any such period of discontinuance.

Section 4. Payments When a Short-Fall of The Trust Assets Occurs

(a) If there are not sufficient assets for the payment of current and expected future benefits pursuant to Section 2 or Section 3(c) hereof and the Company does not otherwise make such payments within a reasonable time after demand from the Trustee, the Trustee shall allocate the Trust assets among the Participants of a particular subtrust in the following order of priority:

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(1) vested Participants (regardless of whether they are actively employed); and

(2) non-vested Participants (regardless of whether they are actively employed).

(b) Within each category, assets shall be allocated pro-rata with respect to the total present value of benefits expected for each within the category, and payments due under the terms of the Arrangements to each Participant shall be made to the extent of the assets allocated to each Participant. For purposes

of the foregoing, calculations of the present values shall be performed within normal actuarial practices and within the most recent Actuarial Standards of Practice.

(c) Upon receipt of a contribution from the Company necessary to make up for a short-fall in the payments due, the Trustee shall resume payments to all the Participants under the Arrangements. Following a Triggering Event, the Trustee shall have the right and duty to compel a contribution to the Trust from the Company to make-up for any short-fall.

Section 5.Payments to the Company

(a) Except as provided in Section 1(i), Section 2, Section 3, Section 5(b), and Section 8 hereof, the Company shall have no right or power to direct the Trustee to return to the Company or to divert to others any of the Trust assets before all payment of benefits have been made to Participants pursuant to the terms of the Arrangements.

(b) In the event that the Company, prior to a Triggering Event, or the Trustee in its sole and absolute discretion, after a Triggering Event, determines that the Trust assets exceed one-hundred twenty-five percent (125%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements and that all of the subtrusts' assets exceed one-hundred percent (100%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements, the Trustee, at the written direction of the Company, prior to a Triggering Event, or the Trustee in its sole and absolute discretion, after a Triggering Event, shall distribute to the Company such excess portion of Trust assets. For purposes of the foregoing,in the event that the Company, prior to a Triggering Event, or the Trustee in its sole and absolute discretion, after a Triggering Event, determines that the Trust assets in a particular subtrust exceed one-hundred percent (100%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements from such subtrust, such excess amounts may be allocated to other subtrusts whose assets are less than one-hundred percent (100%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements from such subtrust.

Section 6.Investment Authority

(a) Prior to a Triggering Event, the Company shall have the right, subject to this Section, to direct the Trustee with respect to investments.

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(1) The Company may direct the Trustee to segregate all or a portion of the Fund in a separate investment account or accounts and may appoint one or more investment managers and/or an investment committee established by the Company to direct the investment and reinvestment of each such investment account or accounts. In such event, the Company shall notify the Trustee of the appointment of each such investment manager and/or investment committee. No such investment manager shall be related, directly or indirectly, to the Company, but members of the investment committee may be employees of the Company.

(2) Thereafter, until a Triggering Event, the Trustee shall make every sale or investment with respect to such investment account as directed in writing by the investment manager or investment committee. It shall be the duty of the Trustee to act strictly in accordance with each direction. The Trustee shall be under no duty to question any such direction of the investment manager or investment committee, to review any securities or other property held in such investment account or accounts acquired by it pursuant to such directions or to make any recommendations to the investment managers or investment committee with respect to such securities or other property.

(3) Notwithstanding the foregoing, the Trustee, without obtaining prior approval or direction from an investment manager or investment committee, shall invest cash balances held by it from time to time in short term cash equivalents including, but not limited to, through the medium of any short term common, collective, or commingled trust fund established and maintained by the Trustee subject to the instrument establishing such trust fund, U.S. Treasury Bills, commercial paper (including such forms of commercial paper as may be available through the Trustee's Trust Department), certificates of deposit (including certificates issued by the Trustee in its separate corporate capacity), and similar type securities, with a maturity not to exceed one year; and, furthermore, sell such short term investments as may be necessary to carry out the instructions of an investment manager or investment committee regarding more permanent type investment and directed distributions.

(4) The Trustee shall neither be liable nor responsible for any loss resulting to the Fund by reason of any sale or purchase of an investment directed by an investment manager or investment committee nor by reason of the failure to take any action with respect to any investment which was acquired pursuant to any such direction in the absence of further directions of such investment manager or investment committee.

a. Notwithstanding anything in this Agreement to the contrary, the Trustee shall be indemnified and saved harmless by the Company from and against any and all personal liability to which the Trustee may be subjected by carrying out any directions of an investment manager or investment committee issued pursuant hereto or for failure to act in the absence of directions of the investment manager or investment committee including all expenses reasonably incurred in its defense in the event the Company fails to provide such defense; provided, however, the Trustee shall not be so indemnified if it participates knowingly in, or knowingly undertakes to conceal, an

act or omission of an investment manager or investment committee, having actual knowledge that such act or omission is a breach of a fiduciary duty; provided further, however, that the Trustee shall not be deemed to have knowingly

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participated in or knowingly undertaken to conceal an act or omission of an investment manager or investment committee with knowledge that such act or omission was a breach of fiduciary duty by merely complying with directions of an investment manager or investment committee or for failure to act in the absence of directions of an investment manager or investment committee. The Trustee may rely upon any order, certificate, notice, direction or other documentary confirmation purporting to have been issued by the investment manager or investment committee which the Trustee believes to be genuine and to have been issued by the investment manager or investment committee. The Trustee shall not be charged with knowledge of the termination of the appointment of any investment manager or investment committee until it receives written notice thereof from the Company.

b. The Company, prior to a Triggering Event, may direct the Trustee to invest in securities (including stock and the rights to acquire stock) or obligations issued by the Company.

c. All rights associated with respect to any investment held by the Trust, including but not limited to, exercising or voting of proxies, in person or by general or limited proxy, shall be in accordance with and as directed in writing by the Company or its authorized representative.

(b) Following a Triggering Event, the Trustee shall have the power in investing and reinvesting the Fund in its sole discretion, unless otherwise provided below:

(1) To invest and reinvest in any readily marketable common and preferred stocks (including any stock or security of the Company), bonds, notes, debentures (including convertible stocks and securities but not including any stock or security of the Trustee other than a de minimus amount held in a mutual fund), certificates of deposit or demand or time deposits (including any such deposits with the Trustee), limited partnerships or limited liability companies, private placements and shares of investment companies, and mutual funds, without being limited to the classes or property in which the Trustees are authorized to invest by any law or any rule of court of any state and without regard to the proportion any such property may bear to the entire amount of the Fund. Without limitation, the Trustee may invest the Trust in any investment company (including any investment company or companies for which Wells Fargo Bank, N.A. or an affiliated company acts as the investment advisor {“Special Investment Companies”}) or, any insurance contract or contracts issued by an insurance company or companies in each case as the Trustee may determine provided that the Trustee may in its sole discretion keep such portion of the Trust in cash or cash balances for such reasonable periods as may from time to time be deemed advisable pending investment or in order to meet contemplated payments of benefits;

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(2) To invest and reinvest all or any portion of the Fund collectively through the medium of any proprietary mutual fund that may be established and maintained by the Trustee;

(3) To commingle for investment purposes all or any portion of the Fund with assets of any other similar trust or trusts established by the Company with the Trustee for the purpose of safeguarding deferred compensation or retirement income benefits of its employees and/or directors;

(4) To retain any property at any time received by the Trustee;

(5) To sell or exchange any property held by it at public or private sale, for cash or on credit, to grant and exercise options for the purchase or exchange thereof, to exercise all conversion or subscription rights pertaining to any such property and to enter into any covenant or agreement to purchase any property in the future;

(6) To participate in any plan of reorganization, consolidation, merger, combination, liquidation or other similar plan relating to property held by it and to consent to or oppose any such plan or any action thereunder or any contract, lease, mortgage, purchase, sale or other action by any person;

(7) To deposit any property held by it with any protective, reorganization or similar committee, to delegate discretionary power thereto, and to pay part of the expenses and compensation thereof for any assessments levied with respect to any such property to be deposited;

(8) To extend the time of payment of any obligation held by it;

(9) To hold uninvested any moneys received by it, without liability for interest thereon, but only in anticipation of payments due for investments, reinvestments, expenses or disbursements;

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(10) To exercise all voting or other rights, at the direction of the Company, with respect to any property held by it and to grant proxies, discretionary or otherwise;

(11) For the purposes of the Trust, to borrow money from others, to issue its promissory note or notes therefor, and to secure the repayment thereof by pledging any property held by it;

(12) To employ suitable contractors and counsel, who may be counsel to the Company or to the Trustee, and to pay their reasonable expenses and compensation from the Fund to the extent not paid by the Company;

(13) To register investments in its own name or in the name of a nominee; and to combine certificates representing securities with certificates of the same issue held by it in other fiduciary capacities or to deposit or to arrange for the deposit of such securities with any depository, even though, when so deposited, such securities may be held in the name of the nominee of such depository with other securities deposited therewith by other persons, or to deposit or to arrange for the deposit of any securities issued or guaranteed by the United States government, or any agency or instrumentality thereof, including securities evidenced by book entries rather than by certificates, with the United States Department of the Treasury or a Federal Reserve Bank, even though, when so deposited, such securities may not be held separate from securities deposited therein by other persons; provided, however, that no securities held in the Fund shall be deposited with the United States Department of the Treasury or a Federal Reserve Bank or other depository in the same account as any individual property of the Trustee, and provided, further, that the books and records of the Trustee shall at all times show that all such securities are part of the Trust Fund;

(14) To settle, compromise or submit to arbitration any claims, debts or damages due or owing to or from the Trust, respectively, to commence or defend suits or legal proceedings to protect any interest of the Trust, and to represent the Trust in all suits or legal proceedings in any court or before any other body or tribunal; provided, however, that the Trustee shall not be required to take any such action unless it shall have been indemnified by the Company to its reasonable satisfaction against liability or expenses it might incur therefrom;

(15) Subject to Section 7, to hold and retain policies of life insurance, annuity contracts, and other property of any kind which policies are contributed to the Trust by the Company or any subsidiary of the Company or are purchased by the Trustee;

(16) To hold any other class of assets which may be contributed by the Company and     that is deemed reasonable by the Trustee, unless expressly prohibited herein;

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(17) To loan any securities at any time held by it to brokers or dealers upon such security as may be deemed advisable, and during the terms of any such loan to permit the loaned securities to be transferred into the name of and voted by the borrower or others; and

(18) Generally, to do all acts, whether or not expressly authorized, that the Trustee may deem necessary or desirable for the protection of the Fund.

(c) Following a Triggering Event, the Trustee shall have the sole and absolute discretion in the management of the Trust assets and shall have all the powers set forth under this Section 6(c). In investing the Trust assets, the Trustee shall consider:

(1) the needs of the Arrangements;

(2) the need for matching of the Trust assets with the liabilities of the Arrangements; and

(3) the duty of the Trustee to act solely in the best interests of the Participants.

(d) In no event may the Trustee invest in offshore securities or any other investments prohibited by IRC Section 409A.

(e) The Trustee shall have the right, in its sole discretion, to delegate its investment responsibility to an investment manager who may be an affiliate of the Trustee. In the event the Trustee shall exercise this right, the Trustee shall remain, at all times responsible for the acts of an investment manager. The Trustee shall have the right to purchase an insurance policy or an annuity to fund the benefits of the Arrangements.

(f) The Company shall have the right at any time to substitute assets (other than securities issued by the Trustee or the Company) of equal fair market value for any asset held by the Trust, provided, however, that no such substitution shall be permitted unless the Trustee determines that the fair market values of the substituted assets are equal (which determination shall be made on a timely basis).

Section 7.Insurance Contracts

(a) To the extent that the Trustee is directed by the Company prior to a Triggering Event to invest part or all of the Trust Fund in insurance contracts, the type and amount thereof shall be specified by the Company. The Trustee shall be under no duty to make inquiry as to the propriety of the type or amount so specified.

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(b) Each insurance contract issued shall provide that the Trustee shall be the owner thereof with the power to exercise all rights, privileges, options and elections granted by or permitted under such contract or under the rules of the insurer. The exercise by the Trustee of any incidents of ownership under any contract shall, prior to a Triggering Event, be subject to the direction of the Company. After a Triggering Event, the Trustee shall have all such rights.

(c) The Trustee shall have no power to name a beneficiary of the policy other than the Trust, to assign the policy (as distinct from conversion of the policy to a different form) other than to a successor Trustee, or to loan to any person the proceeds of any borrowing against an insurance policy held in the Trust Fund.

(d) No insurer shall be deemed to be a party to the Trust and an insurer's obligations shall be measured and determined solely by the terms of contracts and other agreements executed by the insurer.

Section 8.Disposition of Income

(a) Prior to a Triggering Event, all income received by the Trust, net of expenses and taxes, may be returned to the Company or accumulated and reinvested within the Trust at the direction of the Company.

(b) Following a Triggering Event, all income received by the Trust, net of expenses and taxes payable by the Trust, shall be accumulated and reinvested within the Trust.

Section 9.Accounting by The Trustee

The Trustee shall keep accurate and detailed records of all investments, receipts, disbursements, and all other transactions required to be made, including such specific records as shall be agreed upon in writing between the Company and the Trustee. Within forty-five (45) days following the close of each calendar year and within forty-five (45) days after the removal or resignation of the Trustee, the Trustee shall deliver to the Company a written account of its administration of the Trust during such year or during the period from the close of the last preceding year to the date of such removal or resignation setting forth all investments, receipts, disbursements and other transactions effected by it, including a description of all securities and investments purchased and sold with the cost or net proceeds of such purchases or sales (accrued interest paid or receivable being shown separately), and showing all cash, securities and other property held in the Trust at the end of such year or as of the date of such removal or resignation, as the case may be. The Company may approve such account by an instrument in writing delivered to the Trustee. In the absence of the Company's filing with the Trustee objections to any such account within one hundred and eighty (180) days after its receipt, the Company shall be deemed to have so approved such account. In such case, or upon the written approval by the Company of any such account, the Trustee shall, to the extent permitted by law, be discharged from all liability to the Company for its acts or failures to act described by such account. The foregoing, however, shall not preclude the Trustee from having its accounting settled by a court of competent jurisdiction. The Trustee shall be entitled to hold and to commingle the assets of the Trust in one Fund for investment purposes but at the direction of the Company prior to a Change in Control, the Trustee shall create one or more sub-accounts.

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Section 10.Responsibility of The Trustee

(a) The Trustee shall act with the care, skill, prudence and diligence under the circumstances then prevailing that a prudent person acting in like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, provided, however, that the Trustee shall incur no liability to any person for any action taken pursuant to a direction, request or approval given by the Company which is contemplated by, and in conformity with, the terms of the Arrangements or this Trust and is given in writing by the Company. In the event of a dispute between

the Company and a party, the Trustee may apply to a court of competent jurisdiction to resolve the dispute, subject, however to Section 2(d) hereof.

(b) The Company hereby indemnifies the Trustee against losses, liabilities, claims, costs and expenses in connection with the administration of the Trust, unless resulting from the negligence or willful misconduct of Trustee. The Trustee hereby indemnifies the Company against liabilities, claims, costs and expenses resulting from negligence or willful misconduct of the Trustee. The Trustee shall not be liable under any circumstances for indirect, incidental, consequential, punitive, or special damages in connection with the administration of this Trust. To the extent the Company fails to make any payment on account of an indemnity provided in this Section 10(b), in a reasonably timely manner, the Trustee may obtain payment from the Trust. If the Trustee undertakes or defends any litigation arising in connection with this Trust or to protect a Participant's rights under the Arrangements, the Company agrees to indemnify the Trustee against the Trustee's costs, reasonable expenses and liabilities (including, without limitation, attorneys' fees and expenses) relating thereto and to be primarily liable for such payments. If the Company does not pay such costs, expenses and liabilities in a reasonably timely manner, the Trustee may obtain payment from the Trust.

(c) The Trustee may consult with legal counsel (who may also be counsel for the Company generally) with respect to any of its duties or obligations hereunder.

(d) The Trustee may hire agents, accountants, actuaries, investment advisors, financial consultants or other professionals to assist it in performing any of its duties or obligations hereunder and may rely on any determinations made by such agents and information provided to it by the Company.

(e) The Trustee shall have, without exclusion, all powers conferred on the Trustee by applicable law, unless expressly provided otherwise herein.

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(f) Notwithstanding any powers granted to the Trustee pursuant to this Trust Agreement or to applicable law, the Trustee shall not have any power that could give this Trust the objective of carrying on a business and dividing the gains therefrom, within the meaning of section 301.7701-2 of the Procedure and Administrative Regulations promulgated pursuant to the Internal Revenue Code.

Section 11.Compensation and Expenses of The Trustee

The Trustee's compensation shall be as agreed in writing from time to time by the Company and the Trustee. The Company shall pay all administrative expenses and the Trustee's fees and shall promptly reimburse the Trustee for any fees and expenses of its agents. If not so paid within thirty (30) days of being invoiced, the fees and expenses shall be paid from the Trust.

Section 12.Resignation and Removal of The Trustee

(a) Prior to a Triggering Event, the Trustee may resign at any time by written notice to the Committee, which shall be effective sixty (60) days after receipt of such notice unless the Committee and the Trustee agree otherwise. Following a Triggering Event, the Trustee may resign thirty-six (36) months or more after the Triggering Event by written notice to the Committee, which shall be effective sixty (60) days after receipt of such notice or upon shorter notice as the Committee and the Trustee agree. Or, following a Triggering Event, the Trustee may resign twenty-four (24) months or more after the Triggering Event if a successor Trustee has been appointed by the Committee in accordance with Section 13 or the Trustee has received written consent from a Majority of the Participants as defined in Section 15.

(b) Prior to a Triggering Event, the Trustee may be removed by the Committee on sixty (60) days written notice or upon shorter notice accepted by the Trustee. After a Triggering Event, the Trustee may be removed by the Committee with written consent from a Majority of the Participants.

(c) If the Trustee resigns following a Triggering Event and if the Committee fails to appoint a successor Trustee within a reasonable period of time following such resignation, the Trustee shall apply to a court of competent jurisdiction for the appointment of a successor Trustee which satisfies the requirements of Section 13 or for instructions.

(d) Upon resignation or removal of the Trustee and appointment of a successor Trustee, all assets shall subsequently be transferred to the successor Trustee. The transfer shall be completed within sixty (60) days after receipt of notice of resignation, removal or transfer, unless the Committee extends the time limit.

(e) If the Trustee resigns or is removed, a successor Trustee shall be appointed by the Committee, in accordance with Section 13 hereof, by the effective date of resignation or removal under paragraph(s) (a) or (b) of this section. If no such appointment has been made, the Trustee may apply to a court of competent jurisdiction for appointment of a successor or for instructions. All expenses of the Trustee in connection with the proceeding shall be allowed as administrative expenses of the Trust.

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Section 13.Appointment of Successor

(a) If the Trustee resigns or is removed in accordance with Section 12 hereof, the Committee may appoint, subject to Section 12, any third party national banking association with a market capitalization exceeding $25,000,000 to replace the Trustee upon resignation or removal. The successor Trustee shall have all of the rights and powers of the former Trustee, including ownership rights in the Trust. The former Trustee shall execute any instrument necessary or reasonably requested by the Committee or the successor Trustee to evidence the transfer.

(b) The successor Trustee need not examine the records and acts of any prior Trustee and may retain or dispose of existing Trust assets, subject to Section 9 and 10 hereof. The successor Trustee shall not

be responsible for and the Company shall indemnify and defend the successor Trustee from any claim or liability resulting from any action or inaction of any prior Trustee or from any other past event, or any condition existing at the time it becomes successor Trustee.

Section 14. Amendment or Termination

(a) The Company's Board of Directors and the Trustee may amend this Trust Agreement at any time by a written instrument executed by both parties, provided, however, that such amendment shall not become effective until the Company has receive the written consent of a Majority of the Participants. Notwithstanding the foregoing, Participant consent need not be obtained for non-substantive or minor administrative changes, corrections, or clarifications. No such amendment shall conflict with the terms of the Arrangements or shall make the Trust revocable, except as provided in Section 14(c). No amendment made under this Section may violate the provisions of IRC Section 409A.

(b) Following a Triggering Event, the Trust shall not terminate until the date on which Participants have received all of the benefits due to them under the terms and conditions of the Arrangements, except as provided in Section 14(c). Notwithstanding the foregoing, after individual subtrusts have been created, an individual subtrust may be terminated on the date on which all Participants have received all of the benefits due to them under the terms and conditions of the Arrangements covered by such subtrust.

(c) Upon written approval of all Participants entitled to payment of benefits pursuant to the terms of the Arrangements, the Company's Board of Directors may terminate this Trust prior to the time all benefit payments under the Arrangements have been made. All assets in the Trust at termination shall be returned to the Company.

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Section 15.Definitions

(a) For purposes of this Trust, the following terms shall be defined as set forth below:

(1) “Potential Change in Control” shall mean:

i. the purchase or other acquisition by any person, entity or group of persons, within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (“Act”), or any comparable successor provisions, other than the trustee of any other trust or plan maintained for the benefit of employees of the Company, of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Act) of 20% or more of either the outstanding shares of common stock or the combined voting power of the Company's then outstanding voting securities entitled to vote generally;

ii. the announcement by any person of an intention to take actions which might reasonably result in a business combination between the Company and an entity which has a market capitalization equal to or greater than 80% of the Company;

iii. the issuance of a proxy statement by the Company with respect to an election of directors for which there is proposed one or more directors who are not recommended by the Board of Directors of the Company or its nominating committee, where the election of such proposed director or directors would result in a Change in Control as defined in Section 15(a)(2)(iii); or

iv. submission to the individuals who, as of the date hereof, constitute the Board of Directors, of nominations which, if approved, would change the Executive Officer configuration of the Company (at the Executive Vice President level and above) by 50% or more.

(2) “Change in Control” shall mean the earliest of:

i. the date any one person, or more than one person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires ownership of stock of the Company that, together with stock previously held by the acquirer, constitutes more than fifty (50%) percent of the total fair market value or total voting power of Company stock. If any one person, or more than one person acting as a group, is considered to own more than fifty (50%) percent of the total fair market value or total voting power of Company stock, the acquisition of additional stock by the same person or persons acting as a group does not cause a Change in Control. An increase in the percentage of stock owned by any one person, or persons acting as a group, as a result of a transaction in which Company acquires its stock in exchange for property, is treated as an acquisition of stock;

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ii. the date any one person, or more than one person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that person or persons) ownership of Company stock possessing at least thirty (30%) percent of the total voting power of Company stock;

iii. the date a majority of the members of the Company's Board of Directors is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the Board of Directors prior to the date of appointment or election; or

iv. the date any one person, or more than one person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that person or persons) assets from the Company that have a totalgross fair market value equal to at least forty (40%) percent of the total gross fair market value of all the Company's assets immediately prior to the acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the corporation's assets, or the value of the assets being disposed of, without regard to any liabilities associated with these assets.

In determining whether a Change in Control occurs, the attribution rules of Internal Revenue Code Section 318 apply to determine stock ownership. The stock underlying a vested option is treated as owned by the individual who holds the vested option, and the stock underlying an unvested option is not treated as owned by the individual who holds the unvested option.

For purposes of this Section 15(a), the individuals who, as of the date hereof, constitute the Board of Directors, by a majority vote, shall have the power to determine on the basis of information known to them (a) the number of shares beneficially owned by any person, entity or group; (b) whether there exists an agreement, arrangement or understanding with another as to matters referred to in this Section 15(a); (c) whether persons are acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)); and (d) such other matters with respect to which a determination is necessary under this Section 15(a).

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(3) “Majority of the Participants” shall mean Participants whose combined vested and unvested account balance(s) and accrued benefits within the Arrangements exceed 67% of the total Trust liability.

(4) “Triggering Event” shall mean a Change in Control or, if earlier, a Potential Change in Control. However, a Potential Change in Control will cease to be a Triggering Event and the Trust Agreement will be interpreted as if no such Triggering Event had occurred, if a Change in Control does not occur within two years of the Potential Change in Control or if, within such two year period, the Chief Executive Officer of the Company determines that the Potential Change in Control no longer exists in accordance with Section 15(b).

(b) The Chief Executive Officer of the Company shall have the specific authority to determine whether a Potential Change in Control or Change in Control has transpired, and to determine whether the Potential Change in Control no longer exists under the guidance of this Section 15 and shall be required to give the Trustee notice of a Potential Change in Control, of a Change in Control, or if a Potential Change in Control no longer exists. The Trustee shall be entitled to rely upon such notice, but if the Trustee receives notice of a Potential Change in Control or Change in Control from another source, the Trustee shall make its own independent determination.

Section 16.Confidentiality

(a) This Trust Agreement and certain information relating to the Trust is “Confidential Information” pursuant to applicable federal and state law, and as such it shall be maintained in confidence and not disclosed, used or duplicated, except as described in this section. If it is necessary for the Trustee to disclose Confidential Information to a third party in order to perform the Trustee's duties hereunder, the Trustee shall disclose only such Confidential Information as is necessary for such third party to perform its obligations to the Trustee and shall, before such disclosure is made, ensure that said third party understands and agrees to the confidentiality obligations set forth herein. The Trustee and the Company shall maintain an appropriate information security program and adequate administrative and physical safeguards to prevent the unauthorized disclosure, misuse, alteration or destruction of Confidential Information, and shall inform the other party as soon as possible of any security breach or other incident involving possible unauthorized disclosure of or access to Confidential Information. Confidential Information shall be returned to the disclosing party upon request. Confidential Information does not include information that is generally known or available to the public or that is not treated as confidential by the disclosing party, provided, however, that this exception shall not apply to any publicly available information to the extent that the disclosure or sharing of the information by one or both parties is subject to any limitation, restriction, consent, or notification requirement under any applicable federal or state information privacy law or regulation. If the receiving party is required by law, according to the advice of competent counsel, to disclose Confidential Information, the receiving party may do so without breaching this section, but shall first, if feasible and legally permissible, provide the disclosing party with prompt notice of such pending disclosure so that the disclosing party may seek a protective order or other appropriate remedy or waive compliance with the provisions of this section.

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Section 17.Miscellaneous

(a) Any provision of this Trust Agreement prohibited by law shall be ineffective to the extent of any such prohibition, without invalidating the remaining provisions hereof.

(b) The Company hereby represents and warrants that all of the Arrangements have been established, maintained and administered in accordance with all applicable laws, including without limitation, ERISA. The Company hereby indemnifies and agrees to hold the Trustee harmless from all liabilities, including attorney's fees, relating to or arising out of the establishment, maintenance and administration of the Arrangements. To the extent the Company does not pay any of such liabilities in a reasonably timely manner, the Trustee may obtain payment from the Trust.

(c) Benefits payable to Participants under this Trust Agreement may not be anticipated, assigned (either at law or in equity), alienated, pledged, encumbered or subjected to attachment, garnishment, levy, execution or other legal or equitable process.

(d) This Trust Agreement shall be governed by and construed in accordance with the laws of North Carolina.

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IN WITNESS WHEREOF, this Amended and Restated Deferred Compensation Trust Agreement has been executed on behalf of the parties hereto on the day and year first above written.

ALLETE, INC.		WELLS FARGO BANK, NATIONAL ASSOCIATION as TRUSTEE
By:	/s/ Alan R. Hodnik	By:	/s/ Michael D. Hill
Its:	Chairman, President & Chief Executive Officer	Its:	Senior Vice President
ATTEST:		ATTEST:
By:	/s/ Deborah A. Amberg	By:	/s/ Tonya M. Inscore
Its:	Senior Vice President, General Counsel & Secretary	Its:	Senior Vice President

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Attachment A

The following Arrangements are covered by this Trust:

ALLETE and Affiliated Companies Supplemental Executive Retirement Plan

ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II

Minnesota Power and Affiliated Companies Executive Investment Plan I

Minnesota Power and Affiliated Companies Executive Investment Plan II

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Attachment B

24

EX-10.(K)14

Exhibit 10(k)14

ALLETE

EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

PERFORMANCE SHARE GRANT

Effective 2013

[Eligible Executive Employees]

Name

In accordance with the terms of ALLETE's Executive Long-Term Incentive Compensation Plan, as amended (the "Plan"), as determined by and through the Executive Compensation Committee of ALLETE's Board of Directors, ALLETE hereby grants to you (the "Participant") Performance Shares, as set forth below, subject to the terms and conditions set forth in this Grant including Annexes A and B hereto and all documents incorporated herein by reference:

Number of Performance Shares Granted:
Date of Grant:
Performance Period:
Performance Goals:	See Annex B

This Grant is made in accordance with the Plan.

Further terms and conditions of the Grant are set forth in Annex A hereto and Performance Goals are set forth in Annex B hereto, which are integral parts of this Grant.

All terms, provisions and conditions applicable to the Performance Shares set forth in the Plan and not set forth herein are incorporated by reference. To the extent any provision hereof is inconsistent with a provision of the Plan, the provisions of the Plan will govern.

IN WITNESS WHEREOF, ALLETE has caused this Grant to be executed by its Chairman, President & Chief Executive Officer as of the date and year first above written.

ALLETE

By:
	Chairman, President & CEO

Attachments:    Annex A and Annex B

ANNEX A

TO

ALLETE

EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

PERFORMANCE SHARE GRANT

The Grant of Performance Shares evidenced by the Grant to which this is annexed is subject to the following additional terms and conditions:

1.    Dividend Equivalents. The Participant shall receive Dividend Equivalents with respect to the number of Performance Shares subject to the Grant. Dividend Equivalents shall be calculated and credited to the Participant at the end of the Performance Period. The Dividend Equivalents shall be in the form of additional Performance Shares, which shall be added to the number of Performance Shares subject to the Grant, and which shall equal the number of Shares (including fractional Shares) that could be purchased on the dividend payment dates, based on the closing sale price as reported in the consolidated transaction reporting system on that date, with cash dividends that would have been paid on Performance Shares, if such Performance Shares were Shares.

2.    Satisfaction of Goals. At the end of the Performance Period, the Executive Compensation Committee (the “Committee”) shall determine the extent to which the Performance Goals have been met. The Participant will not be credited with any Performance Shares if the threshold level has not been met. Subject to the provisions of Section 4 hereof and to provisions in the Plan for change in control, percentages of the Performance Share grant shall be credited to the Participant as follows: If the threshold level has been met, 50% of the Performance Shares (as increased by the Dividend Equivalents) shall be credited to the Participant. If the target level has been met, 100% of the Performance Shares (as increased by the Dividend Equivalents) shall be credited to the Participant. If the superior level has been met, 200% of the Performance Shares (as increased by the Dividend Equivalents) shall be credited to the Participant. Straight line interpolation will be used to determine earned awards based on achievement of goals between the threshold, target and superior levels.

3.    Payment. Subject to the provisions of subsection (d) hereof and to provisions in the Plan for change in control, Performance Shares as determined by the Committee according to Section 2 hereof shall be paid out 100% (as increased by the Dividend Equivalents) within two and one half months after the end of the Performance Period and after the Committee has determined the extent to which Performance Goals have been met. Payment shall be made, after withholding Performance Shares equal in value to the Participant's income tax obligation via a deposit of ALLETE common stock into an Invest Direct account. Performance Share awards shall not vest until paid.

4.    Payment Upon Death, Retirement or Disability; Forfeiture of Unvested Performance Shares Upon Demotion, Unsatisfactory Job Performance or Other Separation from Service.

4.1    If during a Performance Period the Participant (i) Retires, (ii) dies while employed by a Related Company, or (iii) becomes Disabled, the Participant (or the Participant's beneficiary or estate) shall receive a payment of any Performance Shares (as increased by the Dividend Equivalents) after the end of the Performance Period, promptly after the Committee has determined the extent to which Performance Goals have been met. The payment shall be prorated based upon the number of whole calendar months within the Performance Period which had elapsed as of the date of death, Retirement or Disability in relation to the number of calendar

months in the full Performance Period. A whole month is counted in the calculation if the Participant was in the position as of the 15^th of the month.

4.2     If after the end of a Performance Period, but before any or all Performance Shares have been paid, as specified in Section 4.1 above, the Participant Retires, dies or becomes Disabled, the Participant (or the Participant's beneficiary or estate) shall be entitled to a full payout of all Performance Shares (as increased by the Dividend Equivalents), which shall be paid out at the next scheduled performance share payment date.

4.3    If prior to payment of all Performance Shares, the Participant is demoted, or ALLETE or a Business Unit determines, in its sole discretion, that the Participant's job performance is unsatisfactory, ALLETE reserves the right to cancel or amend the Participant's grant relating to any unpaid Performance Shares, with the result that some portion or all of the Participant's unpaid Performance Shares will be forfeited.

4.4    If the Participant has a Separation from Service for any reason other than those specified in subsection 4.1 above, all Performance Shares and related Dividend Equivalents to the extent not yet paid shall be forfeited on the date of such Separation from Service, except as otherwise provided by the Committee.

5.    Compensation Recovery Policy. The Grant is subject to the terms of any compensation recovery policy or policies established by ALLETE as may be amended from time to time (“Compensation Recovery Policy”). ALLETE hereby incorporates into the Grant the terms of the Compensation Recovery Policy.

6.    Ratification of Actions. By receiving the Grant or other benefit under the Plan, the Participant and each person claiming under or through Participant shall be conclusively deemed to have indicated the Participant's acceptance and ratification of, and consent to, any action taken under the Plan or the Grant by ALLETE, the Board or the Committee.

7.    Notices. Any notice hereunder to ALLETE shall be addressed to ALLETE, 30 West Superior Street, Duluth, Minnesota 55802, Attention: Manager - Compensation and Benefits, Human Resources, and any notice hereunder to the Participant shall be directed to the Participant's address as indicated by ALLETE's records, subject to the right of either party to designate at any time hereafter in writing some other address.

8.    Governing Law and Severability. To the extent not preempted by the Federal law, the Grant will be governed by and construed in accordance with the laws of the State of Minnesota, without regard to its conflicts of law provisions. In the event any provision of the Grant shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Grant, and the Grant shall be construed and enforced as if the illegal or invalid provision had not been included.

9.    Definitions. Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan. The following definitions apply to the Grant and this Annex A:

9.1    “Code” means the Internal Revenue Code of 1986, as it may be amended from time to time.

9.2    “Disability” or “Disabled” means a physical or mental condition in which the Participant is:

(a) unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months;

(b) by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under the Employer's accident and health plan;

(c) determined to be totally disabled by the Social Security Administration; or

(d) disabled pursuant to an Employer-sponsored disability insurance arrangement provided that the definition of disability applied under such disability insurance program complies with the foregoing definition of Disability.

9.3    “Related Company” means ALLETE, Inc. and all persons with whom the ALLETE, Inc. would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.

9.4    “Retirement” or “Retires” means Separation from Service, for reasons other than death or Disability, on or after attaining normal retirement age or early retirement age as defined in the most applicable qualified retirement plan sponsored by the Related Company that employed the Participant immediately preceding the Separation from Service, without regard to whether the Participant is a participant in such plan, or if the employer Related Company does not sponsor such retirement plan, on or after attaining Normal Retirement Age or Early Retirement Age as defined in the ALLETE and Affiliated Companies Retirement Plan A, without regard to whether the Participant is a participant under the ALLETE and Affiliated Companies Retirement Plan A.

9.5    “Separation from Service” means that the Participant terminates employment within the meaning of Treasury Regulations section 1.409A-1(h) and other applicable guidance with all Related Companies. Whether a termination of employment has occurred is determined under the facts and circumstances, and a termination of employment shall occur if all Related Companies and the Participant reasonably anticipate that no further services shall be performed after a certain date or that the level of bona fide services the Participant shall perform after such

date (as an employee or an independent contractor) shall permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Related Companies if the Participant has been providing services to the Related Companies less than 36 months). A Participant shall not be considered to separate from service during a bona fide leave of absence for less than six (6) months or longer if the Participant retains a right to reemployment with any Related Company by contract or statute. With respect to disability leave, a Participant shall not be considered to separate from service for 29 months unless the Participant otherwise terminates employment or is terminated by all Related Companies.

ANNEX B

TO

ALLETE

Executive Long Term Incentive Compensation Plan

Performance Share Grant

Effective 2013

[Eligible Executive Employees]

Financial Measure:

Total Shareholder Return (TSR) computed over the three-year period.

Performance Share Award:

If ALLETE's TSR ranking is 4th or higher among a peer group of 27 companies (superior performance), 200% of the Performance Share Grant will be earned. If ALLETE's TSR performance ranks 14^th among the peer group (target performance), 100% of the Grant will be earned. If ALLETE's TSR performance ranks 19^th (threshold performance), 50% of the Grant will be earned. If TSR performance is below threshold, no Performance Shares will be earned. Straight-line interpolation will be used to determine earned awards based on the TSR ranking between threshold, target and superior.

TSR Rank	Perf. Level	Payout %
1		200%
2		200%
3		200%
4	Superior	200%
5		190%
6		180%
7		170%
8		160%
9		150%
10		140%
11		130%
12		120%
13		110%
14	Target	100%
15		90%
16		80%
17		70%
18		60%
19	Threshold	50%
20		—%
21		—%
22		—%
23		—%
24		—%
25		—%
26		—%
27		—%
28		—%

EX-10.(K)15

Exhibit 10(k)15

ALLETE

EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

RESTRICTED STOCK UNIT GRANT

Effective 2013

[Eligible Executive Employees]

Name

In accordance with the terms of ALLETE's Executive Long-Term Incentive Compensation Plan, as amended (the "Plan"), as determined by and through the Executive Compensation Committee of ALLETE's Board of Directors, ALLETE hereby grants to you (the "Participant") Restricted Stock Units (“RSU's”) as set forth below, payable in the form of ALLETE Common Stock, subject to the terms and conditions set forth in this Grant, including Annex A hereto, and all documents incorporated herein by reference:

Number of Restricted Stock Units:        

Date of Grant:                    

Vesting Period:                    

This Grant is made in accordance with the Plan.

Further terms and conditions of the Grant are set forth in Annex A hereto, which is an integral part of this Grant.

All terms, provisions and conditions set forth in the Plan and not set forth herein are incorporated by reference.

IN WITNESS WHEREOF, ALLETE has caused this Grant to be executed by its Chairman, President and Chief Executive Officer as of the date and year first above written.

ALLETE

By:
	Chairman, President & CEO

Attachment: Annex A

ANNEX A

TO

ALLETE

EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

RESTRICTED STOCK UNIT GRANT

The grant of restricted stock units (each , a “RSU”) under the ALLETE Executive Long-Term Incentive Compensation Plan (the “Plan”), evidenced by the Grant to which this is annexed, is subject to the following additional terms and conditions:

1.Form and Timing of Payment. Subject to the provisions hereof, each RSU will be paid in the form of one share of ALLETE common stock (each, a “Share”), plus accrued dividend equivalents, which shares will be deposited into an account for the Participant in the ALLETE Invest Direct plan. Except as otherwise provided in sections 3 and 4, below, payment will be made during the period ending sixty days after the end of the vesting period; provided, however, the Participant will not be permitted, directly or indirectly, to designate the taxable year of the distribution. Payment will be subject to withholding Shares equal in value to the Participant's income tax obligation.

2.Dividend Equivalents. The Participant will receive Dividend Equivalents in connection with the RSU's granted. Dividend Equivalents will be calculated and credited to the Participant at the time the underlying RSU's are paid. Dividend Equivalents shall be in the form of additional RSU's, which shall be added to the number of RSU's subject to the grant, and which shall equal the number of Shares (including fractional Shares) that could have been purchased on the dividend payment dates based on the closing price as reported in the consolidated transaction reporting system on that date with cash dividends that would have been paid on the RSU's, if such RSU's were Shares.

3.Payment Upon Retirement, Death or Disability; Forfeiture Upon Other Termination of Employment or Unsatisfactory Job Performance.

3.1Subject to Section 3.4 below, if during the vesting period the Participant (i) Retires, (ii) dies while employed by ALLETE or any Related Company, or (iii) becomes Disabled, a portion of the unvested RSU's subject to the Grant will vest and be paid to the Participant (or the Participant's beneficiary or estate) during the period ending sixty days after such event; provided, however, the Participant will not be permitted, directly or indirectly, to designate the taxable year of the distribution. Except as otherwise provided in Section 4, Payment pursuant to this Section 3.1 shall be prorated, after giving effect to the accumulation of Dividend Equivalents, based on the number of whole calendar months within the vesting period that had elapsed as of the date of Retirement, death or Disability in relation to the number of calendar months in the vesting period. For purposes of this calculation, the Participant will be credited with a whole month if the Participant was employed on the 15^th of the month.

3.2 Except as otherwise provided in Section 4, if during the vesting period or prior to payment of all RSU's the Participant has a Separation from Service for any reason other than those specified in Section 3.1 above, all unvested or unpaid RSU's subject to the Grant will be forfeited on the date of such Separation from Service.

3.3If during the vesting period or prior to payment of all Shares the Participant is demoted, or if ALLETE determines, in its sole discretion, that the Participant's job performance is unsatisfactory, ALLETE may cancel or amend the Participant's grant relating to any unpaid RSU's, resulting in the forfeiture of some portion or all of the Participant's unpaid RSU's.

3.4Notwithstanding anything herein to the contrary, if the Participant becomes entitled to a payment of the RSU's by reason of the Participant's Retirement and if the Participant is a Specified Employee on the date of such Retirement, payment shall not be made until the earlier of: (i) the expiration of the six-month period beginning on the date of Participant's Retirement, or (ii) the date of the Participant's death. The payment to which a Specified Employee would otherwise be entitled during this six-month period shall be paid, together with dividend equivalents that have accrued during this six-month delay, during the seventh month following the date of the Participant's Retirement, or, if earlier, the date of the Participant's death.

4.Change in Control. Upon a Change in Control, unless the Committee provides otherwise prior to the Change in Control, outstanding unvested RSU's shall be prorated (as described below) and such prorated RSU's shall immediately vest and be payable to the Participant during the period ending sixty days after the Change in Control. The RSU's will not be subject to proration and immediately vest, however, if and to the extent that the Grant is, in connection with the Change in Control, fully assumed by the successor corporation or parent thereof; in such case, the RSU's shall be prorated and immediately vest upon a Participant's termination of employment by the successor corporation for reasons other than cause within 18 months following the Change in Control and be payable to the Participant during the period ending sixty days after the termination of employment. Any payment on account of or in connection with a Change in Control will be prorated, after giving effect to the accumulation of Dividend Equivalents, based on the number of whole calendar months within the three-year vesting period that had elapsed as of the date of the Change in Control or termination of employment, as applicable, in relation to the number of calendar months in the three-year vesting period. For purposes of this calculation, the Participant will be credited with a whole month if the Participant was employed on the 15^th of the month. In no event will the Participant be permitted, directly or indirectly, to designate the taxable year of the distribution on account of or in connection with a Change in Control.

5.Compensation Recovery Policy. The Grant is subject to the terms of any compensation recovery policy or policies established by ALLETE as may be amended from time to time (“Compensation Recovery Policy”). ALLETE hereby incorporates into the Grant the terms of the Compensation Recovery Policy.

6. Section 409A Compliance. To the extent that any provision of the Grant would cause a conflict with the requirements of Section 409A or would cause the administration of the Grant to fail to satisfy Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. Nothing herein shall be construed as a guarantee of any particular tax treatment.

7. Ratification of Actions. By receiving the Grant or other benefit under the Plan, the Participant and each person claiming under or through Participant shall be conclusively deemed to have indicated the Participant's acceptance and ratification of, and consent to, any action taken under the Plan or the Grant by ALLETE, the Board, or the Committee.

8.Notices. Any notice hereunder to ALLETE shall be addressed to ALLETE, 30 West Superior Street, Duluth, Minnesota 55802, Attention: Manager - Compensation and Benefits, Human Resources, and any notice hereunder to the Participant shall be directed to the Participant's address as indicated by ALLETE's records, subject to the right of either party to designate at any time hereafter in writing some other address.

9.Governing Law and Severability. To the extent not preempted by the Federal law, the Grant will be governed by and construed in accordance with the laws of the State of Minnesota, without regard to its conflicts of law provisions. In the event any provision of the Grant shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Grant, and the Grant shall be construed and enforced as if the illegal or invalid provision had not been included.

10.Definitions. Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan. The following definitions apply to the Grant and this Annex A:

10.1“Change in Control” means the earliest of:

(i) the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires ownership of stock of the Company that, together with stock previously held by the acquirer, constitutes more than fifty (50%) percent of the total fair market value or total voting power of Company stock. If any one Person, or more than one Person acting as a group, is considered to own more than fifty (50%) percent of the total fair market value or total voting power of Company stock, the acquisition of additional stock by the same Person or Persons acting as a group does not cause a Change in Control. An increase in the percentage of stock owned by any one Person, or Persons acting as a group, as a result of a transaction in which Company acquires its stock in exchange for property, is treated as an acquisition of stock;

(ii) the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) ownership of Company stock possessing at least thirty (30%) percent of the total voting power of Company stock;

(iii) the date a majority of the members of the Company's board of directors is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of appointment or election; or

(iv) the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) assets from the Company that have a total gross fair market value equal to at least forty (40%) percent of the total gross fair market value of all the Company's assets immediately prior to the acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the corporation's assets, or the value of the assets being disposed of, without regard to any liabilities associated with these assets.

In determining whether a Change in Control occurs, the attribution rules of Code section 318 apply to determine stock ownership. The stock underlying a vested option is treated as owned by the individual who holds the vested option, and the stock underlying an unvested option is not treated as owned by the individual who holds the unvested option. The term “Person” used in this definition means any individual, corporation (including any non-profit corporation), general, limited or limited liability partnership, limited liability company, joint venture, estate, trust, firm, association, organization or other entity or any governmental or quasi-governmental authority, organization, agency or body.

10.2“Code” means the Internal Revenue Code of 1986, as it may be amended from time to time

10.3“Disability” or “Disabled” means a physical or mental condition in which the Participant is:

i. unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months;

ii. by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under the Employer's accident and health plan;

iii. determined to be totally disabled by the Social Security Administration; or

iv. disabled pursuant to an Employer-sponsored disability insurance arrangement provided that the definition of disability applied under such disability insurance program complies with the foregoing definition of Disability.

10.4“Related Company” means the ALLETE, Inc. and all persons with whom the ALLETE, Inc. would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.

10.5“Retirement” or “Retires” means Separation from Service, for reasons other than death or Disability, on or after attaining normal retirement age or early retirement age as defined in the most applicable qualified retirement plan sponsored by the Related Company that employed the Participant immediately preceding the Separation from Service, without regard to whether the Participant is a participant in such plan, or if the employer Related Company does not sponsor such retirement plan, on or after attaining Normal Retirement Age or Early Retirement Age as defined in the ALLETE and Affiliated Companies Retirement Plan A, without regard to whether the Participant is a participant under the ALLETE and Affiliated Companies Retirement Plan A.

10.6 “Section 409A”means Section 409A of the Code and Treasury Regulations section 1.409A-1 et seq., as they both may be amended from time to time, or other guidance issued by the Treasury Department and Internal Revenue Service thereunder.

10.7“Separation from Service” means that the Participant terminates employment within the meaning of Treasury Regulations section 1.409A-1(h) and other applicable guidance with all Related Companies. Whether a termination of employment has occurred is determined under the facts and circumstances, and a termination of employment shall occur if all Related Companies and the Participant reasonably anticipate that no further services shall be performed after a certain date or that the level of bona fide services the Participant shall perform after such date (as an employee or an independent contractor) shall permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Related Companies if the Participant has been providing services to the Related Companies less than 36 months). A Participant shall not be considered to separate from service during a bona fide leave of absence for less than six (6) months or longer if the Participant retains a right to reemployment with any Related Company by contract or statute. With respect to disability leave, a Participant shall not be considered to separate from service for 29 months unless the Participant otherwise terminates employment or is terminated by all Related Companies.

10.8“Specified Employee” means an Participant who is subject to the six-month delay rule described in Code section 409A(2)(B)(i), determined in accordance with guidelines adopted by the Board from time to time as permitted by Section 409A of the Code and Treasury Regulations section 1.409A-1 et seq., as they both may be amended from time to time, and other guidance issued by the Treasury Department and Internal Revenue Service thereunder.

EX-10.(N)5

Exhibit 10(n)5

AMENDMENT TO THE AMENDED AND RESTATED

ALLETE DIRECTOR COMPENSATION DEFERRAL PLAN

The Amended and Restated ALLETE Director Compensation Deferral Plan, dated effective January 1, 1990, is amended as follows:

1. Effective July 24, 2012, Section 5.1 is amended to delete the following:

Any annuity provided under this section shall be calculated using a 7.5% interest rate, or such other rate as approved by the Board. Notwithstanding the foregoing, annuities under this section shall be calculated using an 8% interest rate in any circumstance in which one of the following conditions applies: (i) the Director left service prior to January 1, 2007; or (ii) the Director provided official notice of retirement to the Company prior to January 1, 2007 with an effective retirement date on or before April 1, 2007.

2. Effective July 24, 2012, Section 5.1 is further amended to add the following:

Any annuity provided in this section shall be calculated by crediting to or debiting from the Deferral Account all notional gains and losses associated with the investment funds selected by the Director from among the options provided by the Company until all amounts credited to Deferral Account have been distributed.

ALLETE, Inc.

By: /s/ Alan R. Hodnik

Alan R. Hodnik

Chairman, President & Chief Executive Officer

ATTEST:

By: /s/ Deborah A. Amberg

Deborah A. Amberg

SeniorVice President, General Counsel & Secretary

EX-10.(O)2

Exhibit 10(o)2

ALLETE, INC.

AMENDED AND RESTATED

NON-EMPLOYEE DIRECTOR COMPENSATION DEFERRAL PLAN II

Effective July 24, 2012

TABLE OF CONTENTS
					Page
ARTICLE 1			Establishment and Purpose............................................................		1
ARTICLE 2			Administration...............................................................................		1
	2.1	Administrator.............................................................................................			1
	2.2	Duties........................................................................................................			1
	2.3	Agents........................................................................................................			1
	2.4	Binding Effect of Decisions......................................................................			2
	2.5	Company Information...............................................................................			2
ARTICLE 3			Participation...................................................................................		2
ARTICLE 4			Deferral Elections..........................................................................		2
	4.1	Annual Deferral Election..........................................................................			2
	4.2	Initial Deferral Election.............................................................................			2
	4.3	Cancellations of Deferral Elections due to Unforeseeable Emergency.....			3
ARTICLE 5			Accounts........................................................................................		3
	5.1	Accounts...................................................................................................			3
	5.2	Cash Account.............................................................................................			3
		5.2.1		Establishment of Cash Account...................................................	3
		5.2.2		Timing of Credits to Cash Accounts...........................................	3
		5.2.3		Investments..................................................................................	3
		5.2.4		Valuation Date.............................................................................	4
	5.3	Stock Account...........................................................................................			4
		5.3.1		Establishment of Stock Account.................................................	4
		5.3.2		Credits to Stock Accounts...........................................................	4
		5.3.3		Dividend Equivalents..................................................................	4
		5.3.4		Adjustments in Case of Changes in Common Stock...................	4
ARTICLE 6			Distributions...................................................................................		5
	6.1	Distributions..............................................................................................			5
		6.1.1		Specified Year..............................................................................	5
		6.1.2		Separation from Service..............................................................	6
		6.1.3		Unforeseeable Emergency...........................................................	6
	6.2	Additional Distribution Rules...................................................................			6

		6.2.1		Medium of Payment....................................................................	6
		6.2.2		Default Time and Form of Payment............................................	6
		6.2.3		Rules Applicable to All Distributions..........................................	6
		6.2.4		Installment Payments..................................................................	7
		6.2.5		Death After Commencement of Distributions.............................	7
	6.3	Subsequent Changes in Time and Form of Payment.................................			7
ARTICLE 7			Payment Acceleration and Delay...................................................		8
	7.1	Permitted Accelerations of Payment.........................................................			8
	7.2	Permissible Distribution Delays................................................................			8
	7.3	Suspension Not Allowed...........................................................................			9
ARTICLE 8				Beneficiary Designation..............................................................	9
	8.1	Beneficiary................................................................................................			9
	8.2	No Beneficiary Designation......................................................................			9
ARTICLE 9				Claims Procedures.......................................................................	9
ARTICLE 10				Amendment or Termination........................................................	10
ARTICLE 11				Miscellaneous Provisions............................................................	10
	11.1	Unsecured General Creditor......................................................................			10
	11.2	Trust Fund.................................................................................................			10
	11.3	Section 409A Compliance.........................................................................			10
	11.4	Company's Liability..................................................................................			10
	11.5	Nonassignability........................................................................................			11
	11.6	No Right to Board Position.......................................................................			11
	11.7	Incompetency............................................................................................			11
	11.8	Furnishing Information.............................................................................			11
	11.9	Notice........................................................................................................			11
	11.10	Compliance with Government Regulations..............................................			11
	11.11	Exchange Act Exemption..........................................................................			12
	11.12	Gender and Number..................................................................................			12
	11.13	Headings....................................................................................................			12
	11.14	Applicable Law and Construction.............................................................			12
	11.15	Invalid or Unenforceable Provisions.........................................................			12
	11.16	Successors.................................................................................................			12
ARTICLE 12				Definitions...................................................................................	13

ALLETE, INC.

AMENDED AND RESTATED

NON-EMPLOYEE DIRECTOR COMPENSATION DEFERRAL PLAN II

Effective July 24, 2012

ARTICLE 1

Establishment and Purpose

This document includes the terms of the ALLETE, Inc. Amended and Restated Non-Employee Director Compensation Deferral Plan II, the purpose of which is to provide Directors an opportunity to elect to defer his or her Annual Retainer. The Plan is a successor to the ALLETE Director Compensation Deferral Plan (the “Predecessor Plan”). On December 31, 2004, the Company froze the Predecessor Plan, and on January 1, 2005, the Company established the Plan to govern amounts initially deferred after December 31, 2004 and investment earnings thereon. From January 1, 2005 to the effective date hereof, the Company operated and administered the Plan in all material respects in good faith compliance with the applicable requirements of Section 409A, the final and proposed Treasury Regulations, IRS Notice 2005-1, and all other IRS guidance. Effective January 1, 2009, the Company amended and restated the Plan in its entirety to comply with Section 409A. Effective May 1, 2009, the Company amended the Plan to expand the types of compensation that Directors may defer. Effective July 24, 2012, the Company further amends the Plan to eliminate the fixed crediting rate. Capitalized terms, unless otherwise defined herein, shall have the meaning provided in Article 12.

ARTICLE 2

Administration

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

2.2 Duties. The Administrator has the authority to construe and interpret all provisions of the Plan, to resolve any ambiguities, to adopt rules and practices concerning the administration of the Plan, to make any determinations and calculations necessary or appropriate hereunder, and, to the maximum extent permitted by Section 409A, the authority to remedy any errors, inconsistencies or omissions. The Company shall pay all expenses and liabilities incurred in connection with Plan administration.

2.3 Agents. The Administrator may engage the services of accountants, attorneys, actuaries, investment consultants, and such other professional personnel as are deemed necessary or advisable to assist in fulfilling the Administrator's responsibilities. The Administrator, the

Company and the Board may rely upon the advice, opinions or valuations of any such persons.

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

2.5 Company Information. To enable the Administrator to perform its duties, the Company shall supply full and timely information to the Administrator on all matters relating to the Annual Retainer, the Directors, the date and circumstances of a Director's Separation from Service, and other pertinent information as the Administrator may reasonably require.

ARTICLE 3

Participation

Directors may participate in the Plan. Each Plan Year, the Administrator shall notify Directors of their eligibility to participate in the Plan and defer compensation to be paid on account of services as a Director during the next Service Period.  A Director who is eligible to participate shall become a participant by completing an election form on which the Director elects to defer some or all of his or her Annual Retainer and delivering the completed form to the Company as specified in the Plan. The terms of this Plan shall continue to govern a Director's Accounts until the Accounts are paid in full.

ARTICLE 4

Deferral Elections

4.1 Annual Deferral Election. Each Plan Year, a Director may elect: (i) to defer some or all of the Director's Annual Cash Retainer, the Annual Stock Retainer, or both, attributable to the next Service Period; and (ii) to the extent permitted by this Plan, the time and form of distribution of Cash Deferrals and Stock Deferrals. Elections become irrevocable no later than the date specified by the Administrator, but in any event before the beginning of the Plan Year with which or during which occurs the Service Period to which the elections relate. A Director's election will become effective only if the forms required by the Administrator have been properly completed and signed by the Director, timely delivered to, and accepted by, the Administrator. A Director who fails to file the election before the required date will be treated as having elected not to defer any portion of the Annual Retainer for the following Service Period.

4.2 Initial Deferral Election. A Director who first becomes eligible to participate in the Plan during a Plan Year may elect to defer some or all of the Director's Annual Cash Retainer and Annual Stock Retainer by filing a signed election form with the Administrator no later than 30 days after the

Director first becomes eligible to participate in the Plan. Such election shall be effective only with respect to the Director's Annual Retainer earned after the filing of such election. The election shall become irrevocable with respect to the Service Period covered by the election on the 30th day following the date on which the Director first becomes eligible to participate in the Plan. This election relating to initial participation in the Plan is available only to Directors who do not participate in any other nonqualified deferred compensation elective account balance plans (within the meaning of Section 409A) maintained by the Company or any Related Company. If a Director whose participation in the Plan is terminated again becomes a Director, he or she may elect to

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defer pursuant to this Section only if the Director was ineligible to defer compensation in this Plan and all other Related Company elective account balance plans for the 24 months preceding the date on which the Director again became eligible to participate in this Plan.

4.3 Cancellations of Deferral Elections due to Unforeseeable Emergency. If a Director experiences an Unforeseeable Emergency, the Director may submit to the Administrator a written request to cancel Deferrals for the Service Period to satisfy the Unforeseeable Emergency. If the Administrator either approves the Director's request to cancel Deferrals for the Service Period, or approves a request for a distribution of prior Deferrals in accordance with Section 6.1.3, then effective as of the date the request is approved the Administrator shall cancel the Director's deferral elections for the remainder of the Service Period. A Director whose Deferrals are canceled in accordance with this section may elect Deferrals for the following Service Period.

ARTICLE 5

Accounts

5.1 Accounts. The Company will establish notional accounts and sub-accounts for each Director as the Administrator deems necessary or advisable from time to time. The Company will establish a Director's Accounts during the year in which the Director first elects to defer any amounts. All amounts in a Director's Accounts are fully vested at all times.

5.2 Cash Account.

5.2.1 Establishment of Cash Account. The Company shall establish and maintain a Cash Account for each Director who has elected to defer any portion of the Annual Cash Retainer. A Director's Cash Account shall be credited as appropriate for Cash Deferrals and earnings with respect to Cash Deferrals and debited for distributions from the Cash Account.

5.2.2 Timing of Credits to Cash Accounts. No later than the end of the calendar year during which the Company would otherwise have paid the Annual Cash Retainer to the Director but for the Director's deferral election, the Administrator shall credit the Director's Cash Account with an amount equal to the portion of the Annual Cash Retainer that the Director elected to defer.

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5.2.3 Investments. The Administrator may select investment funds to use for measuring notional gains and losses with respect to Cash Deferrals. The Administrator will establish, from time to time, rules and procedures for allowing each Director to designate which one or more of the selected investment funds will be used to determine the notional gains and losses credited or debited to the Director's Cash Account.

5.2.4 Valuation Date. As of each Valuation Date, each Cash Account will be adjusted to reflect the effect of notional investment gains or losses, additions, distributions, transfers and all other transactions with respect to that account since the previous Valuation Date.

5.3 Stock Account.

5.3.1 Establishment of Stock Account. The Company shall establish and maintain a Stock Account for each Director who has elected to defer any portion of the Annual Stock Retainer. A Director's Stock Account shall be credited as appropriate for Stock Deferrals and Dividend Equivalents and debited for distributions from the Stock Account. Stock Deferrals credited to a Director's Stock Account shall be used solely as a device for determining the number of shares of Common Stock to be distributed to such Director at a later time in accordance with this Plan. Stock Deferrals credited (and the Common Stock to which the Director is entitled under this Plan) shall be subject to adjustment in accordance with Section 5.3.4 of this Plan.

5.3.2 Credits to Stock Accounts. The Administrator shall credit a Director's Stock Account with Stock Deferrals as of the day on which the Annual Stock Retainer would otherwise have been paid to the Director pursuant to the Stock Plan but for the Director's deferral election. The number of Stock Deferrals credited to the Stock Account shall equal the number of shares of Common Stock that would have been issued to the Director pursuant to the Stock Plan in the absence of a deferral election.

5.3.3 Dividend Equivalents. Stock Deferrals credited to a Director's Stock Account shall be credited with Dividend Equivalents equal to cash dividends that are declared and paid on Common Stock. The Company will credit each Director's Stock Account with Dividend Equivalents as of the date that the Company pays a dividend on its Common Stock, and will convert the Dividend Equivalents into additional Stock Deferrals by dividing the amount of the Dividend Equivalents by the Fair Market Value of a share of Common Stock on that date.

5.3.4 Adjustments in Case of Changes in Common Stock. If the outstanding shares of Common Stock of the Company are increased, decreased, or exchanged for a different number or kind of shares or other securities, or if additional shares or new or different shares or other securities are distributed with respect to such shares of

Common Stock or other securities, through merger, consolidation, sale of all or substantially all of the property of the Company, reorganization or recapitalization, reclassification, stock dividend, stock split, reverse stock split, combinations of shares, rights offering, distribution of assets or other distribution with respect to

4

such shares of Common Stock or other securities or other change in the corporate structure or shares of Common Stock, the number of Stock Deferrals in a Director's Stock Account and the kind of shares that may be issued under the Plan or both shall be appropriately adjusted by the Committee. Any determination by the Committee as to any such adjustment will be final, binding, and conclusive.

ARTICLE 6

Distributions

6.1 Distributions. The Plan provides for distributions in a Specified Year, upon a Separation from Service or upon an Unforeseeable Emergency. As described in Section 6.1.1, each Plan Year a Director may elect to have all or a portion of the Cash Deferrals, Stock Deferrals, or both, attributable to the next Service Period distributed in a Specified Year. With respect to Deferrals not subject to distribution in a Specified Year, the Plan requires distribution upon Separation from Service at a time and in a form elected by the Director, or for Directors who fail to elect, at a time and in a form specified by the Plan. A Director wishing to elect a time and form of distribution upon Separation from Service must, at the time of the Director's initial Deferrals, submit a distribution election, which may provide a different time and form of distribution upon Separation from Service for Cash Deferrals and Stock Deferrals. A Director's distribution elections are irrevocable and will govern the Deferrals to which the election relates until the Deferrals covered by the election are paid in full or until subsequently changed in accordance with Section 6.3. Notwithstanding any elections by a Director, all distributions are subject to the provisions of Section 6.2.

6.1.1 Specified Year. A Director may elect to receive a distribution of Cash Deferrals and Stock Deferrals in the same or different Specified Years. The Specified Year(s) elected may be no earlier than the third Plan Year beginning after the date on which the Director initially elects to receive a distribution in a Specified Year. Except as otherwise provided in this subsection or in Section 6.3, once a Director has elected to receive a distribution of Cash Deferrals in a Specified Year, the Director may not elect to receive a distribution of Cash Deferrals in a different Specified Year and, once a Director has elected to receive a distribution of Stock Deferrals in a Specified Year, the Director may not elect to receive a distribution of Stock Deferrals in a different Specified Year. Beginning during the year preceding a Specified Year previously elected by the Director, the Director may elect to receive a distribution of future Deferrals in a later Specified Year, subject, however, to the restrictions of this subsection. All amounts distributable in a Specified Year will be

paid in a single lump sum, in the case of Cash Deferrals, or in a single distribution of Common Stock, in the case of Stock Deferrals.

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6.1.2 Separation from Service. A Director may elect to receive a distribution of Deferrals commencing upon Separation from Service or during any of the first five years following the year of the Separation from Service. A Director may elect to receive the distribution in the form of a lump sum, annual installments over a period of five (5), ten (10), or fifteen (15) years, or a combination of both a lump sum and installments. A Director may elect a different time and form of distribution upon Separation from Service for Cash Deferrals and Stock Deferrals.

6.1.3 Unforeseeable Emergency. A Director may submit a written request for a distribution on account of an Unforeseeable Emergency. Upon approval by the Administrator of a Director's request, the Director's Accounts, or that portion of the Director's Accounts deemed necessary by the Administrator to satisfy the Unforeseeable Emergency plus amounts necessary to pay taxes reasonably anticipated because of the distribution, will be distributed in a single lump sum in a manner consistent with Section 409A.

6.2 Additional Distribution Rules.

6.2.1 Medium of Payment. All amounts in a Director's Cash Account shall be paid in cash. All amounts in a Director's Stock Account shall be paid in the form of an equivalent number of whole shares of Common Stock. Fractional shares may be distributed in cash.

6.2.2 Default Time and Form of Payment. If a Director fails timely to elect a time and form of payment, the Director's Accounts will be distributed upon any Separation from Service in the form of a single lump sum payment.

6.2.3 Rules Applicable to All Distributions. Except as otherwise provided in this section, if a Director has elected to receive a distribution commencing upon a Distribution Event, or if the distribution is required upon Separation from Service, the distribution will commence between the date of the Distribution Event and the end of the year in which the Distribution Event occurs. If a Director has elected, or is required, to receive a distribution commencing upon a Distribution Event, and the Distribution Event occurs on or after October 1 of a Plan Year, the distribution may, to the extent permitted by Section 409A, commence after the Distribution Event and on or before the 15^th day of the third calendar month following the Distribution Event, even if after the end of the year during which the Distribution Event occurs; provided, however, the Director will not be permitted, directly or indirectly, to designate the taxable year of the distribution. If a Director has elected to receive a

distribution commencing during any of the first five years following a Separation from Service, the distribution will commence during the year elected by the Director. If a Director has elected to receive a distribution in a Specified Year, the distribution will occur during the Specified Year. Any distribution that complies with this section shall be deemed for all purposes to comply with the Plan requirements regarding the time and form of distributions.

6

6.2.4 Installment Payments. If a Director elects to receive distributions in annual installments, the Director's Account(s) will be paid in substantially equal installments in consecutive years over the period elected by the Director. The Director's Cash Account will be credited or debited with notional gains and losses based on the investment funds selected by the Director, from among the options provided by the Company, until all amounts credited to the Director's Cash Account have been distributed. The Director's Stock Account will continue to be credited with Dividend Equivalents pursuant to Section 5.3.3, until all amounts credited to the Director's Accounts have been distributed. Each annual installment will be paid during the Plan Year in which it is due. Any installment distribution that complies with this section shall be deemed for all purposes to comply with the Plan requirements regarding the time and form of distributions.

6.2.5 Death After Commencement of Distributions. Upon the death of a Director after distributions of the Director's Accounts have commenced, the balance of the Director's Accounts will be distributed to the Director's Beneficiary at the same times and in the same forms that the Accounts would have been distributed to the Director if the Director had survived.

6.3 Subsequent Changes in Time and Form of Payment. A Director may, in accordance with rules, procedures and forms specified from time to time by the Administrator, elect to change the time of payment or change the form in which the Director's Accounts are distributed or both, provided that: (i) the Director elects at least twelve (12) months prior to the date on which payments are otherwise scheduled to commence; (ii) the new election does not take effect for at least twelve (12) months; and (iii) with respect to changes applicable to distributions in a Specified Year or upon Separation from Service, the distributions must be deferred for at least five years from the date the distributions would otherwise have been paid, or in the case of installment payments, five years from the date the installments were scheduled to commence. For purposes of this section, distributions on account of a Specified Year are considered scheduled to commence on January 1 of the Specified Year and distributions on account of a Separation from Service are considered to commence on the date of the Separation from Service, or if the Director has elected to receive a distribution of Deferrals commencing during any of the first five years following the year of the Separation from Service, January 1 of the year elected by the Director. Any such election shall be irrevocable on the date it is filed with the Administrator unless subsequently changed pursuant to this Section.

7

ARTICLE 7

Payment Acceleration and Delay

7.1 Permitted Accelerations of Payment. Except as otherwise provided herein or permitted by Section 409A, the Plan prohibits the acceleration of the time or schedule of any payment due under the Plan.

7.1.1 Distribution in the Event of Taxation. If, for any reason, all or any portion of any benefit provided by the Plan becomes taxable to a Director because of a violation of Section 409A prior to receipt, the Director may file a written request with the Administrator for a distribution of that portion of the Plan benefit that has become taxable. Upon the grant of such a request, which grant shall not be unreasonably withheld, the Director shall receive a distribution equal to the taxable portion of the plan benefit. If the request is granted, the tax liability distribution shall be paid between the date on which the Director's request is approved and the end of the Plan Year during which the approval occurred, or if later, the 15^th day of the third calendar month following the date on which the Director's request is approved.

7.1.2 Compliance with Ethics Laws or Conflicts of Interests Laws. The Administrator may, in its sole discretion, accelerate the time or schedule of a payment to the extent necessary to avoid the violation of any applicable Federal, state, local, or foreign ethics law or conflicts of interest law as provided in Treasury Regulations section 1.409A-3(j)(4)(iii)(B).

7.1.3 Small Accounts. The Administrator may, in its sole discretion, distribute the Director's Accounts in a single lump sum provided: (i) the distribution results in the payment of the Director's entire Accounts and all other account balance plans required to be aggregated with the Director's Accounts pursuant to Section 409A and (ii) the total distribution does not exceed the applicable dollar limit under Code section 402(g)(1)(B). The Administrator shall notify the Director in writing if the Administrator exercises its discretion pursuant to this Section. Any payment to a Director pursuant to this Section must represent the complete liquidation of the Director's interest in the Plan.

7.1.4 Settlement of a Bona Fide Dispute. The Administrator may, in its sole discretion, accelerate the time or schedule of a distribution as part of a settlement of a bona fide dispute between the Director and the Company over a Director's right to a distribution provided that the distribution relates only to the Deferrals in dispute and the Company is not experiencing a downturn in financial health.

7.2 Permissible Distribution Delays. Notwithstanding anything in the Plan to the contrary, to the extent permitted by Section 409A, the Administrator may, in its sole discretion, delay distribution to a Director:

8

7.2.1 If the distribution would jeopardize the Company's ability to continue as a going concern, provided that the delayed distribution is distributed in the first calendar year in which the distribution would not have such effect.

7.2.2 If the distribution would violate Federal securities or other applicable laws, provided that the delayed distribution is distributed at the earliest date at which the Administrator reasonably anticipates that the distribution will not cause such violation.

7.2.3 If calculation of the distribution is not administratively practicable due to events beyond the control of the Director, provided that the delayed distribution is paid in the first calendar year in which the calculation of the distribution is administratively practicable.

7.3 Suspension Not Allowed. If a Director whose distributions have commenced becomes eligible again to defer compensation under any plan maintained by a Related Company, distribution of any remaining amounts in his Accounts may not be suspended.

ARTICLE 8

Beneficiary Designation

8.1 Beneficiary. Each Director shall have the right, at any time, to designate a Beneficiary(ies) (both primary as well as contingent) to whom a Director's Accounts shall be paid if a Director dies prior to complete distribution of the Accounts. Each Beneficiary designation shall be in a written form prescribed by the Administrator, and will be effective only when filed with the Administrator during the Director's lifetime. Any Beneficiary designation may be changed by a Director without the consent of the previously named Beneficiary by filing a new Beneficiary designation with the Administrator. The most recent Beneficiary designation received by the Administrator shall control the distribution of a Director's Accounts in the event of the Director's death.

8.2 No Beneficiary Designation. In the absence of an effective Beneficiary designation, or if all designated Beneficiaries predecease the Director or die prior to the complete distribution of the Director's Accounts, the Accounts shall be paid in the following order of precedence: (a) the Director's surviving spouse; (b) the Director's children (including adopted children), per stirpes; or (c) the Director's estate.

ARTICLE 9

Claims Procedures

Any Director or Beneficiary, or his or her authorized representative, may file a claim for benefits due him or her under the Plan by written request to the Company, setting forth with specificity the facts and events which give rise to the claim. The Company shall promptly respond, consistent with any legal requirements that might apply.

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ARTCILE 10

Amendment or Termination

The Company hereby reserves the right to amend, modify, orterminate the Plan at any time by action of the Board, with or without prior notice. No amendment or termination shall reduce any Director's Accounts without the written consent of the affected Director. Notwithstanding anything herein to the contrary, to the extent consistent with Section 409A, the Board may terminate the Plan and distribute to each Director the amount in his or her Accounts in a lump sum; provided that all distributions (i) commence no earlier than the date that is twelve (12) months following the termination date (or any earlier date that would comply with Section 409A) and (ii) are completed by the date that is twenty-four (24) months following the termination date (or any later date that would comply with Section 409A).  In addition, distributions may be accelerated upon a Plan termination as provided above only if, to the extent required under Section 409A, (i) all other nonqualified deferred compensation “account balance plans” (within the meaning of Section 409A), in which any Director participates are terminated along with the Plan, and (ii) the Company does not adopt any new nonqualified deferred compensation “account balance plan” (within the meaning of Section 409A), for three years following the date of Plan termination.

ARTICLE 11

Miscellaneous Provisions

11.1 Unsecured General Creditor. Directors and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Company. Any and all of the Company's assets shall be, and remain, the general, unpledged unrestricted assets of the Company. The Company's obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay money in the future.

11.2 Trust Fund. At its discretion, the Company may establish a Trust, with such trustees as the Company may approve, for the purpose of providing for the distribution of benefits owed under this Plan. The Trust's assets shall be held for distribution of all the Company's general creditors in the event of insolvency or bankruptcy. To the extent any Plan benefits are paid from any such Trust, the Company shall have no further obligations to pay them. If not paid from the Trust, such benefits shall remain the obligation of the Company.

11.3 Section 409A Compliance. All provisions of the Plan shall be interpreted and administered to the extent possible in a manner consistent with Section 409A. Tothe extent that any provision of the Plan would cause a conflict with the requirements of Section 409A, or would cause the administration of the Plan to fail to satisfy Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. Nothing herein shall be construed as a guarantee of any particular tax treatment to a Director.

11.4 Company's Liability. The Company's liability for the distribution of benefits shall be defined only by the Plan. The Company shall have no obligation to a Director except as expressly provided in the Plan.

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11.5 Nonassignability. Neither a Director nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate, alienate or convey in advance of actual receipt, the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are expressly declared to be, unassignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Director or any other person, be transferable by operation of law in the event of a Director's or any other person's bankruptcy or insolvency or be transferable to a spouse as a result of a property settlement or otherwise.

11.6 No Right to Board Position. Nothing in the Plan shall be deemed to create any obligation on the part of the Board to nominate any of its members for reelection by the Company's stockholders, nor confer upon any Director the right to remain a member of the Board for any period of time, or at any particular rate of compensation.

11.7 Incompetency. If the Administrator determines that a distribution under this Plan is to be paid to a minor, to a person declared incompetent or to a person incapable of handling the disposition of that person's property, the Administrator may direct such distribution to be paid to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Administrator may require proof of majority, competence, capacity, guardianship or status as a legal representative, as it may deem appropriate prior to distribution. Any distribution shall be for the account of the Director and the Director's Beneficiary, as the case may be, and shall completely discharge any liability for such amount.

11.8 Furnishing Information. A Director or his Beneficiary will cooperate with the Administrator by furnishing any and all information requested by the Administrator and take such other actions as may be requested in order to facilitate the administration of the Plan and the distributions hereunder.

11.9 Notice. Any notice or filing required or permitted under the Plan shall be sufficient if in writing and if (i) hand-delivered or sent by telecopy, (ii) sent by registered or certified mail, or (iii) sent by nationally-recognized overnight courier. Such notice shall be deemed given as of (i) the date of delivery if hand-delivered or sent by telecopy, (ii) as of the date shown on the postmark on the receipt for registration or certification, if delivery is by mail, or (iii) on the first business day after dispatch, if sent by nationally-recognized overnight courier.

11.10 Compliance with Government Regulations. Neither the Plan nor the Company shall be obligated to issue any shares of Common Stock pursuant to the Plan at any time unless and until all applicable requirements imposed by any federal and state securities and other laws, rules and regulations, by any regulatory agencies or by any stock exchanges upon which the Common Stock may be listed have been fully met. As a condition precedent to any issuance of shares of Common Stock and delivery of certificates evidencing such shares pursuant to the Plan, the Board or the Administrator may require a Director to take any such action and to make any such covenants,

agreements, and representations as the Board or the Administrator, as the case may be, in its discretion deems necessary or advisable to ensure compliance with such requirements. The Company shall in no event be obligated to register the shares of Common Stock deliverable under the Plan pursuant to the Securities Act of 1933, as amended, or to qualify or register such shares under any securities laws of any state upon their issuance under the Plan or at any time thereafter, or to take any other action in order to cause the issuance and delivery of such shares under the Plan

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or any subsequent offer, sale, or other transfer of such shares to comply with any such law, regulation, or requirement. Directors are responsible for complying with all applicable federal and state securities and other laws, rules, and regulations in connection with any offer, sale, or other transfer of the shares of Common Stock issued under the Plan or any interest therein including, without limitation, compliance with the registration requirements of the Securities Act of 1933 as amended (unless an exception therefrom is available) or with the provisions of Rule 144 promulgated thereunder, if applicable, or any successor provisions. Certificates for shares of Common Stock may be legended as the Administrator shall deem appropriate.

11.11 Exchange Act Exemption. It is the intent of the Company that transactions pursuant to this Plan satisfy and be interpreted in a manner that satisfies the applicable requirements of Rule 16b-3 promulgated under the Exchange Act (“Rule 16b-3”) so that, to the extent elections are timely, the crediting of Stock Deferrals and Dividend Equivalents, the distribution of shares of Common Stock and any other event with respect to Stock Deferrals under the Plan will be entitled to the benefits of Rule 16b-3 or other exemptive rules under Section 16 of the Exchange Act and will not be subjected to liability thereunder.

11.12 Gender and Number. Except when otherwise indicated by context, words in the masculine gender shall include the feminine and neuter genders, the singular shall include the plural, and the plural shall include the singular.

11.13 Headings. The headings contained in this Plan are for convenience only and will not control or affect the meaning or construction of any of the terms or provisions of this Plan.

11.14 Applicable Law and Construction. This Plan shall be governed by, construed and administered in accordance with the laws of the State of Minnesota, other than its laws respecting choice of law.

11.15 Invalid or Unenforceable Provisions. If any provision of this Plan shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof and the Administrator may elect in its sole discretion to construe such invalid or unenforceable provisions in a manner that conforms to applicable law or as if such provisions, to the extent invalid or unenforceable, had not been included.

11.16 Successors. This Plan shall bind any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company, in the same manner and to the same extent that the Company would be obligated under this Plan if no succession had taken place. In the case of any transaction in which a successor would not by the

foregoing provision or by operation of law be bound by this Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the obligations of the Company and each Company under this Plan, in the same manner and to the same extent that the Company and each Company would be required to perform if no such succession had taken place.

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ARTICLE 12

Definitions

The following terms shall have the meanings set forth below:

“Account” or “Accounts” shall mean a Director's Deferral Account, Stock Account, or both, as the context so requires.

“Administrator” means the Executive Compensation Committee of the Board.

“Annual Cash Retainer” means that portion of the Director's Annual Retainer payable in cash.

“Annual Retainer” means the compensation, consisting of the Annual Cash Retainer and the Annual Stock Retainer and excluding perquisites and reimbursements, paid to a Director pursuant to the Stock Plan for service on the Board and any committee of the Board.

“Annual Stock Retainer” means that portion of a Director's Annual Retainer payable in Company Stock.

“Beneficiary” means one or more persons, trusts, estates or other entities, designated in accordance with this Plan, that are entitled to receive Plan benefits upon the death of a Director.

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

“Cash Account” means the bookkeeping account maintained by the Company for each Director that is credited with Cash Deferrals, and such other accounts or sub-accounts as the Administrator deems necessary or appropriate.

“Cash Deferral” means any portion of a Director's Annual Cash Retainer that a Director elects to defer in accordance with the Plan.

“Code” means the Internal Revenue Code of 1986, as it may be amended from time to time.

“Common Stock” means the common stock of ALLETE, Inc.

“Company” means ALLETE, Inc., a Minnesota Corporation, and any successor to all, or substantially all, of the Company's assets or business.

“Deferrals” means the Cash Deferrals, Stock Deferrals, or both, that a Director elects to defer in accordance with the Plan, as the context so requires.

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“Director” means a member of the Board who is not an employee of any Related Company.

“Distribution Event” means a Specified Year, a Separation from Service or the Administrator's determination regarding the occurrence of an Unforeseeable Emergency.

“Dividend Equivalent” means the amount of cash dividends or other cash distributions paid by the Company on that number of shares of Common Stock equal to the number of Stock Deferrals credited to a Director's Stock Account as of the applicable record date for the dividend or other distribution, and which shall be credited in the form of additional Stock Deferrals to the Director's Stock Account, as provided in Section 5.3.3.

“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time.

“Fair Market Value” means the closing sale price as reported in the composite reporting system or, if there is no such sale on the relevant date, then on the last previous day on which a sale was reported.

“IRS” means the Internal Revenue Service.

“Plan” means the ALLETE, Inc. Amended and Restated Non-Employee Director Compensation Deferral Plan II, as amended from time to time.

“Plan Year” means a period beginning on January 1 of each calendar year and continuing through December 31 of such calendar year.

“Related Company” means the Company and all persons with whom the Company would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.

“Section 409A” means section 409A of the Code (and any successor provision), and regulations and other guidance issued by the Treasury Department and Internal Revenue Service thereunder.

“Separation from Service” means that the Director ceases to perform services as a Director and the Company does not then anticipate that the Director will continue to perform services in any capacity for any Related Company.

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

“Specified Year” means the year specified by a Director as the year in which the Director will receive a distribution payment of all or a portion of his Account(s). The Specified Year must be at least two years after the year the Annual Retainer would have been paid but for the Director's deferral election.

“Stock Account” means the bookkeeping Account maintained by the Company for each Director that is credited with any Stock Deferrals and Dividend Equivalents with respect to such Stock Deferrals, and such other accounts or sub-accounts as the Administrator deems necessary or appropriate.

“Stock Deferral” means a non-voting unit of measurement, which is deemed solely for bookkeeping purposes under this Plan to be equivalent to one outstanding share of Common Stock. No Director shall be entitled to any voting or other stockholder rights with respect to Stock Deferrals credited under this Plan.

“Stock Plan” means the ALLETE Director Stock Plan, dated May 9, 1995, as amended, or any predecessor or successor plan.

“Trust” means one or more trusts established pursuant to the ALLETE, Inc. Non-Employee Director Compensation Trust Agreement, effective October 11, 2004, between the Company and the trustee named therein, as amended from time to time.

“Unforeseeable Emergency” means an unanticipated emergency that is caused by an event beyond the control of the Director that would result in severe financial hardship to the Director resulting from (i) an illness or accident of the Director or the Director's spouse, the Director's beneficiary, or the Director's dependent (as defined in Code section 152, without regard to Code sections 152(b)(1), (b)(2), and (d)(1)(B)), (ii) a loss of the Director's property due to casualty, or (iii) such other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Director, all as determined in the sole discretion of the Administrator.

“Valuation Date” means each day that the U.S. stock markets are open or such other dates as may be set by the Administrator from time to time.

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IN WITNESS WHEREOF, ALLETE, Inc. has caused these presents to be signed and its corporate seal to be hereunto affixed by its duly authorized officers, effective as of July 24, 2012.

ALLETE, Inc.:

/s/ Alan R. Hodnik

Alan R. Hodnik

Chairman, President & Chief Executive Officer

ATTEST:

/s/ Deborah A. Amberg

Deborah A. Amberg

Senior Vice President, General Counsel and Secretary

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EX-10.(P)2

Exhibit 10(p)2

ALLETE, INC. AMENDED AND RESTATED

DIRECTOR COMPENSATION TRUST AGREEMENT

Effective December 15, 2012

ALLETE, INC. AMENDED AND RESTATED

DIRECTOR COMPENSATION TRUST AGREEMENT

This Grantor Trust Agreement (the “Trust Agreement”) is made this 15th day of December, 2012 by and between ALLETE, INC. (“the Company”) and WELLS FARGO BANK, NATIONAL ASSOCIATION (“the Trustee”) and hereby amends and restates the ALLETE, Inc. Director Compensation Trust Agreement (the “Original Trust Agreement”), effective October 11, 2004.

Recitals

(a) WHEREAS, the Company has adopted the nonqualified deferred compensation plans and agreements (the “Arrangements”) attached hereto as Attachment A, which may be amended from time to time;

(b) WHEREAS, the Company has incurred or expects to incur liability under the terms of such Arrangements with respect to the individuals participating in such Arrangements or beneficiaries designated by such participants who are entitled to receive benefits under the terms of such arrangements as the result of the death of the participant (collectively, the “Participants”);

(c) WHEREAS, the Company hereby establishes a Trust (the “Trust”) and shall contribute to the Trust assets that shall be held therein, subject to the claims of the Company's creditors in the event the Company becomes Insolvent, as defined in Section 3(a), until paid to Participants in such manner and at such times as specified in the Arrangements and in this Trust Agreement;

(d) WHEREAS, it is the intention of the parties that this Trust shall constitute an unfunded arrangement and shall not affect the status of the Arrangements as an unfunded plan maintained for the purpose of providing deferred compensation for a select group of non-employee directors of ALLETE, Inc.;

(e) WHEREAS, it is the intention of the parties that this Trust shall be interpreted in all respects to comply with Internal Revenue Code Section 409A (IRC Section 409A) and applicable authorities promulgated thereunder as may change from time to time; and

(f) WHEREAS, it is the intention of the Company to make contributions to the Trust to provide itself with a source of funds (“the Fund”) to assist it in satisfying its liabilities under the Arrangements.

NOW, THEREFORE, the parties do hereby establish the Trust and agree that the Trust shall be comprised, held and disposed of as follows:

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

Section 1.Establishment of The Trust

(a) The Trust is intended to be a Grantor Trust, of which the Company is the Grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended, and shall be construed accordingly.

(b) The Company shall be considered a Grantor for the purposes of the Trust.

(c) Subject to Section 1(i), the Trust hereby established is irrevocable.

(d) The Company hereby deposits with the Trustee those assets previously held under the Original Trust Agreement, which assets are listed in Attachment B hereto (the “Initial Contribution”) which shall become the principal of this Trust to be held, administered and disposed of by the Trustee as provided in this Trust Agreement.

(e) The principal of the Trust, and any earnings thereon shall be held separate and apart from other funds of the Company and shall be used exclusively for the uses and purposes of Participants and general creditors as herein set forth. Participants shall have no preferred claim on, or any beneficial ownership interest in, any assets of the Trust. Any rights created under the Arrangements and this Trust Agreement shall be unsecured contractual rights of Participants against the Company. Any assets held by the Trust will be subject to the claims of the general creditors of the Company under federal and state law in the event the Company is Insolvent, as defined in Section 3(a) herein.

(f) The Company, in its sole discretion, may at any time, or from time to time, make additional deposits of cash or other property acceptable to the Trustee in the Trust to augment the principal to be held, administered and disposed of by the Trustee as provided in this Trust Agreement. Prior to a Change in Control (as defined in Section 15) or, if earlier, a Potential Change in Control (as defined in Section 15) (a “Triggering Event,” as such term is more fully defined in Section 15), neither the Trustee nor any Participant shall have any right to compel additional deposits.

(g) In addition to the Initial Contribution, the Company shall make such other contributions as shall from time to time be authorized by due corporate action. Any such payments made by the Company may be in cash, by letter of credit or, prior to the date as of which a Triggering Event, occurs, in such property (including, without limitation, securities issued by the Company) as the Company may determine. The Company shall keep accurate books and records with respect to the interest of each Executive in any Arrangement and shall provide copies of such books and records to the Trustee at any time as the Trustee shall request.

(h) Upon a Triggering Event, the Company shall, as soon as possible, but in no event longer than thirty (30) days following the occurrence of the Triggering Event, make a contribution to the Trust in an amount that is sufficient (taking into account the Trust assets, if any, resulting from prior contributions) to fund the Trust in an amount equal to no less than 100% of the Required Funding and the Expense Reserve. The Required Funding shall be equal to the amount necessary to pay each Participant the benefits to which Participants would be entitled pursuant to the terms of the Arrangements as of the date on which the Triggering Event occurred. The Expense Reserve shall

3

ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

be equal to the greater of: 1) the estimated trustee and record-keeper expenses and fees for one year or 2) fifty thousand dollars ($50,000). Annually, the Company shall recalculate the Required Funding and the Expense Reserve as of December 31 of the preceding year and, if the assets of the trust are less than the sum of the Required Funding and the Expense Reserve, the Company shall make a contribution to the Trust in an amount equal to no less than 100% of the Required Funding and the Expense Reserve.

(i) In the event a Change in Control does not occur within two years of a Potential Change in Control or, earlier if, within such two year period, the Chief Executive Officer of the Company determines that the Potential Change in Control no longer exists in accordance with Section 15(b), the Company shall have the right to recover any amounts contributed to and remaining on hand in the Trust pursuant to a payment made upon the occurrence of a Potential Change in Control in accordance with Section 1(h).

(j) At the direction of the Company, the Trustee shall establish separate subtrusts for separate Arrangements or groups of Participants covered by the Trust. At the discretion of the Company, such subtrusts may reflect a segregation of particular assets or may reflect an undivided interest in the assets of the Trust, not requiring any segregation of assets. If a Triggering Event occurs, the Trustee shall establish a separate subtrust for all then-existing Participants in the Arrangement (or, at the written direction of either the Company or the Executive Compensation Committee of the Board of Directors (the “Committee”), for each Participant in the Arrangement who is covered by the Trust). The subtrust established for all then-existing Participants upon a Triggering Event shall require segregation of particular assets. However, individual subtrusts established for each Participant may reflect an undivided interest in the assets of the subtrust for all then-existing Participants and shall not require segregation of particular assets among particular individual subtrusts. Whenever separate subtrusts are established, the then-existing assets of the Trust or affected portion thereof shall be allocated, as directed by the Committee, in proportion to the vested accrued benefits, and, then, if any assets remain, the unvested (if any) accrued benefits of the Participants affected thereby, in both instances as of the end of the month immediately preceding such allocation. With respect to any new contributions to the Trust by the Company after separate subtrusts have been established, the Company shall designate the subtrust for which such contributions are made. Except as provided in Section 5(b) herein, after separate subtrusts are established, assets allocated to one subtrust may not be utilized to provide benefits under any other subtrust until all benefits payable under such subtrust have been paid in full. Payments to general creditors in the event of the Company becoming Insolvent shall be charged against the subtrusts in proportion to their account balances, except that payment of benefits to a Participant as a general creditor shall be charged against the subtrust for that Participant.

(k) Notwithstanding the foregoing provisions or any other provision of the Arrangements, no contribution shall be required or made if such contribution would violate the provisions of IRC Section 409A and any applicable authorities promulgated thereunder.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

Section 2. Payments to Participants

(a) Prior to a Triggering Event, any distributions from the Trust shall be made by the Trustee to Participants at the direction of the Company. Prior to a Triggering Event, the entitlement of a Participant to benefits under the Arrangements shall be determined by the Committee, and any claim for such benefits shall be considered and reviewed under the procedures set out in the Arrangements. Prior to a Triggering Event, the Company may appoint a third-party administrator (“TPA”) to direct the Trustee with respect to the amount and timing of such payments. After a Triggering Event, the TPA previously appointed by the Company shall continue unless and until the Trustee shall appoint a new TPA to act on its behalf in directing the Trustee with respect to the amount and timing of payments from the Trust.

(b) The Company may direct the Trustee to make payments of benefits to Participants, or the Company may make payments of benefits directly to Participants as they become due under the terms of the Arrangements and may obtain full or partial reimbursement for such benefit payments from the Trust (or offset required contributions to the Trust) within twelve (12) months following the date such payments are made. In addition, if the principal of the Trust, and any earnings thereon, are not sufficient to make payments of benefits in accordance with the terms of the Arrangements, the Company shall make the balance of each such payment as it falls due in accordance with the Arrangements. The Trustee shall notify the Company when principal and earnings are not sufficient to make payments the Trustee has been directed to make by the Company, the Committee, or the TPA. Nothing in this Agreement shall relieve the Company of its liabilities to pay benefits due under the Arrangements except to the extent such liabilities are met by application of assets of the Trust.

(c) The Company shall deliver to the Trustee a schedule of benefits, to include state and federal tax withholding guidelines, due under the Arrangements on an annual basis. Immediately, as soon as administratively practicable, after a Potential Change in Control and before a Change in Control, the Company shall deliver to the Trustee an updated schedule of benefits due under the Arrangements. After a Triggering Event, the Trustee shall pay benefits (unless Company pays pursuant to Section 2(b)) due in accordance with such schedule. After a Triggering Event, the TPA shall make the determination of benefits due to Participants and shall provide the Trustee with an updated schedule, to include state and federal tax withholding guidelines, of benefits due; provided however, a Participant may make application to the Trustee for an independent decision as to the amount or form of their benefits due under the Arrangements. In making any determination required or permitted to be made by the Trustee under this Section, the Trustee shall, in each such case, reach its own independent determination, in its absolute and sole discretion, as to the Participant's entitlement to a payment hereunder. In making its determination, the Trustee may consult with and make such inquiries of such persons, including the Participant, the Company, legal counsel, actuaries or other persons, as the Trustee may reasonably deem necessary. Any reasonable costs incurred by the Trustee in arriving at its determination shall be reimbursed by the Company and, to the extent not paid by the Company within a reasonable time, shall be charged to the Trust. The Company waives any right to contest any amount paid over by the Trustee hereunder pursuant to a good faith determination made by the Trustee notwithstanding any claim by or on behalf of the Company (absent a legal violation or manifest abuse of discretion by the Trustee) that such payments should not be made.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(d) The Trustee agrees that it will not itself institute any action at law or at equity, whether in the nature of an accounting, interpleading action, request for a declaratory judgment or otherwise, requesting a court or administrative or quasi-judicial body to make the determination required to be made by the Trustee under this Section 2 in the place and stead of the Trustee. The Trustee may (and, if necessary or appropriate, shall) institute an action to collect a contribution due the Trust following a Triggering Event or in the event that the Trust should ever experience a short-fall in the amount of assets necessary to make payments pursuant to the terms of the Arrangements.

Section 3. Trustee Responsibility Regarding Payments

To The Trust Beneficiary When The Company Is Insolvent

(a) The Trustee shall cease payment of benefits to Participants if the Company is Insolvent. The Company shall be considered “Insolvent” for purposes of this Trust Agreement if (i) the Company is unable to pay its debts as they become due, or (ii) the Company is subject to a pending proceeding as a debtor under the United States Bankruptcy Code.

(b) At all times during the continuance of this Trust, the principal and income of the Trust shall be subject to claims of general unsecured creditors of the Company under federal and state law as set forth below.

(1) The Board of Directors and the Chief Executive Officer of the Company shall have the duty to inform the Trustee in writing that the Company is Insolvent. If a person claiming to be a creditor of the Company alleges in writing to the Trustee that the Company has become Insolvent, the Trustee shall determine whether the Company is Insolvent and, pending such determination, the Trustee shall discontinue payment of benefits to Participants.

(2) Unless the Trustee has actual knowledge that the Company is Insolvent, or has received notice from the Company or a person claiming to be a creditor alleging that the Company is Insolvent, the Trustee shall have no duty to inquire whether the Company is Insolvent. The Trustee may in all events rely on such evidence concerning the Company's solvency as may be furnished to the Trustee and that provides the Trustee with a reasonable basis for making a determination concerning the Company's solvency.

(3) If at any time the Trustee has determined that the Company is Insolvent, the Trustee shall discontinue payments to Participants and shall hold the assets of the Trust for the benefit of the Company's general creditors. Nothing in this Trust Agreement shall in any way diminish any rights of Participants to pursue their rights as general creditors of the Company with respect to benefits due under the Arrangements or otherwise.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(4) The Trustee shall resume the payment of benefits to Participants in accordance with Section 2 of this Trust Agreement only after the Trustee has determined that the Company is not Insolvent (or is no longer Insolvent).

(c) Provided that there are sufficient assets, if the Trustee discontinues the payment of benefits from the Trust pursuant to Section 3(b) hereof and subsequently resumes such payments, the first payment following such discontinuance shall include the aggregate amount of all payments due to Participants under the terms of the Arrangements for the period of such discontinuance, less the aggregate amount of any payments made to Participants by the Company in lieu of the payments provided for hereunder during any such period of discontinuance.

Section 4. Payments When a Short-Fall of The Trust Assets Occurs

(a) If there are not sufficient assets for the payment of current and expected future benefits pursuant to Section 2 or Section 3(c) hereof and the Company does not otherwise make such payments within a reasonable time after demand from the Trustee, the Trustee shall allocate the Trust assets among the Participants of a particular subtrust in the following order of priority:

(1) vested Participants; and

(2) non-vested Participants.

(b) Within each category, assets shall be allocated pro-rata with respect to the total present value of benefits expected for each Participant within the category, and payments due under the terms of the Arrangements to each Participant shall be made to the extent of the assets allocated to each Participant. For purposes of the foregoing, calculations of present values shall be performed within normal actuarial practice and within the most current Actuarial Standards of Practice. 

(c) Upon receipt of a contribution from the Company necessary to make up for a short-fall in the payments due, the Trustee shall resume payments to all the Participants under the Arrangements. Following a Triggering Event, the Trustee shall have the right and duty to compel a contribution to the Trust from the Company to make-up for any short-fall.

Section 5.Payments to the Company

(a) Except as provided in Section 1(i), Section 2, Section 3, Section 5(b), and Section 8 hereof, the Company shall have no right or power to direct the Trustee to return to the Company or to divert to others any of the Trust assets before all payment of benefits have been made to Participants pursuant to the terms of the Arrangements.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(b) In the event that the Company, prior to a Triggering Event, or the Trustee in its sole and absolute discretion, after a Triggering Event, determines that the Trust assets exceed one-hundred twenty-five percent (125%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements and that all of the subtrusts' assets exceed one-hundred percent (100%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements, the Trustee, at the written direction of the Company, prior to a Triggering Event, or the Trustee in its sole and absolute discretion, after a Triggering Event, shall distribute to the Company such excess portion of Trust assets. For purposes of the foregoing,in the event that the Company, prior to a Triggering Event, or the Trustee in its sole and absolute discretion, after a Triggering Event, determines that the Trust assets in a particular subtrust exceed one-hundred percent (100%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements from such subtrust, such excess amounts may be allocated to other subtrusts whose assets are less than one-hundred percent (100%) of the anticipated benefit obligations and administrative expenses that are to be paid under the Arrangements from such subtrust.

Section 6.Investment Authority

(a) Prior to a Triggering Event, the Company shall have the right, subject to this Section, to direct the Trustee with respect to investments.

(1) The Company may direct the Trustee to segregate all or a portion of the Fund in a separate investment account or accounts and may appoint one or more investment managers and/or an investment committee established by the Company to direct the investment and reinvestment of each such investment account or accounts. In such event, the Company shall notify the Trustee of the appointment of each such investment manager and/or investment committee. No such investment manager shall be related, directly or indirectly, to the Company, but members of the investment committee may be employees of the Company.

(2) Thereafter, until a Triggering Event, the Trustee shall make every sale or investment with respect to such investment account as directed in writing by the investment manager or investment committee. It shall be the duty of the Trustee to act strictly in accordance with each direction. The Trustee shall be under no duty to question any such direction of the investment manager or investment committee, to review any securities or other property held in such investment account or accounts acquired by it pursuant to such directions or to make any recommendations to the investment managers or investment committee with respect to such securities or other property.

(3) Notwithstanding the foregoing, the Trustee, without obtaining prior approval or direction from an investment manager or investment committee, shall invest cash balances held by it from time to time in short term cash equivalents including, but not limited to, through the medium of any short term common, collective, or commingled trust fund established and maintained by the Trustee subject to the instrument establishing such trust fund, U.S. Treasury Bills, commercial paper (including such forms of commercial paper as may be available through the Trustee's Trust Department), certificates of deposit (including certificates issued by the Trustee in its separate corporate capacity), and similar type

8

ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

securities, with a maturity not to exceed one year; and, furthermore, sell such short term investments as may be necessary to carry out the instructions of an investment manager or investment committee regarding more permanent type investment and directed distributions.

(4) The Trustee shall neither be liable nor responsible for any loss resulting to the Fund by reason of any sale or purchase of an investment directed by an investment manager or investment committee nor by reason of the failure to take any action with respect to any investment which was acquired pursuant to any such direction in the absence of further directions of such investment manager or investment committee.

a. Notwithstanding anything in this Agreement to the contrary, the Trustee shall be indemnified and saved harmless by the Company from and against any and all personal liability to which the Trustee may be subjected by carrying out any directions of an investment manager or investment committee issued pursuant hereto or for failure to act in the absence of directions of the investment manager or investment committee including all expenses reasonably incurred in its defense in the event the Company fails to provide such defense; provided, however, the Trustee shall not be so indemnified if it participates knowingly in, or knowingly undertakes to conceal, an act or omission of an investment manager or investment committee, having actual knowledge that such act or omission is a breach of a fiduciary duty; provided further, however, that the Trustee shall not be deemed to have knowingly participated in or knowingly undertaken to conceal an act or omission of an investment manager or investment committee with knowledge that such act or omission was a breach of fiduciary duty by merely complying with directions of an investment manager or investment committee or for failure to act in the absence of directions of an investment manager or investment committee. The Trustee may rely upon any order, certificate, notice, direction or other documentary confirmation purporting to have been issued by the investment manager or investment committee which the Trustee believes to be genuine and to have been issued by the investment manager or investment committee. The Trustee shall not be charged with knowledge of the termination of the appointment of any investment manager or investment committee until it receives written notice thereof from the Company.

b. The Company, prior to a Triggering Event, may direct the Trustee to invest in securities (including stock and the rights to acquire stock) or obligations issued by the Company.

9

ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

c. All rights associated with respect to any investment held by the Trust, including but not limited to, exercising or voting of proxies, in person or by general or limited proxy, shall be in accordance with and as directed in writing by the Company or its authorized representative.

(b) Following a Triggering Event, the Trustee shall have the power in investing and reinvesting the Fund in its sole discretion, unless otherwise provided below:

(1) To invest and reinvest in any readily marketable common and preferred stocks (including any stock or security of the Company), bonds, notes, debentures (including convertible stocks and securities but not including any stock or security of the Trustee other than a de minimus amount held in a mutual fund), certificates of deposit or demand or time deposits (including any such deposits with the Trustee), limited partnerships or limited liability companies, private placements and shares of investment companies, and mutual funds, without being limited to the classes or property in which the Trustees are authorized to invest by any law or any rule of court of any state and without regard to the proportion any such property may bear to the entire amount of the Fund. Without limitation, the Trustee may invest the Trust in any investment company (including any investment company or companies for which Wells Fargo Bank, N.A. or an affiliated company acts as the investment advisor {“Special Investment Companies”}) or, any insurance contract or contracts issued by an insurance company or companies in each case as the Trustee may determine provided that the Trustee may in its sole discretion keep such portion of the Trust in cash or cash balances for such reasonable periods as may from time to time be deemed advisable pending investment or in order to meet contemplated payments of benefits;

(2) To invest and reinvest all or any portion of the Fund collectively through the medium of any proprietary mutual fund that may be established and maintained by the Trustee;

(3) To commingle for investment purposes all or any portion of the Fund with assets of any other similar trust or trusts established by the Company with the Trustee for the purpose of safeguarding deferred compensation or retirement income benefits of its employees and/or directors;

(4) To retain any property at any time received by the Trustee;

(5) To sell or exchange any property held by it at public or private sale, for cash or on credit, to grant and exercise options for the purchase or exchange thereof, to exercise all conversion or subscription rights pertaining to any such property and to enter into any covenant or agreement to purchase any property in the future;

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(6) To participate in any plan of reorganization, consolidation, merger, combination, liquidation or other similar plan relating to property held by it and to consent to or oppose any such plan or any action thereunder or any contract, lease, mortgage, purchase, sale or other action by any person;

(7) To deposit any property held by it with any protective, reorganization or similar committee, to delegate discretionary power thereto, and to pay part of the expenses and compensation thereof for any assessments levied with respect to any such property to be deposited;

(8) To extend the time of payment of any obligation held by it;

(9) To hold uninvested any moneys received by it, without liability for interest thereon, but only in anticipation of payments due for investments, reinvestments, expenses or disbursements;

(10) To exercise all voting or other rights, at the direction of the Company, with respect to any property held by it and to grant proxies, discretionary or otherwise;

(11) For the purposes of the Trust, to borrow money from others, to issue its promissory note or notes therefor, and to secure the repayment thereof by pledging any property held by it;

(12) To employ suitable contractors and counsel, who may be counsel to the Company or to the Trustee, and to pay their reasonable expenses and compensation from the Fund to the extent not paid by the Company;

(13) To register investments in its own name or in the name of a nominee; and to combine certificates representing securities with certificates of the same issue held by it in other fiduciary capacities or to deposit or to arrange for the deposit of such securities with any depository, even though, when so deposited, such securities may be held in the name of the nominee of such depository with other securities deposited therewith by other persons, or to deposit or to arrange for the deposit of any securities issued or guaranteed by the United States government, or any agency or instrumentality thereof, including securities evidenced by book entries rather than by certificates, with the United States Department of the Treasury or a Federal Reserve Bank, even though, when so deposited, such securities may not be held separate from securities deposited therein by other persons; provided, however, that no securities held in the Fund shall be deposited with the United States Department of the Treasury or a Federal Reserve Bank or other depository in the same account as any individual property of the Trustee, and provided, further, that the books and records of the Trustee shall at all times show that all such securities are part of the Trust Fund;

(14) To settle, compromise or submit to arbitration any claims, debts or damages due or owing to or from the Trust, respectively, to commence or defend suits or legal proceedings to protect any interest of the Trust, and to represent the Trust in all suits or legal proceedings in any court or before any other body or tribunal; provided, however, that the Trustee shall not be required to take any such action unless it shall have been indemnified by the Company to its reasonable satisfaction against liability or expenses it might incur therefrom;

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(15) Subject to Section 7, to hold and retain policies of life insurance, annuity contracts, and other property of any kind which policies are contributed to the Trust by the Company or any subsidiary of the Company or are purchased by the Trustee;

(16) To hold any other class of assets which may be contributed by the Company and     that is deemed reasonable by the Trustee, unless expressly prohibited herein;

(17) To loan any securities at any time held by it to brokers or dealers upon such security as may be deemed advisable, and during the terms of any such loan to permit the loaned securities to be transferred into the name of and voted by the borrower or others; and

(18) Generally, to do all acts, whether or not expressly authorized, that the Trustee may deem necessary or desirable for the protection of the Fund.

(c) Following a Triggering Event, the Trustee shall have the sole and absolute discretion in the management of the Trust assets and shall have all the powers set forth under this Section 6(c). In investing the Trust assets, the Trustee shall consider:

(1) the needs of the Arrangements;

(2) the need for matching of the Trust assets with the liabilities of the Arrangements; and

(3) the duty of the Trustee to act solely in the best interests of the Participants.

(d) In no event may the Trustee invest in offshore securities or any other investments prohibited by IRC Section 409A.

(e) The Trustee shall have the right, in its sole discretion, to delegate its investment responsibility to an investment manager who may be an affiliate of the Trustee. In the event the Trustee shall exercise this right, the Trustee shall remain, at all times responsible for the acts of an investment manager. The Trustee shall have the right to purchase an insurance policy or an annuity to fund the benefits of the Arrangements.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(f) The Company shall have the right at any time to substitute assets (other than securities issued by the Trustee or the Company) of equal fair market value for any asset held by the Trust, provided, however, that no such substitution shall be permitted unless the Trustee determines that the fair market values of the substituted assets are equal (which determination shall be made on a timely basis).

Section 7.Insurance Contracts

(a) To the extent that the Trustee is directed by the Company prior to a Triggering Event to invest part or all of the Trust Fund in insurance contracts, the type and amount thereof shall be specified by the Company. The Trustee shall be under no duty to make inquiry as to the propriety of the type or amount so specified.

(b) Each insurance contract issued shall provide that the Trustee shall be the owner thereof with the power to exercise all rights, privileges, options and elections granted by or permitted under such contract or under the rules of the insurer. The exercise by the Trustee of any incidents of ownership under any contract shall, prior to a Triggering Event, be subject to the direction of the Company. After a Triggering Event, the Trustee shall have all such rights.

(c) The Trustee shall have no power to name a beneficiary of the policy other than the Trust, to assign the policy (as distinct from conversion of the policy to a different form) other than to a successor Trustee, or to loan to any person the proceeds of any borrowing against an insurance policy held in the Trust Fund.

(d) No insurer shall be deemed to be a party to the Trust and an insurer's obligations shall be measured and determined solely by the terms of contracts and other agreements executed by the insurer.

Section 8.Disposition of Income

(a) Prior to a Triggering Event, all income received by the Trust, net of expenses and taxes, may be returned to the Company or accumulated and reinvested within the Trust at the direction of the Company.

(b) Following a Triggering Event, all income received by the Trust, net of expenses and taxes payable by the Trust, shall be accumulated and reinvested within the Trust.

Section 9.Accounting by The Trustee

The Trustee shall keep accurate and detailed records of all investments, receipts, disbursements, and all other transactions required to be made, including such specific records as shall be agreed upon in writing between the Company and the Trustee. Within forty-five (45) days following the close of each calendar year and within forty-five (45) days after the removal or resignation of the Trustee, the Trustee shall deliver to the Company a written account of its administration of the Trust during such year or during the period from the close of the last preceding year to the date of such removal or resignation setting forth all investments, receipts, disbursements and other transactions effected by it, including a description of all securities and investments purchased and sold with the cost or net proceeds of such purchases or sales

13

ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(accrued interest paid or receivable being shown separately), and showing all cash, securities and other property held in the Trust at the end of such year or as of the date of such removal or resignation, as the case may be. The Company may approve such account by an instrument in writing delivered to the Trustee. In the absence of the Company's filing with the Trustee objections to any such account within one hundred and eighty (180) days after its receipt, the Company shall be deemed to have so approved such account. In such case, or upon the written approval by the Company of any such account, the Trustee shall, to the extent permitted by law, be discharged from all liability to the Company for its acts or failures to act described by such account. The foregoing, however, shall not preclude the Trustee from having its accounting settled by a court of competent jurisdiction. The Trustee shall be entitled to hold and to commingle the assets of the Trust in one Fund for investment purposes but at the direction of the Company prior to a Change in Control, the Trustee shall create one or more sub-accounts.

Section 10.Responsibility of The Trustee

(a) The Trustee shall act with the care, skill, prudence and diligence under the circumstances then prevailing that a prudent person acting in like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, provided, however, that the Trustee shall incur no liability to any person for any action taken pursuant to a direction, request or approval given by the Company which is contemplated by, and in conformity with, the terms of the Arrangements or this Trust and is given in writing by the Company. In the event of a dispute between the Company and a party, the Trustee may apply to a court of competent jurisdiction to resolve the dispute, subject, however to Section 2(d) hereof.

(b) The Company hereby indemnifies the Trustee against losses, liabilities, claims, costs and expenses in connection with the administration of the Trust, unless resulting from the negligence or willful misconduct of Trustee. The Trustee hereby indemnifies the Company against liabilities, claims, costs and expenses resulting from negligence or willful misconduct of the Trustee. The Trustee shall not be liable under any circumstances for indirect, incidental, consequential, punitive, or special damages in connection with the administration of this Trust. To the extent the Company fails to make any payment on account of an indemnity provided in this Section 10(b), in a reasonably timely manner, the Trustee may obtain payment from the Trust. If the Trustee undertakes or defends any litigation arising in connection with this Trust or to protect a Participant's rights under the Arrangements, the Company agrees to indemnify the Trustee against the Trustee's costs, reasonable expenses and liabilities (including, without limitation, attorneys' fees and expenses) relating thereto and to be primarily liable for such payments. If the Company does not pay such costs, expenses and liabilities in a reasonably timely manner, the Trustee may obtain payment from the Trust.

(c) The Trustee may consult with legal counsel (who may also be counsel for the Company generally) with respect to any of its duties or obligations hereunder.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(d) The Trustee may hire agents, accountants, actuaries, investment advisors, financial consultants or other professionals to assist it in performing any of its duties or obligations hereunder and may rely on any determinations made by such agents and information provided to it by the Company.

(e) The Trustee shall have, without exclusion, all powers conferred on the Trustee by applicable law, unless expressly provided otherwise herein.

(f) Notwithstanding any powers granted to the Trustee pursuant to this Trust Agreement or to applicable law, the Trustee shall not have any power that could give this Trust the objective of carrying on a business and dividing the gains therefrom, within the meaning of section 301.7701-2 of the Procedure and Administrative Regulations promulgated pursuant to the Internal Revenue Code.

Section 11.Compensation and Expenses of The Trustee

The Trustee's compensation shall be as agreed in writing from time to time by the Company and the Trustee. The Company shall pay all administrative expenses and the Trustee's fees and shall promptly reimburse the Trustee for any fees and expenses of its agents. If not so paid within thirty (30) days of being invoiced, the fees and expenses shall be paid from the Trust.

Section 12.Resignation and Removal of The Trustee

(a) Prior to a Triggering Event, the Trustee may resign at any time by written notice to the Committee, which shall be effective sixty (60) days after receipt of such notice unless the Committee and the Trustee agree otherwise. Following a Triggering Event, the Trustee may resign thirty-six (36) months or more after the Triggering Event by written notice to the Committee, which shall be effective sixty (60) days after receipt of such notice or upon shorter notice as the Committee and the Trustee agree. Or, following a Triggering Event, the Trustee may resign twenty-four (24) months or more after the Triggering Event if a successor Trustee has been appointed by the Committee in accordance with Section 13 or the Trustee has received written consent from a Majority of the Participants as defined in Section 15.

(b) Prior to a Triggering Event, the Trustee may be removed by the Committee on sixty (60) days written notice or upon shorter notice accepted by the Trustee. After a Triggering Event, the Trustee may be removed by the Committee with written consent from a Majority of the Participants.

(c) If the Trustee resigns following a Triggering Event and if the Committee fails to appoint a successor Trustee within a reasonable period of time following such resignation, the Trustee shall apply to a court of competent jurisdiction for the appointment of a successor Trustee which satisfies the requirements of Section 13 or for instructions.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(d) Upon resignation or removal of the Trustee and appointment of a successor Trustee, all assets shall subsequently be transferred to the successor Trustee. The transfer shall be completed within sixty (60) days after receipt of notice of resignation, removal or transfer, unless the Committee extends the time limit.

(e) If the Trustee resigns or is removed, a successor Trustee shall be appointed by the Committee, in accordance with Section 13 hereof, by the effective date of resignation or removal under paragraph(s) (a) or (b) of this section. If no such appointment has been made, the Trustee may apply to a court of competent jurisdiction for appointment of a successor or for instructions. All expenses of the Trustee in connection with the proceeding shall be allowed as administrative expenses of the Trust.

Section 13.Appointment of Successor

(a) If the Trustee resigns or is removed in accordance with Section 12 hereof, the Committee may appoint, subject to Section 12, any third party national banking association with a market capitalization exceeding $25,000,000 to replace the Trustee upon resignation or removal. The successor Trustee shall have all of the rights and powers of the former Trustee, including ownership rights in the Trust. The former Trustee shall execute any instrument necessary or reasonably requested by the Committee or the successor Trustee to evidence the transfer.

(b) The successor Trustee need not examine the records and acts of any prior Trustee and may retain or dispose of existing Trust assets, subject to Section 9 and 10 hereof. The successor Trustee shall not be responsible for and the Company shall indemnify and defend the successor Trustee from any claim or liability resulting from any action or inaction of any prior Trustee or from any other past event, or any condition existing at the time it becomes successor Trustee.

Section 14. Amendment or Termination

(a) The Board of Directors and the Trustee may amend this Trust Agreement at any time by a written instrument executed by both parties. No such amendment shall conflict with the terms of the Arrangements or shall make the Trust revocable, except as provided in Section 14(c). No amendment shall cause the principal and income of the Trust to fail to be subject to claims of the Company's general unsecured creditors under federal and state law in the event the Company becomes Insolvent as defined in Section 3(a). No amendment may violate the provisions of IRC Section 409A.

(b) Following a Triggering Event, the Trust shall not terminate until the date on which Participants have received all of the benefits due to them under the terms and conditions of the Arrangements, except as provided in Section 14(c). Notwithstanding the foregoing, after individual subtrusts have been created, an individual subtrust may be terminated on the date on which all Participants have received all of the benefits due to them under the terms and conditions of the Arrangements covered by such subtrust.

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(c) Upon written approval of all Participants entitled to payment of benefits pursuant to the terms of the Arrangements, the Company may terminate this Trust prior to the time all benefit payments under the Arrangements have been made. All assets in the Trust at termination shall be returned to the Company.

Section 15.Definitions

(a) For purposes of this Trust, the following terms shall be defined as set forth below:

(1) “Potential Change in Control” shall mean:

i. the purchase or other acquisition by any person, entity or group of persons, within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (“Act”), or any comparable successor provisions, other than the trustee of any other trust or plan maintained for the benefit of employees of the Company, of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Act) of 20% or more of either the outstanding shares of common stock or the combined voting power of the Company's then outstanding voting securities entitled to vote generally;

ii. the announcement by any person of an intention to take actions which might reasonably result in a business combination between the Company and an entity which has a market capitalization equal to or greater than 80% of the Company;

iii. the issuance of a proxy statement by the Company with respect to an election of directors for which there is proposed one or more directors who are not recommended by the Board of Directors of the Company or its nominating committee, where the election of such proposed director or directors would result in a Change in Control as defined in Section 15(a)(2)(iii); or

iv. submission to the individuals who, as of the date hereof, constitute the Board of Directors, of nominations which, if approved, would change the Executive Officer configuration of the Company (at the Executive Vice President level and above) by 50% or more.

(2) “Change in Control” shall mean the earliest of:

i. the date any one person, or more than one person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires ownership of stock of the Company that, together with stock previously held by the acquirer, constitutes more than fifty (50%) percent of the total fair market value or total voting power of Company stock. If any one person, or more than one person acting as a group, is considered to own more than fifty (50%) percent of the total fair market value or total voting power of Company stock, the acquisition of additional stock by the same person or persons acting as a group does not cause a Change in Control. An increase in the percentage of stock owned by any one person, or persons acting as a group, as a result of a transaction

ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

in which Company acquires its stock in exchange for property, is treated as an acquisition of stock;

ii. the date any one person, or more than one person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that person or persons) ownership of Company stock possessing at least thirty (30%) percent of the total voting power of Company stock;

iii. the date a majority of the members of the Company's board of directors is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of appointment or election; or

iv. the date any one person, or more than one person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that person or persons) assets from the Company that have a total gross fair market value equal to at least forty (40%) percent of the total gross fair market value of all the Company's assets immediately prior to the acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the corporation's assets, or the value of the assets being disposed of, without regard to any liabilities associated with these assets.

In determining whether a Change in Control occurs, the attribution rules of Internal Revenue Code Section 318 apply to determine stock ownership. The stock underlying a vested option is treated as owned by the individual who holds the vested option, and the stock underlying an unvested option is not treated as owned by the individual who holds the unvested option.

For purposes of this Section 15(a), the individuals who, as of the date hereof, constitute the Board of Directors, by a majority vote, shall have the power to determine on the basis of information known to them (a) the number of shares beneficially owned by any person, entity or group; (b) whether there exists an agreement, arrangement or understanding with another as to matters referred to in this Section 15(a); (c) whether persons are acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)); and (d) such other matters with respect to which a determination is necessary under this Section 15(a).

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

(3)     “Majority of the Participants” shall mean Participants whose combined vested and unvested account balance(s) and accrued benefits within the Arrangements exceed 67% of the total Trust liability.

(4)     “Triggering Event” shall mean a Change in Control or, if earlier, a Potential Change in Control. However, a Potential Change in Control will cease to be a Triggering Event and the Trust Agreement will be interpreted as if no such Triggering Event had occurred, if a Change in Control does not occur within two years of the Potential Change in Control or if, within such two year period, the Chief Executive Officer of the Company determines that the Potential Change in Control no longer exists in accordance with Section 15(b).

(b) The Chief Executive Officer of the Company shall have the specific authority to determine whether a Potential Change in Control or Change in Control has transpired, and to determine whether the Potential Change in Control no longer exists under the guidance of this Section 15 and shall be required to give the Trustee notice of a Potential Change in Control, of a Change in Control, or if a Potential Change in Control no longer exists. The Trustee shall be entitled to rely upon such notice, but if the Trustee receives notice of a Potential Change in Control or Change in Control from another source, the Trustee shall make its own independent determination.

Section 16.Confidentiality

(a) This Trust Agreement and certain information relating to the Trust is “Confidential Information” pursuant to applicable federal and state law, and as such it shall be maintained in confidence and not disclosed, used or duplicated, except as described in this section. If it is necessary for the Trustee to disclose Confidential Information to a third party in order to perform the Trustee's duties hereunder, the Trustee shall disclose only such Confidential Information as is necessary for such third party to perform its obligations to the Trustee and shall, before such disclosure is made, ensure that said third party understands and agrees to the confidentiality obligations set forth herein. The Trustee and the Company shall maintain an appropriate information security program and adequate administrative and physical safeguards to prevent the unauthorized disclosure, misuse, alteration or destruction of Confidential Information, and shall inform the other party as soon as possible of any security breach or other incident involving possible unauthorized disclosure of or access to Confidential Information. Confidential Information shall be returned to the disclosing party upon request. Confidential Information does not include information that is generally known or available to the public or that is not treated as confidential by the disclosing party, provided, however, that this exception shall not apply to any publicly available information to the extent that the disclosure or sharing of the information by one or both parties is subject to any limitation, restriction, consent, or notification requirement under any applicable federal or state information privacy law or regulation. If the receiving party is required by law, according to the advice of competent counsel, to disclose

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ALLETE, Inc. Amended and Restated Director Compensation Trust Agreement

Confidential Information, the receiving party may do so without breaching this section, but shall first, if feasible and legally permissible, provide the disclosing party with prompt notice of such pending disclosure so that the disclosing party may seek a protective order or other appropriate remedy or waive compliance with the provisions of this section.

Section 17.Miscellaneous

(a) Any provision of this Trust Agreement prohibited by law shall be ineffective to the extent of any such prohibition, without invalidating the remaining provisions hereof.

(b) The Company hereby represents and warrants that all of the Arrangements have been established, maintained and administered in accordance with all applicable laws, including without limitation, ERISA. The Company hereby indemnifies and agrees to hold the Trustee harmless from all liabilities, including attorney's fees, relating to or arising out of the establishment, maintenance and administration of the Arrangements. To the extent the Company does not pay any of such liabilities in a reasonably timely manner, the Trustee may obtain payment from the Trust.

(c) Benefits payable to Participants under this Trust Agreement may not be anticipated, assigned (either at law or in equity), alienated, pledged, encumbered or subjected to attachment, garnishment, levy, execution or other legal or equitable process.

(d) This Trust Agreement shall be governed by and construed in accordance with the laws of North Carolina.

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IN WITNESS WHEREOF, this Amended and Restated Director Compensation Trust Agreement has been executed on behalf of the parties hereto on the day and year first above written.

ALLETE, INC.		WELLS FARGO BANK, NATIONAL ASSOCIATION as TRUSTEE
By:	/s/ Alan R. Hodnik	By:	/s/ Michael D. Hill
Its:	Chairman, President & Chief Executive Officer	Its:	Senior Vice President
ATTEST:		ATTEST:
By:	/s/ Deborah A. Amberg	By:	/s/ Tonya M. Inscore
Its:	Senior Vice President, General Counsel & Secretary	Its:	Senior Vice President

20

Attachment A

The following Arrangements are covered by this Trust:

ALLETE Director Compensation Deferral Plan

ALLETE Non-Employee Director Compensation Deferral Plan II

21

Attachment B

22

EX-12

Exhibit 12

ALLETE

Computation of Ratios of Earnings to Fixed Charges (Unaudited)

Year Ended December 31,		2012		2011		2010		2009		2008
Millions
Earnings are defined:
	Pretax Income Before Non-Controlling Interest		$135.0		$129.2		$119.1		$91.5		$126.4
	Add: Fixed Charges	51.2		47.6		43.4		38.3		30.3
	Undistributed Income from Less than 50 percent Owned Equity Investment	3.8		3.8		3.4		3.7		3.8
	Earnings as defined:		$182.4		$173.0		$159.1		$126.1		$152.9
Fixed Charges:
	Interest on Long-Term Debt		$47.0		$43.1		$39.7		$34.2		$27.4
	Other Interest Charges	0.4		1.6		1.0		1.6		0.4
	Interest Component of All Rentals (a)	3.8		2.9		2.7		2.5		2.5
	Total Fixed Charges		$51.2		$47.6		$43.4		$38.3		$30.3
Ratio of Earnings to Fixed Charges		3.56		3.63		3.67		3.29		5.05

(a) Represents interest portion of rents estimated at 33 1/3 percent.

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

(As of December 31, 2012)

(Reported Under Item 601 of Regulation S-K)

Name of Organization	State or Country
ALLETE, Inc. (d.b.a. ALLETE; Minnesota Power; Minnesota Power, Inc.;	Minnesota
Minnesota Power & Light Company; MPEX; MPEX A Division of Minnesota Power)
ALLETE Automotive Services, LLC	Minnesota
ALLETE Capital II	Delaware
ALLETE Capital III	Delaware
ALLETE Properties, LLC (d.b.a. ALLETE Properties)	Minnesota
ALLETE Commercial, LLC	Florida
Cape Coral Holdings, Inc.	Florida
Lake Swamp, LLC	Florida
Lehigh Acquisition Corporation	Delaware
Florida Landmark Communities, LLC	Florida
Lehigh Corporation	Florida
Mardem, LLC	Florida
Palm Coast Holdings, Inc.	Florida
Port Orange Holdings, LLC	Florida
Interlachen Lakes Estates, LLC	Florida
Palm Coast Land, LLC	Florida
Tomoka Holdings, LLC	Florida
ALLETE Water Services, Inc.	Minnesota
Florida Water Services Corporation	Florida
Energy Replacement Property, LLC	Minnesota
Energy Land, Incorporated	Wisconsin
Lakeview Financial Corporation I	Minnesota
Lakeview Financial Corporation II	Minnesota
Logistics Coal, LLC	Minnesota
Minnesota Power Enterprises, Inc.	Minnesota
ALLETE Renewable Resources, Inc.	North Dakota
ALLETE Clean Energy, Inc.	Minnesota
BNI Coal, Ltd.	North Dakota
MP Affiliate Resources, Inc.	Minnesota
Rainy River Energy Corporation	Minnesota
Rainy River Energy Corporation - Wisconsin	Wisconsin
Upper Minnesota Properties, Inc.	Minnesota
Upper Minnesota Properties - Development, Inc.	Minnesota
Upper Minnesota Properties - Irving, Inc.	Minnesota
Upper Minnesota Properties - Meadowlands, Inc.	Minnesota
MP Investments, Inc.	Delaware
RendField Land Company, Inc.	Minnesota
Superior Water, Light and Power Company	Wisconsin

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-166515, 333-170289) and Form S-8 (Nos. 333-91348, 333-183051, 333-162890) of ALLETE, Inc. of our reportdated February 15, 2013, relating to the financial statements,financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Minneapolis, Minnesota

February 15, 2013

EX-31.A

Exhibit 31(a)

Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer

Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Alan R. Hodnik, certify that:

1. I have reviewed this annual report on Form 10-K for the fiscal year ended December 31, 2012, of ALLETE, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:	February 15, 2013	/s/ Alan R. Hodnik
		Alan R. Hodnik
		President and Chief Executive Officer

EX-31.B

Exhibit 31(b)

Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer

Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Mark A. Schober, certify that:

1. I have reviewed this annual report on Form 10-K for the fiscal year ended December 31, 2012, of ALLETE, Inc.;

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

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

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

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

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

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

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

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

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

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

Date:	February 15, 2013	/s/ Mark A. Schober
		Mark A. Schober
		Senior Vice President and Chief Financial Officer

EX-32

Exhibit 32

Section 1350 Certification of Periodic Report

By the Chief Executive Officer and Chief Financial Officer

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

1. The Annual Report on Form 10-K of ALLETE for the fiscal year ended December 31, 2012, (Report) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

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

Date:	February 15, 2013	/s/ Alan R. Hodnik
		Alan R. Hodnik
		President and Chief Executive Officer

Date:	February 15, 2013	/s/ Mark A. Schober
		Mark A. Schober
		Senior Vice President and Chief Financial Officer

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

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

EX-95

Exhibit 95

Mine Safety Disclosure

Mine or Operating Name/MSHA Identification Number

Section 104 S&S Citations (#)

Section 104(b) Orders (#)

Section 104(d) Citations and Orders (#)

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

Section 107(a) Orders (#)

Total Dollar Value of MSHA Assessments Proposed ($)

Total Number of Mining Related Fatalities (#)

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

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

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

Legal Actions Initiated During Period (#)

Legal Actions Resolved During Period (#)

Center Mine / 3200218

2

—

—

—

—

$2,874

—

No

No

—

—

—

For the year ended December 31, 2102, BNI Coal, owner of Center Mine, received nine citations under Section 104(a) of the Mine Safety Act, two of which were significant and substantial (S&S) citations. The total penalties assessed on BNI with respect to the nine citations were $2,874. For the year ended December 31, 2012 there were no citations, orders, violations or notices received under Sections 104(b), 104(d), 107(a), 104(e) or 110(b)(2) of the Mine Safety Act and there were no fatalities.

EX-99

		Exhibit 99
	For Release:	February 15, 2013
	Investor Contact:	Tim Thorp
		218-723-3953
		tthorp@allete.com
NEWS

ALLETE reports 2012 earnings of $2.58 per share

Results in upper end of guidance range

Duluth, Minn. -ALLETE, Inc. (NYSE: ALE) today reported 2012 earnings of $2.58 per share compared with $2.65 per share in 2011. Excluding two non-recurring items, ALLETE's pro-forma earnings in 2011 were $2.39 per share.

The company recorded net income of $97.1 million in 2012 compared with $93.8 million a year ago, an increase of 3.5 percent. Operating revenue was $961.2 million this year versus $928.2 million in 2011.

Income from ALLETE's Regulated Operations segment decreased by $4.3 million in 2012 compared to 2011, however, last year's results included the benefit of two non-recurring items: the reversal of a $6.2 million, or 18 cents per share, deferred tax liability and a $2.9 million, or 8 cents per share, income tax benefit. Excluding these items, Regulated Operations increased by $4.8 million.

Continued strong retail and municipal sales, higher cost recovery revenue and renewable energy tax credits all contributed to the year-over-year increase. Minnesota Power electric sales to industrial customers increased by nearly two percent over 2011 to more than 7.5 million kilowatt-hours. These increases were partially offset by increased operating and maintenance, depreciation and interest expenses, as well as higher costs under the Square Butte power purchase agreement.

The Investments and Other segment recorded net income of $1 million in 2012 compared to a net loss of $6.6 million in 2011, due primarily to lower state income tax and interest expense.

Earnings for 2012 were diluted by 16 cents per share due to issuances of common shares needed to fund major capital investments.

“I'm pleased with our 2012 financial and operational performance as we executed our multi-faceted growth strategies,” said ALLETE President, Chairman and CEO Al Hodnik. “Our year-end results were in the upper end of our $2.50 to $2.60 guidance range.”

Hodnik said he was confident in ALLETE's ability to deliver continued earnings growth in 2013. “We expect another strong year of energy sales as our regional economy grows and we will continue to make needed capital investments to ensure reliability and meet state renewable and environmental mandates.”

ALLETE will host a conference call and webcast at 10:00 a.m. Eastern time today to discuss details of its financial performance for 2012, and its outlook for 2013. Interested parties may listen live by calling (877) 303-5852, or by accessing the webcast at www.allete.com. A replay of the call will be available through February 18, 2013 by calling (855) 859-2056, pass code 89501500.

ALLETE is an energy company headquartered in Duluth, Minn. ALLETE's energy businesses include Minnesota Power, Superior Water, Light & Power Co., BNI Coal and ALLETE Clean Energy. More information about the company is available at www.allete.com.

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

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

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

ALLETE, Inc.

Consolidated Statement of Income

For the Periods Ended December 31, 2012 and 2011

Millions Except Per Share Amounts

	Quarter Ended		Year to Date
	2012	2011	2012	2011
Operating Revenue	$256.0	$239.2	$961.2	$928.2
Operating Expenses
Fuel and Purchased Power	80.0	76.8	308.7	306.6
Operating and Maintenance	102.3	104.9	397.1	381.2
Depreciation	25.8	23.3	100.2	90.4
Total Operating Expenses	208.1	205.0	806.0	778.2
Operating Income	47.9	34.2	155.2	150.0
Other Income (Expense)
Interest Expense	(12.1)	(11.0)	(45.5)	(43.6)
Equity Earnings in ATC	5.1	4.7	19.4	18.4
Other	2.6	2.1	6.0	4.4
Total Other Expense	(4.4)	(4.2)	(20.1)	(20.8)
Income Before Non-Controlling Interest and Income Taxes	43.5	30.0	135.1	129.2
Income Tax Expense	14.6	10.9	38.0	35.6
Net Income	28.9	19.1	97.1	93.6
Less: Non-Controlling Interest in Subsidiaries	—	—	—	(0.2)
Net Income Attributable to ALLETE	28.9	$19.1	$97.1	$93.8
Average Shares of Common Stock
Basic	38.5	36.0	37.6	35.3
Diluted	38.6	36.1	37.6	35.4
Basic Earnings Per Share of Common Stock	$0.76	$0.53	$2.59	$2.66
Diluted Earnings Per Share of Common Stock	$0.75	$0.53	$2.58	$2.65
Dividends Per Share of Common Stock	$0.46	$0.445	$1.84	$1.78

Consolidated Balance Sheet

Millions

	Dec. 31,	Dec. 31,		Dec. 31,	Dec. 31,
	2012	2011		2012	2011
Assets			Liabilities and Shareholders' Equity
Cash and Short-Term Investments	$80.8	$101.1	Current Liabilities	$283.4	$163.1
Other Current Assets	192.4	175.9	Long-Term Debt	933.6	857.9
Property, Plant and Equipment	2,347.6	1,982.7	Deferred Income Taxes	423.8	373.6
Regulatory Assets	340.3	345.9	Regulatory Liabilities	60.1	43.5
Investment in ATC	107.3	98.9	Defined Benefit Pension & Other Postretirement Benefit Plans	228.2	253.5
Investments	143.5	132.3	Other Liabilities	123.3	105.1
Other	41.5	39.2	Shareholders' Equity	1,201.0	1,079.3
Total Assets	$3,253.4	$2,876.0	Total Liabilities and Shareholders' Equity	$3,253.4	$2,876.0

	Quarter Ended		Year to Date
ALLETE, Inc.	December 31,		December 31,
Income (Loss)	2012	2011	2012	2011
Millions
Regulated Operations	$28.0	$19.9	$96.1	$100.4
Investments and Other	0.9	(0.8)	1.0	(6.6)
Net Income Attributable to ALLETE	$28.9	$19.1	$97.1	$93.8
Diluted Earnings Per Share	$0.75	$0.53	$2.58	$2.65

Statistical Data
Corporate
Common Stock
High	$42.09	$42.54	$42.66	$42.54
Low	$37.73	$35.14	$37.73	$35.14
Close	$40.98	$41.98	$40.98	$41.98
Book Value	$30.50	$28.77	$30.50	$28.77

Kilowatt-hours Sold
Millions
Regulated Utility
Retail and Municipals
Residential	303	294	1,132	1,159
Commercial	352	360	1,436	1,433
Municipals	262	256	1,020	1,013
Industrial	1,877	1,895	7,502	7,365
Total Retail and Municipal	2,794	2,805	11,090	10,970
Other Power Suppliers	512	514	1,999	2,205
Total Regulated Utility	3,306	3,319	13,089	13,175
Non-regulated Energy Operations	33	30	113	105
Total Kilowatt-hours Sold	3,339	3,349	13,202	13,280

Regulated Utility Revenue
Millions
Regulated Operations
Retail and Municipals
Residential		$28.1		$26.6		$104.5		$109.1
Commercial	29.0		28.7		116.2		116.9
Municipals	15.6		14.6		60.6		61.2
Industrial	100.1		98.9		393.4		390.2
Total Retail and Municipals	172.8		168.8		674.7		677.4
Other Power Suppliers	18.6		18.5		73.1		78.7
Other	41.0		32.3		126.6		95.8
Total Regulated Utility Revenue		$232.4		$219.6		$874.4		$851.9

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.

XML

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]

Income Tax Expense
Year Ended December 31	2012			2011			2010
Millions
Current Tax Expense (Benefit)
Federal (a)	—			$1.4			$(23.0)
State (a)	$0.5			(1.6		)	1.3
Total Current Tax Expense (Benefit)	0.5			(0.2		)	(21.7		)
Deferred Tax Expense
Federal (b)	38.1			27.3			61.4
State (b)	(1.7		)	9.5			5.3
Change in Valuation Allowance (c)	2.0			(0.1		)	0.2
Investment Tax Credit Amortization	(0.9		)	(0.9		)	(0.9		)
Total Deferred Tax Expense	37.5			35.8			66.0
Total Income Tax Expense		$38.0			$35.6			$44.3

(a) For the years ended December 31, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, a federal current tax benefit was recorded as a result of tax planning initiatives and the bonus depreciation provision in the Small Business Jobs Act of 2010. The 2010 federal NOL was partially utilized by carrying it back against prior years’ income with the remainder carried forward to offset future years’ income.

(b) For the year ended December 31, 2012, the state deferred tax benefit of $1.7 million is due to state renewable tax credits earned which will be carried forward to offset future state income tax expense. The year ended December 31, 2011, included an income tax benefit for the reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and a benefit of $2.9 million related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. Included in the year ended December 31, 2010, was a charge of $4.0 million as a result of the PPACA. (See Note 5. Regulatory Matters.)

(c) For the year ending December 31, 2012, the change in the valuation allowance is due to state renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Table Text Block]

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2012			2011			2010
Millions
Income Before Non-Controlling Interest and Income Taxes		$135.1			$129.2			$119.1
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$47.3			$45.2			$41.7
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	1.2			6.0			4.5
Impact of the PPACA	—			—			4.0
Deferred Accounting for Retail Portion of the PPACA	—			(2.9		)	—
2010 Rate Case Stipulation Agreement - Deferred Tax Reversal	—			(6.2		)	—
Regulatory Differences for Utility Plant	(2.2		)	(1.2		)	(2.0		)
Production Tax Credits	(7.6		)	(4.3		)	(1.6		)
Other	(0.7		)	(1.0		)	(2.3		)
Total Income Tax Expense		$38.0			$35.6			$44.3

Deferred Tax Assets and Liabilities [Table Text Block]

Deferred Tax Assets and Liabilities
As of December 31	2012			2011
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$120.2			$132.7
Property Related	59.8			56.4
NOL Carryforwards	90.8			61.7
Tax Credit Carryforwards	28.3			12.2
Other	24.6			20.4
Gross Deferred Tax Assets	323.7			283.4
Deferred Tax Asset Valuation Allowance	(2.4		)	(0.4		)
Total Deferred Tax Assets		$321.3			$283.0
Deferred Tax Liabilities
Property Related		$577.1			$482.7
Regulatory Asset for Benefit Obligations	104.3			117.9
Unamortized Investment Tax Credits	11.9			12.8
Partnership Basis Differences	28.6			24.4
Other	30.1			24.0
Total Deferred Tax Liabilities		$752.0			$661.8
Net Deferred Income Taxes		$430.7			$378.8
Recorded as:
Net Current Deferred Tax Liabilities (a)		$6.9			$5.2
Net Long-Term Deferred Tax Liabilities	423.8			373.6
Net Deferred Income Taxes		$430.7			$378.8

(a) Included in Other Current Liabilities.

NOL and Tax Credit Carryforwards [Table Text Block]

NOL and Tax Credit Carryforwards
Year Ended December 31	2012		2011
Millions
Federal NOL carryforwards (a)		$244.1		$162.0
Federal tax credit carryforwards	$16.0		$8.4
State NOL carryforwards (a) (b)	$90.6		$73.1
State tax credit carryforwards (c)	$10.3		$3.8

(a) Pretax amounts

(b) Net of $0.4 million valuation allowance.

(c) Net of $2.0 million valuation allowance.

Gross Unrecognized Income Tax Benefits [Table Text Block]

Gross Unrecognized Income Tax Benefits	2012			2011			2010
Millions
Balance at January 1		$11.4			$12.3			$9.5
Reductions for Tax Positions Related to the Current Year	—			—			(0.2		)
Additions for Tax Positions Related to Prior Years	—			—			4.4
Reductions for Tax Positions Related to Prior Years	(8.7		)	(0.9		)	—
Reductions for Settlements	—			—			(0.3		)
Reductions for Expired Statute of Limitations	—			—			(1.1		)
Balance as of December 31		$2.7			$11.4			$12.3

XML

Regulatory Matters - Regulatory Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Regulatory Assets and Liabilities [Line Items]
Current Regulatory Asset	$ 22.5		$ 17.5
Non-Current Regulatory Asset	340.3		345.9
Total Regulatory Assets	362.8		363.4
Non-Current Regulatory Liability	60.1		43.5
Income Taxes [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liability	19.5		21.9
Plant Removal Obligations [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liability	18.1		15.0
Wholesale and Retail Contra AFUDC [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liability	15.5		1.5
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liability	7.0		5.1
Deferred Fuel [Member]
Regulatory Assets and Liabilities [Line Items]
Current Regulatory Asset	22.5	[1]	17.5	[1]
Future Benefit Obligations Under Defined Benefit Pension and Other Postretirement Benefit Plans [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Asset	260.7		292.8
Income Taxes [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Asset	36.0		28.6
Asset Retirement Obligation [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Asset	12.1		9.8
Cost Recovery Riders [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Asset	18.5	[2]	0.7	[2]
PPACA Income Tax Deferral [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Asset	5.0		5.0
Conservation Improvement Program [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Asset	4.3		4.6
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Asset	$ 3.7		$ 4.4

[1] Current regulatory assets are included in prepayments and other on our Consolidated Balance Sheet.

[2] The increase in cost recovery rider regulatory assets in 2012 is primarily due to revenues related to our Bison Wind Energy Center.

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Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Business Segments [Line Items]
Operating Revenue	$ 256.0	$ 248.8	$ 216.4	$ 240.0	$ 239.2	$ 226.9	$ 219.9	$ 242.2	$ 961.2	$ 928.2	$ 907.0
Fuel and Purchased Power Expense									308.7	306.6	325.1
Operating and Maintenance Expense									397.1	381.2	365.6
Depreciation Expense									100.2	90.4	80.5
Operating Income (Loss)	47.9	45.6	23.3	38.4	34.2	38.9	26.1	50.8	155.2	150.0	135.8
Interest Expense									(45.5)	(43.6)	(39.2)
Equity Earnings in ATC									19.4	18.4	17.9
Other Income									6.0	4.4	4.6
Income (Loss) Before Non-Controlling Interest and Income Taxes									135.1	129.2	119.1
Income Tax Expense (Benefit)									38.0	35.6	44.3
Net Income (Loss)									97.1	93.6	74.8
Less: Non-Controlling Interest in Subsidiaries									0	(0.2)	(0.5)
Net Income (Loss) Attributable to ALLETE	28.9	29.4	14.4	24.4	19.1	20.5	17.0	37.2	97.1	93.8	75.3
Total Assets	3,253.4				2,876.0				3,253.4	2,876.0	2,609.1
Capital Additions									432.2	246.8	260.0
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue									874.4	851.9	835.5
Fuel and Purchased Power Expense									308.7	306.6	325.1
Operating and Maintenance Expense									310.0	301.5	292.3
Depreciation Expense									93.9	85.4	76.1
Operating Income (Loss)									161.8	158.4	142.0
Interest Expense									(39.8)	(35.8)	(32.3)
Equity Earnings in ATC									19.4	18.4	17.9
Other Income									5.1	2.6	3.8
Income (Loss) Before Non-Controlling Interest and Income Taxes									146.5	143.6	131.4
Income Tax Expense (Benefit)									50.4	43.2	51.6
Net Income (Loss)									96.1	100.4	79.8
Less: Non-Controlling Interest in Subsidiaries									0	0	0
Net Income (Loss) Attributable to ALLETE									96.1	100.4	79.8
Total Assets	2,962.4				2,579.8				2,962.4	2,579.8	2,375.4
Capital Additions									418.2	228.0	256.4
Investments and Other [Member]
Business Segments [Line Items]
Number of acres of land in Minnesota (in acres)	6,100								6,100
Operating Revenue									86.8	76.3	71.5
Fuel and Purchased Power Expense									0	0	0
Operating and Maintenance Expense									87.1	79.7	73.3
Depreciation Expense									6.3	5.0	4.4
Operating Income (Loss)									(6.6)	(8.4)	(6.2)
Interest Expense									(5.7)	(7.8)	(6.9)
Equity Earnings in ATC									0	0	0
Other Income									0.9	1.8	0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes									(11.4)	(14.4)	(12.3)
Income Tax Expense (Benefit)									(12.4)	(7.6)	(7.3)
Net Income (Loss)									1.0	(6.8)	(5.0)
Less: Non-Controlling Interest in Subsidiaries									0	(0.2)	(0.5)
Net Income (Loss) Attributable to ALLETE									1.0	(6.6)	(4.5)
Total Assets	291.0				296.2				291.0	296.2	233.7
Capital Additions									$ 14.0	$ 18.8	$ 3.6

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Commitments, Guarantees and Contingencies - Environmental Matters (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Environmental Compliance Costs - Minimum	$ 350
Estimated Environmental Compliance Costs - Maximum	$ 400

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Investment in ATC (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Balance Sheet Data [Abstract]
Current Assets		$ 63.1	$ 58.7
Non-Current Assets		3,274.7	3,053.7
Total Assets		3,337.8	3,112.4
Current Liabilities		251.5	298.5
Long-Term Debt		1,550.0	1,400.0
Other Non-Current Liabilities		95.8	82.6
Members' Equity		1,440.5	1,331.3
Total Liabilities and Members' Equity		3,337.8	3,112.4
Income Statement Data [Abstract]
Revenue		603.2	567.2	556.7
Operating Expense		281.0	261.6	251.1
Other Expense		84.8	81.7	85.9
Net Income		237.4	223.9	219.7
ALLETE's Equity in Net Income		19.4	18.4	17.9
Investment in ATC [Abstract]
Equity Method Investment, Ownership Percentage		8.00%
Equity Method Investment, Approved Return on Common Equity		12.20%
Equity Method Investment, Expected Future Investment		2.0
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance	107.3	98.9	93.3
Cash Investments	0.4	4.7	2.0
Equity Earnings in ATC		19.4	18.4	17.9
Distributed ATC Earnings		(15.7)	(14.8)
Equity Investment Ending Balance		$ 107.3	$ 98.9	$ 93.3

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Income Tax Expense - Deferred Tax Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Deferred Tax Assets [Abstract]
Employee Benefits and Compensation	$ 120.2		$ 132.7
Property Related	59.8		56.4
NOL Carryforwards	90.8		61.7
Tax Credit Carryforwards	28.3		12.2
Other	24.6		20.4
Gross Deferred Tax Assets	323.7		283.4
Deferred Tax Asset Valuation Allowance	(2.4)		(0.4)
Total Deferred Tax Assets	321.3		283.0
Deferred Tax Liabilities [Abstract]
Property Related	577.1		482.7
Regulatory Asset for Benefit Obligations	104.3		117.9
Unamortized Investment Tax Credits	11.9		12.8
Partnership Basis Differences	28.6		24.4
Other	30.1		24.0
Total Deferred Tax Liabilities	752.0		661.8
Net Deferred Income Taxes	430.7		378.8
Net Current Deferred Tax Liabilities	6.9	[1]	5.2	[1]
Net Long-Term Deferred Tax Liabilities	$ 423.8		$ 373.6

[1] Included in Other Current Liabilities.

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Operations and Significant Accounting Policies - Investments and Other (Details)	12 Months Ended
	Dec. 31, 2012
Long-term Contract for Purchase of Electric Power [Line Items]
Real Estate Sales Revenue Recognition, Minimum Contract Price Cash Collections Requirement	20.00%
Square Butte PPA [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Output Purchased (Percent)	50.00%
Output Purchased (MW)	227.5

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Investment in ATC (Tables)

12 Months Ended

Dec. 31, 2012

Investment in ATC [Abstract]

ALLETE's Interest in ATC [Table Text Block]

ALLETE’s Interest in ATC
Year Ended December 31	2012			2011
Millions
Equity Investment Beginning Balance		$98.9			$93.3
Cash Investments	4.7			2.0
Equity in ATC Earnings	19.4			18.4
Distributed ATC Earnings	(15.7		)	(14.8		)
Equity Investment Ending Balance		$107.3			$98.9

ATC Summarized Financial Data [Table Text Block]

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2012		2011
Millions
Current Assets		$63.1		$58.7
Non-Current Assets	3,274.7		3,053.7
Total Assets		$3,337.8		$3,112.4
Current Liabilities		$251.5		$298.5
Long-Term Debt	1,550.0		1,400.0
Other Non-Current Liabilities	95.8		82.6
Members’ Equity	1,440.5		1,331.3
Total Liabilities and Members’ Equity		$3,337.8		$3,112.4

Income Statement Data
Year Ended December 31	2012		2011		2010
Millions
Revenue		$603.2		$567.2		$556.7
Operating Expense	281.0		261.6		251.1
Other Expense	84.8		81.7		85.9
Net Income		$237.4		$223.9		$219.7
ALLETE’s Equity in Net Income		$19.4		$18.4		$17.9

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Income Tax Expense - NOL and Tax Credit Carryforwards (Details) (USD $)	Dec. 31, 2012		Dec. 31, 2011
Federal [Member]
NOL and Tax Credit Carryforwards [Line Items]
NOL Carryforward	$ 244,100,000	[1]	$ 162,000,000	[1]
Tax Credit Carryforwards	16,000,000		8,400,000
NOL and Tax Credit Carryforwards, Valuation Allowance	0
State [Member]
NOL and Tax Credit Carryforwards [Line Items]
NOL Carryforward	90,600,000	[1],[2]	73,100,000	[1],[2]
Tax Credit Carryforwards	10,300,000	[3]	3,800,000	[3]
NOL Carryforwards, Valuation Allowance	400,000
Tax Credit Carryforwards, Valuation Allowance	$ 2,000,000

[1] Pretax amounts

[2] Net of $0.4 million valuation allowance.

[3] Net of $2.0 million valuation allowance.

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Common Stock and Earnings Per Share - Summary of Common Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Common Stock [Member]	Dec. 31, 2011 Common Stock [Member]	Dec. 31, 2010 Common Stock [Member]	Dec. 31, 2009 Common Stock [Member]
Class of Stock [Line Items]
Common Stock Outstanding, Shares		39,400,000	37,500,000		39,377,000	37,513,000	35,817,000	35,221,000
Common Stock Outstanding, Value					$ 784.7	$ 705.6	$ 636.1	$ 613.4
Employee Stock Purchase Program, Shares					20,000	20,000	19,000
Employee Stock Purchase Program, Value					0.8	0.8	0.6
Invest Direct, Shares					474,000	437,000	346,000
Invest Direct, Value					19.2	17.2	11.7
Options and Stock Awards, Shares					95,000	109,000	51,000
Options and Stock Awards, Value					6.0	6.7	4.4
Equity Issuance Program, Shares					1,275,000	400,000	180,000
Equity Issuance Program, Value					53.1	16.0	6.0
Purchase of Non-Controlling Interest, Shares	200,000					222,000
Purchase of Non-Controlling Interest, Value						8.8
Contributions to Pension, Shares						508,000
Contributions to Pension, Value		$ 0	$ (20.0)	$ 0		$ 20.0
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share					200,000	300,000	500,000
Equity Issuance Program Shares Authorized					9,600,000
Equity Issuance Program Shares Available for Issuance					4,500,000

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Pension and Other Postretirement Benefit Plans - Weighted-Average Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.10%	4.54%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Discount Rate	4.54%	5.36%	5.81%
Expected Long-term Return on Plan Assets	8.25%	8.50%	8.50%
Pension [Member] | Minimum [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]
Rate of Compensation Increase	4.30%	4.30%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	4.30%	4.30%	4.30%
Pension [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]
Rate of Compensation Increase	4.60%	4.60%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	4.60%	4.60%	4.60%
Postretirement Health and Life [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.13%	4.56%
Trend Rate	9.25%	10.00%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2019	2018
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Discount Rate	4.56%	5.40%	5.81%
Postretirement Health and Life [Member] | Minimum [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-term Return on Plan Assets	6.60%	6.80%	6.80%
Postretirement Health and Life [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-term Return on Plan Assets	8.25%	8.50%	8.50%

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Investments Parenthetical (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Investments Parenthetical [Abstract]
Long-Term Finance Receivables, Allowance	$ 0.6	$ 0.6

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Income Tax Expense (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Income Tax Expense [Abstract]
Current Federal Tax Expense (Benefit)		$ 0	[1]	$ 1.4	[1]	$ (23.0)	[1]
Current State Tax Expense (Benefit)		0.5	[1]	(1.6)	[1]	1.3	[1]
Total Current Tax Expense (Benefit)		0.5		(0.2)		(21.7)
Deferred Federal Tax Expense		38.1	[2]	27.3	[2]	61.4	[2]
Deferred State Tax Expense (Benefit)		(1.7)	[2]	9.5	[2]	5.3	[2]
Change in Valuation Allowance		2.0	[3]	(0.1)	[3]	0.2	[3]
Investment Tax Credit Amortization		(0.9)		(0.9)		(0.9)
Total Deferred Tax Expense		37.5		35.8		66.0
Total Income Tax Expense		38.0		35.6		44.3
2010 Rate Case Stipulation Agreement, Revenue Receivable Foregone [Member]
Income Tax Expense [Abstract]
Total Deferred Tax Expense		0		(6.2)		0
PPACA Elimination of Medicare Part D [Member]
Income Tax Expense [Abstract]
Total Deferred Tax Expense	2.9	0		(2.9)		0
Unusual or Infrequent Item [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions		$ 0		$ 0		$ 4.0

[1] For the years ended December 31, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, a federal current tax benefit was recorded as a result of tax planning initiatives and the bonus depreciation provision in the Small Business Jobs Act of 2010. The 2010 federal NOL was partially utilized by carrying it back against prior years’ income with the remainder carried forward to offset future years’ income.

[2] For the year ended December 31, 2012, the state deferred tax benefit of $1.7 million is due to state renewable tax credits earned which will be carried forward to offset future state income tax expense. The year ended December 31, 2011, included an income tax benefit for the reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and a benefit of $2.9 million related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. Included in the year ended December 31, 2010, was a charge of $4.0 million as a result of the PPACA. (See Note 5. Regulatory Matters.)

[3] For the year ending December 31, 2012, the change in the valuation allowance is due to state renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

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Pension and Other Postretirement Benefit Plans - Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) (Pension [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 652.1	$ 597.5
Accumulated Benefit Obligation	598.7	550.6
Fair Value of Plan Assets	$ 460.1	$ 432.4

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Pension and Other Postretirement Benefit Plans - Contributions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended					3 Months Ended		3 Months Ended	12 Months Ended		3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Pension [Member]	Dec. 31, 2011 Pension [Member]	Mar. 31, 2013 Postretirement Health and Life [Member]	Feb. 15, 2013 Postretirement Health and Life [Member]	Mar. 31, 2013 VEBA [Member]	Dec. 31, 2012 VEBA [Member]	Dec. 31, 2011 VEBA [Member]	Mar. 31, 2013 Grantor Trust [Member]	Dec. 31, 2012 Grantor Trust [Member]	Dec. 31, 2011 Grantor Trust [Member]
Pension and Other Postretirement Benefit Plans [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Amount	$ 7.7	$ 7.3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Contributions				7.3	33.8	4.8		2.8	1.5	10.9	2.0	0	0
ALLETE Common Stock Contributed to Pension Plan	0	(20.0)	0		20.0
Defined Benefit Plans, Estimated Employer Contributions				$ 0			$ 0

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Pension and Other Postretirement Benefit Plans - Estimated Future Benefit Payments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2013	$ 31.2
2014	32.1
2015	33.2
2016	34.4
2017	35.5
Years 2018 - 2022	189.4
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2013	7.6
2014	8.2
2015	8.9
2016	9.4
2017	9.7
Years 2018 - 2022	$ 52.0

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Income Tax Expense - Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Expense [Abstract]
Income Before Non-Controlling Interest and Income Taxes		$ 135.1	$ 129.2	$ 119.1
Statutory Federal Income Tax Rate		35.00%	35.00%	35.00%
Income Taxes Computed at 35 Percent Statutory Federal Rate		47.3	45.2	41.7
Increase (Decrease) in Tax [Abstract]
State Income Taxes - Net of Federal Income Tax Benefit		1.2	6.0	4.5
Unusual or Infrequent Item [Line Items]
Deferred Income Tax Expense (Benefit)		37.5	35.8	66.0
Regulatory Differences for Utility Plant		(2.2)	(1.2)	(2.0)
Production Tax Credits		7.6	4.3	1.6
Other		(0.7)	(1.0)	(2.3)
Income Tax Expense		38.0	35.6	44.3
Effective Income Tax Rate		28.10%	27.60%	37.20%
PPACA Elimination of Medicare Part D [Member]
Unusual or Infrequent Item [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions		0	0	4.0
Deferred Income Tax Expense (Benefit)	2.9	0	(2.9)	0
2010 Rate Case Stipulation Agreement [Member]
Unusual or Infrequent Item [Line Items]
Deferred Income Tax Expense (Benefit)		$ 0	$ (6.2)	$ 0

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Commitments, Guarantees and Contingencies - Other Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 Years	Dec. 31, 2011
BNI Coal Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Surety Bond	$ 29.8
Letters of Credit	2.6
Estimated Reclamation Liability	32.4
ALLETE Properties Performance and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Surety Bond	10.2
Performance and Maintenance Obligations	7.4
Performance and Maintenance Obligations, Land Purchaser Contractual Obligation	0.6
Town Center Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Community Development District Obligation, Bond	26.4
Community Development Distrcit Obligation, Bond Interest Rate	6.00%
Community Development District Obligation, Bond Term (in Years)	31
Community Development District Obligation, Ownership Percentage of Benefited Property	73.00%	73.00%
Community Development District Obligation, Annual Assessment	1.4
Palm Coast Park Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Community Development District Obligation, Bond	31.8
Community Development Distrcit Obligation, Bond Interest Rate	5.70%
Community Development District Obligation, Bond Term (in Years)	31
Community Development District Obligation, Ownership Percentage of Benefited Property	93.00%	93.00%
Community Development District Obligation, Annual Assessment	$ 2.1

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data (Unaudited) [Abstract]

Quarterly Financial Data (Unaudited) [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED)

Information for any one quarterly period is not necessarily indicative of the results which may be expected for the year.

Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
2012
Operating Revenue		$240.0		$216.4		$248.8		$256.0
Operating Income		$38.4		$23.3		$45.6		$47.9
Net Income Attributable to ALLETE		$24.4		$14.4		$29.4		$28.9
Earnings Per Share of Common Stock
Basic		$0.66		$0.39		$0.78		$0.76
Diluted		$0.66		$0.39		$0.78		$0.75
2011
Operating Revenue		$242.2		$219.9		$226.9		$239.2
Operating Income		$50.8		$26.1		$38.9		$34.2
Net Income Attributable to ALLETE		$37.2		$17.0		$20.5		$19.1
Earnings Per Share of Common Stock
Basic		$1.07		$0.49		$0.57		$0.53
Diluted		$1.07		$0.48		$0.57		$0.53

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Jointly-Owned Facilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Jointly-Owned Facilities [Line Items]
Plant in Service	$ 435.9
Accumulated Depreciation	188.5
Construction Work in Progress	50.4
Boswell Unit 4 [Member]
Jointly-Owned Facilities [Line Items]
Plant in Service	413.1
Accumulated Depreciation	188.1
Construction Work in Progress	25.0
% Ownership	80.00%
Generating Unit Capacity (MW)	585
% Not Owned	20.00%
CapX2020 [Member]
Jointly-Owned Facilities [Line Items]
Plant in Service	22.8
Accumulated Depreciation	0.4
Construction Work in Progress	$ 25.4
Number of Projects	3
CapX2020 [Member] | Minimum [Member]
Jointly-Owned Facilities [Line Items]
% Ownership	9.30%
CapX2020 [Member] | Maximum [Member]
Jointly-Owned Facilities [Line Items]
% Ownership	14.70%

XML

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data (Unaudited) [Abstract]

Quarterly Financial Data (Unaudited) [Table Text Block]

Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
2012
Operating Revenue		$240.0		$216.4		$248.8		$256.0
Operating Income		$38.4		$23.3		$45.6		$47.9
Net Income Attributable to ALLETE		$24.4		$14.4		$29.4		$28.9
Earnings Per Share of Common Stock
Basic		$0.66		$0.39		$0.78		$0.76
Diluted		$0.66		$0.39		$0.78		$0.75
2011
Operating Revenue		$242.2		$219.9		$226.9		$239.2
Operating Income		$50.8		$26.1		$38.9		$34.2
Net Income Attributable to ALLETE		$37.2		$17.0		$20.5		$19.1
Earnings Per Share of Common Stock
Basic		$1.07		$0.49		$0.57		$0.53
Diluted		$1.07		$0.48		$0.57		$0.53

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Other Income (Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Income (Expense) [Abstract]
AFUDC - Equity	$ 5.1	$ 2.5	$ 4.2
Investment and Other Income	0.9	1.9	0.4
Total Other Income	$ 6.0	$ 4.4	$ 4.6

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Employee Stock and Incentive Plans - Non-Qualified Stock Options (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2008
Number of Options [Abstract]
Outstanding as of January 1,	460,234		560,887		646,235
Granted	0	[1]	0	[1]	0	[1]
Exercised	49,075		80,798		40,769
Forfeited	15,481		19,855		44,579
Outstanding as of December 31,	395,678		460,234		560,887
Exercisable as of December 31,	395,678		460,234		523,491
Weighted Average Exercise Price [Abstract]
Outstanding as of January 1,	$ 41.68		$ 40.69		$ 40.05
Granted	$ 0	[1]	$ 0	[1]	$ 0	[1]
Exercised	$ 35.84		$ 34.25		$ 27.76
Forfeited	$ 44.86		$ 43.96		$ 43.16
Outstanding as of December 31,	$ 42.28		$ 41.68		$ 40.69
Exercisable as of December 31,	$ 41.71		$ 41.59		$ 39.76
Proceeds from Stock Options Exercised	$ 0.1
Weighted Average Grant Date Intrinsic Value of Options Granted							$ 6.18
Total Intrinsic Value of Options Exercised	$ 0.3		$ 0.5		$ 0.3

[1] Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

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Common Stock and Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Common Stock and Earnings Per Share [Abstract]

Summary of Common Stock [Table Text Block]

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2009	35,221		$613.4
Employee Stock Purchase Program	19	0.6
Invest Direct	346	11.7
Options and Stock Awards	51	4.4
Equity Issuance Program	180	6.0
Balance as of December 31, 2010	35,817		$636.1
Employee Stock Purchase Program	20	0.8
Invest Direct	437	17.2
Options and Stock Awards	109	6.7
Equity Issuance Program	400	16.0
Purchase of Non-Controlling Interest	222	8.8
Contributions to Pension	508	20.0
Balance as of December 31, 2011	37,513		$705.6
Employee Stock Purchase Program	20	0.8
Invest Direct	474	19.2
Options and Stock Awards	95	6.0
Equity Issuance Program	1,275	53.1
Balance as of December 31, 2012	39,377		$784.7

Reconciliation of Basic and Diluted Earnings Per Share [Table Text Block]

Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2012
Net Income Attributable to ALLETE		$97.1			$97.1
Average Common Shares	37.6		—	37.6
Earnings Per Share		$2.59			$2.58
2011
Net Income Attributable to ALLETE		$93.8			$93.8
Average Common Shares	35.3		0.1	35.4
Earnings Per Share		$2.66			$2.65
2010
Net Income Attributable to ALLETE		$75.3			$75.3
Average Common Shares	34.2		0.1	34.3
Earnings Per Share		$2.20			$2.19

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Regulatory Matters - Boswell Mercury Emission Reduction Plan (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Environmental Compliance Costs - Minimum	$ 350
Estimated Environmental Compliance Costs - Maximum	$ 400

XML

Commitments, Guarantees and Contingencies - Coal Rail and Shipping Contracts (Details) (Coal and Transportation [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Coal and Transportation [Member]
Coal Rail and Shipping Contracts [Line Items]
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2013	$ 51.4
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2014	$ 0.8

XML

Fair Value - Recurring Fair Value Measures, Activity in Level 3 (Details) (Debt Securities Issued by States of the United States (ARS) [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Debt Securities Issued by States of the United States (ARS) [Member]
Recurring Fair Value Measures, Activity in Level 3 [Line Items]
Beginning Balance	$ 6.7
Redeemed During the Period	(6.7)	[1]
Ending Balance	$ 0

[1] The ARS were redeemed at carrying value on January 5, 2011.

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Operations and Significant Accounting Policies - Concentraion of Credit Risk (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Customer Information [Line Items]
Major Customer, Percent of Total Revenue	12.30%	12.80%	12.50%
NewPage Bankruptcy Pre-Petition Receivable	$ 3.2
Large Power Customer [Member]
Customer Information [Line Items]
Number of Customers	9
Large Power Customers, Accounts Receivable	$ 11.6	9.3

XML

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Operations and Significant Accounting Policies [Abstract]

Operations and Significant Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Preparation. References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue, and expenses. Actual results could differ from those estimates.

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

Principles of Consolidation. Our consolidated financial statements include the accounts of ALLETE and all of our majority-owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.

Business Segments. Our Regulated Operations and Investments and Other segments were determined in accordance with the guidance on segment reporting. Segmentation is based on the manner in which we operate, assess, and allocate resources to the business. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,100 acres of land in Minnesota, and earnings on cash and investments.

BNI Coal, a wholly-owned subsidiary, mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2012, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under a long-term contract. (See Note 11. Commitments, Guarantees and Contingencies.) Coal sales are recognized when delivered at the cost of production plus a specified profit per ton of coal delivered.

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. ALLETE does not intend to acquire additional Florida real estate.

Full profit recognition is recorded on sales upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. In certain cases, where there are obligations to perform significant development activities after the date of sale, we recognize profit on a percentage-of-completion basis. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

In certain cases, we pay fees or construct improvements to mitigate offsite traffic impacts. In return, we receive traffic impact fee credits as a result of some of these expenditures. We recognize revenue from the sale of traffic impact fee credits when payment is received.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Land inventories are accounted for in accordance with the accounting standards for property, plant and equipment, and are included in Other Investments on our Consolidated Balance Sheet. Real estate costs include the cost of land acquired, subsequent development costs and costs of improvements, capitalized development period interest, real estate taxes and payroll costs of certain employees devoted directly to the development effort. These real estate costs incurred are capitalized to the cost of real estate parcels based upon the relative sales value of parcels within each development project in accordance with the accounting standards for real estate. The cost of real estate sold includes the actual costs incurred and the estimate of future completion costs allocated to the real estate sold based upon the relative sales value method. Whenever events or circumstances indicate that the carrying value of the real estate may not be recoverable, impairments are recorded and the related assets are adjusted to their estimated fair value. (See Note 7. Investments.)

ALLETE Clean Energy, a wholly-owned subsidiary of ALLETE, operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. 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.

Non-Controlling Interest in Subsidiaries. In August 2011, ALLETE purchased the remaining shares of the ALLETE Properties non-controlling interest at book value for $8.8 million by issuing 0.2 million shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or comprehensive income.

Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.

Supplemental Statement of Cash Flow Information

Consolidated Statement of Cash Flows
Year Ended December 31	2012		2011		2010
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$42.7		$43.2		$35.7
Cash Received During the Period for Income Taxes (a)	—		$(11.4)		$(54.2)
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$20.2		$5.9	$7.5
Capitalized Asset Retirement Costs		$17.1		$0.3		$2.8
AFUDC – Equity		$5.1		$2.5		$4.2
ALLETE Common Stock Contributed to the Pension Plan	—		$(20.0)		—

(a) Due to bonus depreciation provisions in 2009 and 2010 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and refunds were received from NOL carrybacks against prior years’ taxable income.

Accounts Receivable. Accounts receivable are reported on the balance sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses.

Accounts Receivable
As of December 31	2012		2011
Millions
Trade Accounts Receivable
Billed		$70.4		$63.7
Unbilled	17.4		15.6
Less: Allowance for Doubtful Accounts	1.0		0.9
Total Trade Accounts Receivable	86.8		78.4
Income Taxes Receivable	2.2		1.3
Total Accounts Receivable - Net		$89.0		$79.7

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Concentration of Credit Risk. Financial instruments that subject us to concentrations of credit risk consist primarily of accounts receivable. Minnesota Power sells electricity to 9 Large Power Customers. Receivables from these customers totaled $11.6 million at December 31, 2012 ($9.3 million at December 31, 2011). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, our taconite-producing Large Power Customers, which are a part of our Regulated Operations segment, are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 12.3 percent of consolidated revenue in 2012 (12.8 percent in 2011; 12.5 percent in 2010). In the third quarter of 2011, one of Minnesota Power’s Large Power Customers, NewPage Corporation (NewPage), filed for Chapter 11 bankruptcy protection. In September 2012, NewPage submitted a motion to the bankruptcy court to approve amended and restated service agreements and payment of the pre-petition amount, which was approved on October 16, 2012. The agreement was subsequently approved by the MPUC in a December 10, 2012 order, which resulted in the pre-petition receivable of $3.2 million being paid as of December 31, 2012. Throughout the bankruptcy proceedings this customer’s operations continued without interruption and we continued to provide electric and steam service to this customer.

Long-Term Finance Receivables. Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals. (See Note 7. Investments.)

Available-for-Sale Securities. Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as the share price trends and the impact of overall market conditions. (See Note 7. Investments.)

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

Inventories
As of December 31	2012		2011
Millions
Fuel		$28.0		$28.6
Materials and Supplies	41.8		40.5
Total Inventories		$69.8		$69.1

Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the balance sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on non-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for Regulated Operations. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. The MPUC has approved cost recovery for several large capital projects recently, at which time the recognition of AFUDC ceases. (See Note 3. Property, Plant and Equipment.)

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed for the recovery of the remaining basis of retired plant assets. In January 2013 we announced the retirement of Taconite Harbor Unit 3 and conversion of Laskin Energy Center to natural gas in 2015, which is subject to MPUC approval. Accordingly, we do not expect any loss as a result of the retirement of Taconite Harbor Unit 3 or conversion of Laskin Energy Center.

Impairment of Long-Lived Assets. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels into bulk sales, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, and may vary among each land parcel or bulk sale.If the excess of undiscounted cash flows over the carrying value of a property is small, there is a greater risk of future impairment in the event of such changes and any resulting impairment charges could be material.

Weak market conditions for real estate in Florida have required us to review our land inventories for impairment. Our undiscounted cash flow analysis was estimated using management’s current intent for disposition of each property, which is an estimated selling period of five to ten years based on a December 2011 asset management and disposition plan (“Plan”). The Plan is reviewed annually for adjustment or modification and we have concluded that the estimates and assumptions remain appropriate in 2012. As such, we continue to utilize the Plan when evaluating our land inventory for impairment. Future selling prices have been estimated through management’s best estimate of future sales prices in collaboration and consultation with outside advisors, and based on the best use of the properties over the expected period of sale. The undiscounted cash flow analysis assumes two scenarios: retail land sales followed by project bulk sales over a five year period and retail land sales over a ten year period. Our analysis assumes the most likely case of retail land sales followed by project bulk sales over a five year period; however, under both scenarios, except as noted below, the undiscounted cash flows exceeded carrying values. If our major development projects are sold in one bulk sale or if the properties are sold differently than anticipated in the Plan, the actual results could be materially different from our undiscounted cash flow analysis.

The results of the impairment analysis are particularly dependent on the estimated future sales prices, method of disposition, and holding period for each property. The estimated holding period is based on management’s current intent for the use and disposition of each property, which could be subject to change in future periods if the intentions of the Company as set by management and approved by the Board of Directors were to change.

In the event that projected future undiscounted cash flows are not adequate to recover the carrying value of an asset, impairment is indicated and may require a write down to the asset’s fair value. Fair value is determined based on best available evidence including comparable sales, current appraised values, property tax assessed values, and discounted cash flow analysis. If fair value is less than cost, the carrying value of our investments is reduced and an impairment charge is recorded in the current period. In 2012, impairment analysis’ of estimated future undiscounted cash flows were conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. As a result, there was no impairment recorded for the year ended December 31, 2012. For the year ended December 31, 2011, a $1.7 million impairment charge was recorded.

Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage interest rate risk related to certain variable-rate borrowings.

Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 16. Employee Stock and Incentive Plans.)

Prepayments and Other Current Assets
As of December 31	2012		2011
Millions
Deferred Fuel Adjustment Clause		$22.5		$17.5
Other	11.1		9.6
Total Prepayments and Other Current Assets		$33.6		$27.1

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Current Liabilities
As of December 31	2012		2011
Millions
Customer Deposits (a)		$28.8		$16.3
Other	33.8		29.3
Total Other Current Liabilities		$62.6		$45.6

(a) Customer deposits were higher in 2012 primarily due to customer security deposits for capital expenditures relating to a transmission project.

Other Non-Current Liabilities
As of December 31	2012		2011
Millions
Asset Retirement Obligation		$77.9		$57.0
Other	45.4		48.1
Total Other Non-Current Liabilities		$123.3		$105.1

Environmental Liabilities. We review environmental matters for disclosure on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the 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 operating expense unless recoverable in rates from customers. (See Note 11. Commitments, Guarantees and Contingencies.)

Revenue Recognition. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for service provided but not billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. BNI recognizes revenue when coal is delivered.

Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue and net purchases in Fuel and Purchased Power Expense on our Consolidated Statement of Income. The revenues and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.

Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using the straight-line method which approximates the effective interest method.

Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return and combined and separate state income tax returns. We account for income taxes using the liability method in accordance with the accounting standards for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with the accounting standards for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than 50 percent likely. (See Note 14. Income Tax Expense.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Excise Taxes. We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.

New Accounting Standards.

There are no recently issued accounting standard updates applicable for our adoption in future periods.

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Fair Value - Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,018.1	$ 863.3
Long-Term Debt, Including Current Portion - Fair Value	$ 1,143.7	$ 966.4

XML

Operations and Significant Accounting Policies (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Non-Controlling Interest in Subsidiaries [Abstract]
Purchase of Non-Controlling Interest at Book Value	$ 8.8
Purchase of Non-Controlling Interest, Shares Issued	200
Trade Accounts Receivable [Abstract]
Billed		70.4		63.7
Unbilled		17.4		15.6
Less: Allowance for Doubtful Accounts		1.0		0.9
Total Trade Accounts Receivable		86.8		78.4
Income Taxes Receivable		2.2		1.3
Total Accounts Receivable - Net		89.0		79.7
Inventories [Abstract]
Fuel		28.0		28.6
Materials and Supplies		41.8		40.5
Total Inventories		69.8		69.1
Impairement of Long-Lived Assets [Abstract]
Land Impairment		0		1.7
Prepayments and Other Current Assets [Abstract]
Deferred Fuel Adjustment Clause		22.5		17.5
Other		11.1		9.6
Total Prepayments and Other Current Assets		33.6		27.1
Other Current Liabilities [Abstract]
Customer Deposits		28.8	[1]	16.3	[1]
Other		33.8		29.3
Total Other Current Liabilities		62.6		45.6
Other Non-Current Liabilities [Abstract]
Asset Retirement Obligation		77.9		57.0		50.3
Other		45.4		48.1
Total Other Non-Current Liabilities		$ 123.3		$ 105.1
Income Tax Disclosure [Abstract]
More Likely Than Not Definition		50.00%
Municipal Customers [Member]
Customer Information [Line Items]
Number of Customers		16
Non-Affiliated Private Utility [Member]
Customer Information [Line Items]
Number of Customers		1
Retail Customers [Member]
Customer Information [Line Items]
Number of Customers		143,000
Electric [Member]
Customer Information [Line Items]
Number of Customers		15,000
Natural Gas [Member]
Customer Information [Line Items]
Number of Customers		12,000
Water [Member]
Customer Information [Line Items]
Number of Customers		10,000

[1] 2012 primarily due to customer security deposits for capital expenditures relating to a transmission project.

XML

Business Segments (Tables)

12 Months Ended

Dec. 31, 2012

Business Segments [Abstract]

Business Segments [Table Text Block]

	Consolidated			Regulated Operations			Investments and Other
Millions
2011
Operating Revenue		$928.2			$851.9			$76.3
Fuel and Purchased Power Expense	306.6			306.6			—
Operating and Maintenance Expense	381.2			301.5			79.7
Depreciation Expense	90.4			85.4			5.0
Operating Income (Loss)	150.0			158.4			(8.4		)
Interest Expense	(43.6		)	(35.8		)	(7.8		)
Equity Earnings in ATC	18.4			18.4			—
Other Income	4.4			2.6			1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	129.2			143.6			(14.4		)
Income Tax Expense (Benefit)	35.6			43.2			(7.6		)
Net Income (Loss)	93.6			100.4			(6.8		)
Less: Non-Controlling Interest in Subsidiaries	(0.2		)	—			(0.2		)
Net Income (Loss) Attributable to ALLETE		$93.8			$100.4		$(6.6)
Total Assets		$2,876.0			$2,579.8			$296.2
Capital Additions		$246.8			$228.0			$18.8

	Consolidated			Regulated Operations			Investments and Other
Millions
2010
Operating Revenue		$907.0			$835.5			$71.5
Fuel and Purchased Power Expense	325.1			325.1			—
Operating and Maintenance Expense	365.6			292.3			73.3
Depreciation Expense	80.5			76.1			4.4
Operating Income (Loss)	135.8			142.0			(6.2		)
Interest Expense	(39.2		)	(32.3		)	(6.9		)
Equity Earnings in ATC	17.9			17.9			—
Other Income	4.6			3.8			0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	119.1			131.4			(12.3		)
Income Tax Expense (Benefit)	44.3			51.6			(7.3		)
Net Income (Loss)	74.8			79.8			(5.0		)
Less: Non-Controlling Interest in Subsidiaries	(0.5		)	—			(0.5		)
Net Income (Loss) Attributable to ALLETE		$75.3			$79.8		$(4.5)
Total Assets		$2,609.1			$2,375.4			$233.7
Capital Additions		$260.0			$256.4			$3.6

	Consolidated			Regulated Operations			Investments and Other
Millions
2012
Operating Revenue		$961.2			$874.4			$86.8
Fuel and Purchased Power Expense	308.7			308.7			—
Operating and Maintenance Expense	397.1			310.0			87.1
Depreciation Expense	100.2			93.9			6.3
Operating Income (Loss)	155.2			161.8			(6.6		)
Interest Expense	(45.5		)	(39.8		)	(5.7		)
Equity Earnings in ATC	19.4			19.4			—
Other Income	6.0			5.1			0.9
Income (Loss) Before Non-Controlling Interest and Income Taxes	135.1			146.5			(11.4		)
Income Tax Expense (Benefit)	38.0			50.4			(12.4		)
Net Income	97.1			96.1			1.0
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE		$97.1			$96.1			$1.0
Total Assets		$3,253.4			$2,962.4			$291.0
Capital Additions		$432.2			$418.2			$14.0

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Operations and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Operations and Significant Accounting Policies [Abstract]

Supplemental Statement of Cash Flow Information [Table Text Block]

Supplemental Statement of Cash Flow Information

Consolidated Statement of Cash Flows
Year Ended December 31	2012		2011		2010
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$42.7		$43.2		$35.7
Cash Received During the Period for Income Taxes (a)	—		$(11.4)		$(54.2)
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$20.2		$5.9	$7.5
Capitalized Asset Retirement Costs		$17.1		$0.3		$2.8
AFUDC – Equity		$5.1		$2.5		$4.2
ALLETE Common Stock Contributed to the Pension Plan	—		$(20.0)		—

(a) Due to bonus depreciation provisions in 2009 and 2010 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and refunds were received from NOL carrybacks against prior years’ taxable income.

Accounts Receivable [Table Text Block]

Accounts Receivable
As of December 31	2012		2011
Millions
Trade Accounts Receivable
Billed		$70.4		$63.7
Unbilled	17.4		15.6
Less: Allowance for Doubtful Accounts	1.0		0.9
Total Trade Accounts Receivable	86.8		78.4
Income Taxes Receivable	2.2		1.3
Total Accounts Receivable - Net		$89.0		$79.7

Inventories [Table Text Block]

Inventories
As of December 31	2012		2011
Millions
Fuel		$28.0		$28.6
Materials and Supplies	41.8		40.5
Total Inventories		$69.8		$69.1

Prepayments and Other Current Assets [Table Text Block]

Prepayments and Other Current Assets
As of December 31	2012		2011
Millions
Deferred Fuel Adjustment Clause		$22.5		$17.5
Other	11.1		9.6
Total Prepayments and Other Current Assets		$33.6		$27.1

Other Liabilities [Table Text Block]

Other Current Liabilities
As of December 31	2012		2011
Millions
Customer Deposits (a)		$28.8		$16.3
Other	33.8		29.3
Total Other Current Liabilities		$62.6		$45.6

(a) Customer deposits were higher in 2012 primarily due to customer security deposits for capital expenditures relating to a transmission project.

Other Non-Current Liabilities
As of December 31	2012		2011
Millions
Asset Retirement Obligation		$77.9		$57.0
Other	45.4		48.1
Total Other Non-Current Liabilities		$123.3		$105.1

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Quarterly Financial Data (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Quarterly Financial Data (Unaudited) [Abstract]
Operating Revenue	$ 256.0	$ 248.8	$ 216.4	$ 240.0	$ 239.2	$ 226.9	$ 219.9	$ 242.2	$ 961.2	$ 928.2	$ 907.0
Operating Income	47.9	45.6	23.3	38.4	34.2	38.9	26.1	50.8	155.2	150.0	135.8
Net Income Attributable to ALLETE	$ 28.9	$ 29.4	$ 14.4	$ 24.4	$ 19.1	$ 20.5	$ 17.0	$ 37.2	$ 97.1	$ 93.8	$ 75.3
Basic Earnings Per Share of Common Stock	$ 0.76	$ 0.78	$ 0.39	$ 0.66	$ 0.53	$ 0.57	$ 0.49	$ 1.07	$ 2.59	$ 2.66	$ 2.20
Diluted Earnings Per Share of Common Stock	$ 0.75	$ 0.78	$ 0.39	$ 0.66	$ 0.53	$ 0.57	$ 0.48	$ 1.07	$ 2.58	$ 2.65	$ 2.19

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Investments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jan. 05, 2011
Available-for-sale Securities [Abstract]
Cost	$ 27.4	$ 27.3	$ 27.4
Gross Unrealized Gain	0.5	0.1	0.2
Gross Unrealized (Loss)	(1.1)	(2.7)	(2.4)
Fair Value	26.8	24.7	25.2
Net Proceeds	1.5	7.8	0.6
Gross Realized Gain	0	0	0
Gross Realized (Loss)	0	0	0
Net Unrealized Gain (Loss) in Other Comprehensive Income	1.2	(0.3)	0.8
Available for sale securities, Issued by States of the United States (ARS)				6.7
Investments [Abstract]
ALLETE Properties	91.1	91.3
Available-for-sale Securities	26.8	24.7
Other	25.6	16.3
Total Investments	143.5	132.3
Reconciliation of Carrying Amount of Real Estate Investments [Roll Forward]
Land Inventory Beginning Balance	86.0	86.0
Deeds to Collateralized Property	0.5	1.8
Land Impairment	0	(1.7)
Cost of Sales	(0.2)	(0.3)
Capitalized Improvements and Other	0.2	0.2
Land Inventory Ending Balance	86.5	86.0	86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4	2.0
Other	3.2	3.3
Total Real Estate Assets	91.1	91.3
Long-Term Finance Receivables, Allowance	$ 0.6	$ 0.6

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Operations and Significant Accounting Policies - Minnesota Land Acres (Details) (Investments and Other [Member])	Dec. 31, 2012
Investments and Other [Member]
Business Segments [Line Items]
Number of acres of land in Minnesota (in acres)	6,100

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment [Table Text Block]

Property, Plant and Equipment
As of December 31	2012			2011
Millions
Regulated Utility		$3,232.9			$2,794.8
Construction Work in Progress	151.8			155.0
Accumulated Depreciation	(1,102.8		)	(1,024.6		)
Regulated Utility Plant - Net	2,281.9			1,925.2
Non-Rate Base Energy Operations	118.0			106.4
Construction Work in Progress	4.2			2.3
Accumulated Depreciation	(56.7		)	(51.4		)
Non-Rate Base Energy Operations Plant - Net	65.5			57.3
Other Plant - Net	0.2			0.2
Property, Plant and Equipment - Net		$2,347.6			$1,982.7

Estimated Useful Lives of Property, Plant and Equipment [Table Text Block]

Estimated Useful Lives of Property, Plant and Equipment
Regulated Utility –	Generation	3 to 35 years	Non-Rate Base Operations	3 to 61 years
	Transmission	42 to 61 years	Other Plant	5 to 25 years
	Distribution	14 to 65 years

Asset Retirement Obligation [Table Text Block]

Asset Retirement Obligation
Millions
Obligation as of December 31, 2010		$50.3
Accretion Expense	6.4
Additional Liabilities Incurred in 2011	0.3
Obligation as of December 31, 2011	57.0
Accretion Expense	3.8
Additional Liabilities Incurred in 2012	17.1
Obligation as of December 31, 2012		$77.9

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Jointly-Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2012

Jointly-Owned Facilities [Abstract]

Jointly-Owned Facilities [Table Text Block]

Following are our investments in jointly-owned facilities and the related ownership percentages as of December 31, 2012:

Regulated Utility Plant	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
Boswell Unit 4		$413.1		$188.1		$25.0	80
CapX2020	22.8		0.4		25.4		9.3 - 14.7
Total		$435.9		$188.5		$50.4

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Consolidated Statement of Shareholders' Equity (USD $) In Millions, unless otherwise specified	Total	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Unearned ESOP Shares	Common Stock
Balance at Dec. 31, 2009	$ 929.5	$ 385.4	$ (24.0)	$ (45.3)	$ 613.4
Comprehensive Income
Net Income	74.8	74.8
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	0.8		0.8
Unrealized Loss on Derivatives - Net	0
Defined Benefit Pension and Other Postretirement Plans - Net	0
Total Comprehensive Income	75.6
Non-Controlling Interest in Subsidiaries	0.5	0.5
Comprehensive Income Attributable to ALLETE	76.1
Common Stock Issued - Net	22.7				22.7
Dividends Declared	(60.8)	(60.8)
ESOP Shares Earned	8.5			8.5
Balance at Dec. 31, 2010	976.0	399.9	(23.2)	(36.8)	636.1
Comprehensive Income
Net Income	93.6	93.6
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	(0.3)		(0.3)
Unrealized Loss on Derivatives - Net	(0.3)		(0.3)
Defined Benefit Pension and Other Postretirement Plans - Net	(5.1)		(5.1)
Total Comprehensive Income	87.9
Non-Controlling Interest in Subsidiaries	0.2	0.2
Comprehensive Income Attributable to ALLETE	88.1
Common Stock Issued - Net	69.5				69.5
Dividends Declared	(62.1)	(62.1)
ESOP Shares Earned	7.8			7.8
Balance at Dec. 31, 2011	1,079.3	431.6	(28.9)	(29.0)	705.6
Comprehensive Income
Net Income	97.1	97.1
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	1.2		1.2
Unrealized Loss on Derivatives - Net	(0.2)		(0.2)
Defined Benefit Pension and Other Postretirement Plans - Net	5.9		5.9
Total Comprehensive Income	104.0
Non-Controlling Interest in Subsidiaries	0
Comprehensive Income Attributable to ALLETE	104.0
Common Stock Issued - Net	79.1				79.1
Dividends Declared	(69.1)	(69.1)
ESOP Shares Earned	7.7			7.7
Balance at Dec. 31, 2012	$ 1,201.0	$ 459.6	$ (22.0)	$ (21.3)	$ 784.7

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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2012

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]

Regulatory Assets and Liabilities
As of December 31	2012		2011
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.5		$17.5
Total Current Regulatory Assets	22.5		17.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans	260.7		292.8
Income Taxes	36.0		28.6
Asset Retirement Obligation	12.1		9.8
Cost Recovery Riders (b)	18.5		0.7
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	4.3		4.6
Other	3.7		4.4
Total Non-Current Regulatory Assets	340.3		345.9
Total Regulatory Assets		$362.8		$363.4
Non-Current Regulatory Liabilities
Income Taxes		$19.5		$21.9
Plant Removal Obligations	18.1		15.0
Wholesale and Retail Contra AFUDC	15.5		1.5
Other	7.0		5.1
Total Non-Current Regulatory Liabilities		$60.1		$43.5

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

(b) The increase in cost recovery rider regulatory assets in 2012 is primarily due to revenues related to our Bison Wind Energy Center.

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Pension and Other Postretirement Benefit Plans - Unrecognized Costs (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 286.8	$ 269.0
Prior Service Cost (Credit)	0.7	1.1
Total Unrecognized Costs	287.5	270.1
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	23.5	78.5
Prior Service Cost (Credit)	(13.1)	(9.5)
Transition Obligation	0	0.1
Total Unrecognized Costs	$ 10.4	$ 69.1

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Pension and Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Defined Benefit Plan Disclosure [Line Items]

Estimated Future Benefit Payments [Table Text Block]

Estimated Future Benefit Payments
			Postretirement
	Pension		Health and Life
Millions
2013		$31.2		$7.6
2014		$32.1		$8.2
2015		$33.2		$8.9
2016		$34.4		$9.4
2017		$35.5		$9.7
Years 2018 – 2022		$189.4		$52.0

Defined Benefit Costs Recorded in Regulatory Long-Term Assets and Accumulated Other Comprehensive Income Expected to be Recognized over Next Fiscal Year [Table Text Block]

The pension and postretirement health and life costs recorded in regulatory long-term assets and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2013, are as follows:

	Pension		Postretirement Health and Life
Millions
Net Loss		$21.4		$1.6
Prior Service Cost (Credit)	0.3		(2.5		)
Total Pension and Postretirement Health and Life Cost (Credit)		$21.7	$(0.9)

Weighted-Average Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs [Table Text Block]

Weighted-Average Assumptions Used to Determine Benefit Obligation
As of December 31	2012	2011
Discount Rate
Pension	4.10%	4.54%
Postretirement Health and Life	4.13%	4.56%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%
Health Care Trend Rates
Trend Rate	9.25%	10%
Ultimate Trend Rate	5%	5%
Year Ultimate Trend Rate Effective	2019	2018

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2012	2011	2010
Discount Rate	4.54 - 4.56%	5.36 - 5.40%	5.81%
Expected Long-Term Return on Plan Assets
Pension	8.25%	8.5%	8.5%
Postretirement Health and Life	6.6 - 8.25%	6.8 - 8.5%	6.8 - 8.5%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%	4.3 - 4.6%

Plan Asset Allocations, Actual and Target [Table Text Block]

Actual Plan Asset Allocations
	Pension				Postretirement Health and Life (a)
	2012		2011		2012		2011
Equity Securities	54	%	52	%	56	%	51	%
Debt Securities	28	%	27	%	35	%	39	%
Private Equity	13	%	16	%	9	%	10	%
Real Estate	5	%	5	%	—		—
	100	%	100	%	100	%	100	%

(a) Includes VEBAs and irrevocable grantor trusts.

Plan Asset Target Allocations
			Postretirement
	Pension		Health and Life (a)
Equity Securities	52	%	48	%
Debt Securities	30	%	34	%
Real Estate	9	%	9	%
Private Equity	9	%	9	%
	100	%	100	%

(a) Includes VEBAs and irrevocable grantor trusts.

Recurring Fair Value Measures [Table Text Block]

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$18.0	—		—		$18.0
Available-for-sale Securities – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5
Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$17.6	—		—		$17.6
Available-for-sale Securities – Corporate Debt Securities	—			$8.2	—	8.2
Cash Equivalents	11.4		—		—	11.4
Total Fair Value of Assets		$29.0		$8.2	—		$37.2
Liabilities:
Deferred Compensation	—			$12.8	—		$12.8
Derivatives – Interest Rate Swap	—			$0.4	—		$0.4
Total Fair Value of Liabilities	—			$13.2	—		$13.2
Total Net Fair Value of Assets (Liabilities)		$29.0	$(5.0)		—		$24.0

Recurring Fair Value Measures - Activity in Level 3 [Table Text Block]

Recurring Fair Value Measures Activity in Level 3	Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2010		$6.7
Redeemed During the Period (a)	(6.7		)
Balance as of December 31, 2011		$—

(a) The ARS were redeemed at carrying value on January 5, 2011.

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]

Pension Obligation and Funded Status
Year Ended December 31	2012			2011
Millions
Accumulated Benefit Obligation		$598.7			$550.6
Change in Benefit Obligation
Obligation, Beginning of Year		$597.5			$525.6
Service Cost	9.1			7.6
Interest Cost	26.4			27.4
Actuarial Loss	38.5			54.6
Benefits Paid	(30.9		)	(28.6		)
Participant Contributions	11.5			10.9
Obligation, End of Year		$652.1			$597.5
Change in Plan Assets
Fair Value, Beginning of Year		$432.4			$382.0
Actual Return on Plan Assets	38.7			33.2
Employer Contribution	19.9			45.8
Benefits Paid	(30.9		)	(28.6		)
Fair Value, End of Year		$460.1			$432.4
Funded Status, End of Year	$(192.0)			$(165.1)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(190.9)			$(164.0)

Unrecognized Benefit Costs [Table Text Block]

The pension costs that are reported as a component within our Consolidated Balance Sheet, reflected in long-term regulatory assets and accumulated other comprehensive income, consist of the following:

Unrecognized Pension Costs
Year Ended December 31	2012		2011
Millions
Net Loss		$286.8		$269.0
Prior Service Cost	0.7		1.1
Total Unrecognized Pension Costs		$287.5		$270.1

Components of Net Periodic Expense [Table Text Block]

Components of Net Periodic Pension Expense
Year Ended December 31	2012			2011			2010
Millions
Service Cost		$9.1			$7.6			$6.2
Interest Cost	26.4			27.4			26.2
Expected Return on Plan Assets	(35.4		)	(34.6		)	(33.7		)
Amortization of Loss	17.5			12.1			6.6
Amortization of Prior Service Cost	0.3			0.3			0.5
Net Pension Expense		$17.9			$12.8			$5.8

Other Changes in Defined Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets [Table Text Block]

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2012			2011
Millions
Net Loss		$35.2			$56.1
Amortization of Prior Service Cost	(0.3		)	(0.3		)
Amortization of Loss	(17.5		)	(12.2		)
Total Recognized in Other Comprehensive Income and Regulatory Assets		$17.4			$43.6

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets [Table Text Block]

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 31	2012		2011
Millions
Projected Benefit Obligation		$652.1		$597.5
Accumulated Benefit Obligation		$598.7		$550.6
Fair Value of Plan Assets		$460.1		$432.4

Recurring Fair Value Measures [Table Text Block]

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$43.0		$36.0	—			$79.0
U.S. Mid-cap Growth (a)	18.3		15.3		—		33.6
U.S. Small-cap (a)	18.3		15.3		—		33.6
International	50.5		45.9		—		96.4
Debt Securities:
Mutual Funds	72.5		—		—		72.5
Fixed Income	10.4		50.8		—		61.2
Other Types of Investments:
Private Equity Funds	—		—			$58.9	58.9
Real Estate	—		—		24.9		24.9
Total Fair Value of Assets		$213.0		$163.3		$83.8		$460.1

(a) The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$37.3	—			$69.4
U.S. Mid-cap Growth (a)	13.5		15.8		—		29.3
U.S. Small-cap (a)	13.1		15.2		—		28.3
International	—		75.1		—		75.1
ALLETE	21.3		—		—		21.3
Debt Securities:
Mutual Funds	72.8		—		—		72.8
Fixed Income	—		45.5		—		45.5
Other Types of Investments:
Private Equity Funds	—		—			$69.0	69.0
Real Estate	—		—		21.7		21.7
Total Fair Value of Assets		$152.8		$188.9		$90.7		$432.4

(a) The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

Recurring Fair Value Measures - Activity in Level 3 [Table Text Block]

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2011		$69.0			$21.7
Actual Return on Plan Assets	(9.7		)	3.4
Purchases, sales, and settlements, net	(0.4		)	(0.2		)
Balance as of December 31, 2012		$58.9			$24.9

Recurring Fair Value Measures
Activity in Level 3	Equity Securities (ARS)			Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2010		$6.7			$50.7			$20.1
Actual Return on Plan Assets	—			30.9			3.5
Purchases, sales, and settlements, net	(6.7		)	(12.6		)	(1.9		)
Balance as of December 31, 2011	—				$69.0			$21.7

Postretirement Health and Life [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]

Postretirement Health and Life Obligation and Funded Status
Year Ended December 31	2012			2011
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$210.6			$204.1
Service Cost	4.2			3.8
Interest Cost	9.4			10.8
Actuarial Gain	(43.2		)	(2.9		)
Participant Contributions	2.6			2.5
Plan Amendments	(5.3		)	—
Benefits Paid	(9.5		)	(7.7		)
Obligation, End of Year		$168.8			$210.6
Change in Plan Assets
Fair Value, Beginning of Year		$121.0			$114.7
Actual Return on Plan Assets	14.3			—
Employer Contribution	2.3			11.4
Participant Contributions	2.5			2.5
Benefits Paid	(9.1		)	(7.6		)
Fair Value, End of Year		$131.0			$121.0
Funded Status, End of Year	$(37.8)			$(89.6)
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(0.8)			$(0.9)
Non-Current Liabilities	$(37.0)			$(88.7)

Unrecognized Benefit Costs [Table Text Block]

The postretirement health and life costs that are reported as a component within our Consolidated Balance Sheet, reflected in regulatory long-term assets and accumulated other comprehensive income, consist of the following:

Unrecognized Postretirement Health and Life Costs
Year Ended December 31	2012			2011
Millions
Net Loss		$23.5			$78.5
Prior Service Credit	(13.1		)	(9.5		)
Transition Obligation	—			0.1
Total Unrecognized Postretirement Health and Life Costs		$10.4			$69.1

Components of Net Periodic Expense [Table Text Block]

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2012			2011			2010
Millions
Service Cost		$4.2			$3.8			$4.8
Interest Cost	9.4			10.8			10.9
Expected Return on Plan Assets	(9.9		)	(9.7		)	(9.5		)
Amortization of Prior Service Credit	(1.7		)	(1.7		)	(0.1		)
Amortization of Loss	7.5			8.5			4.8
Amortization of Transition Obligation	0.1			0.1			2.5
Net Postretirement Health and Life Expense		$9.6			$11.8			$13.4

Other Changes in Defined Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets [Table Text Block]

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2012		2011
Millions
Net (Gain) Loss	$(47.5)			$6.9
Prior Service Credit Arising During the Period	(5.3	)	—
Amortization of Prior Service Credit	1.7		1.7
Amortization of Transition Obligation	(0.1	)	(0.1		)
Amortization of Loss	(7.5	)	(8.5		)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(58.7)		—

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates [Table Text Block]

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent		One Percent
	Increase		Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$2.0	$(1.6)
Effect on Postretirement Health and Life Obligation		$18.2	$(15.1)

Recurring Fair Value Measures [Table Text Block]

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$16.7	—		—			$16.7
U.S. Mid-cap Growth (a)	13.2		—		—		13.2
U.S. Small-cap (a)	13.3		—		—		13.3
International	30.3		—		—		30.3
Debt Securities:
Mutual Funds	25.5		—		—		25.5
Fixed Income	0.2			$18.3	—		18.5
Other Types of Investments:
Private Equity Funds	—		—			$13.5	13.5
Total Fair Value of Assets		$99.2		$18.3		$13.5		$131.0

(a) The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$15.9	—		—			$15.9
U.S. Mid-cap Growth (a)	11.5		—		—		11.5
U.S. Small-cap (a)	11.2		—		—		11.2
International	25.1		—		—		25.1
Debt Securities:
Mutual Funds	24.1		—		—		24.1
Fixed Income	0.3			$18.9	—		19.2
Other Types of Investments:
Private Equity Funds	—		—			$14.0	14.0
Total Fair Value of Assets		$88.1		$18.9		$14.0		$121.0

(a) The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

Recurring Fair Value Measures - Activity in Level 3 [Table Text Block]

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2011		$14.0
Actual Return on Plan Assets	0.2
Purchases, sales, and settlements, net	(0.7		)
Balance as of December 31, 2012		$13.5

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2010		$12.4
Actual Return on Plan Assets	1.1
Purchases, sales, and settlements, net	0.5
Balance as of December 31, 2011		$14.0

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Regulatory Matters - The Patient Protection and Affordable Care Act of 2010 (PPACA) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Unusual or Infrequent Item [Line Items]
Deferred Income Tax Expense (Benefit)		$ 37.5	$ 35.8	$ 66.0
Non-Current Regulatory Asset		340.3	345.9
PPACA Elimination of Medicare Part D [Member]
Unusual or Infrequent Item [Line Items]
Reversal of Previously Recorded Tax Benefit		0	0	4.0
Deferred Income Tax Expense (Benefit)	2.9	0	(2.9)	0
Non-Current Regulatory Asset		$ 5.0

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Commitments, Guarantees and Contingencies - Legal Proceedings (Details) (Pending Litigation [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 20.0

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Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Cash and Cash Equivalents	$ 80.8	$ 101.1
Accounts Receivable (Less Allowance of $1.0 and $0.9)	89.0	79.7
Inventories	69.8	69.1
Prepayments and Other	33.6	27.1
Total Current Assets	273.2	277.0
Property, Plant and Equipment - Net	2,347.6	1,982.7
Regulatory Assets	340.3	345.9
Investment in ATC	107.3	98.9
Other Investments	143.5	132.3
Other Non-Current Assets	41.5	39.2
Total Assets	3,253.4	2,876.0
Current Liabilities
Accounts Payable	90.5	71.8
Accrued Taxes	30.2	26.4
Accrued Interest	15.6	12.8
Long-Term Debt Due Within One Year	84.5	5.4
Notes Payable	0	1.1
Other	62.6	45.6
Total Current Liabilities	283.4	163.1
Long-Term Debt	933.6	857.9
Deferred Income Taxes	423.8	373.6
Regulatory Liabilities	60.1	43.5
Defined Benefit Pension and Other Postretirement Benefit Plans	228.2	253.5
Other Non-Current Liabilities	123.3	105.1
Total Liabilities	2,052.4	1,796.7
Commitments and Contingencies (Note 11)
Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 39.4 and 37.5 Shares Outstanding	784.7	705.6
Unearned ESOP Shares	(21.3)	(29.0)
Accumulated Other Comprehensive Loss	(22.0)	(28.9)
Retained Earnings	459.6	431.6
Total Equity	1,201.0	1,079.3
Total Liabilities and Equity	$ 3,253.4	$ 2,876.0

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Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest - Net of Amounts Capitalized	$ 42.7		$ 43.2		$ 35.7
Cash Received During the Period for Income Taxes	0	[1]	(11.4)	[1]	(54.2)	[1]
Noncash Investing and Financing Activities [Abstract]
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment	20.2		5.9		7.5
Capitalized Asset Retirement Costs	17.1		0.3		2.8
AFUDC - Equity	5.1		2.5		4.2
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
ALLETE Common Stock Contributed to Pension Plan	0		(20.0)		0
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
ALLETE Common Stock Contributed to Pension Plan			$ 20.0

[1] Due to bonus depreciation provisions in 2009 and 2010 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and refunds were received from NOL carrybacks against prior years’ taxable income.

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Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Expense	$ 2.1	$ 1.6	$ 2.2
Income Tax Benefit	0.9	0.7	0.9
Capitalized Stock-Based Compensation Expense	0	0	0
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Expense	0	0	0.1
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Expense	1.4	1.1	1.5
Unrecognized Compensation Cost	1.3
Weighted Average Period for Recognition	1 year 8 months 12 days
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Expense	0.7	0.5	0.6
Unrecognized Compensation Cost	$ 0.6
Weighted Average Period for Recognition	1 year 8 months 12 days

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Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain (Loss) on Securities, Taxes	$ 0.8	$ (0.1)	$ 0.6
Unrealized Loss on Derivatives, Taxes	(0.1)	(0.2)	0
Defined Benefit Pension and Other Postretirement Benefit Plans, Taxes	$ 3.9	$ (3.6)	$ 0

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Employee Stock and Incentive Plans - Employee Stock Ownership Plan (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee Stock and Incentive Plans [Abstract]
ESOP Employer Loan, Description	In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our newly issued common stock. The note was refinanced in 2006 at 6 percent.
ESOP Compensation Expense	$ 7.7	$ 7.4	$ 7.1
ESOP Shares, Allocated	2.2	2.2	2.2
ESOP Shares, Unallocated	0.7	1.0	1.3
ESOP Shares, Total	2.9	3.2	3.5
Fair Value of Unallocated ESOP Shares	$ 28.7	$ 42.0	$ 48.4

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Derivatives (Details) (Interest Rate Swap [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Interest Rate Swap [Member]
Derivative [Line Items]
Percentage of Debt Hedged by Interest Rate Swap	8.00%
Interest Rate Swap Variable Rate Basis	one-month LIBOR
Interest Rate Swap Fixed Interest Rate	0.825%
Discussion of Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in value of the Swap designated as the hedging instrument will be deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the year ended December 31, 2012.
Interest Rate Swap Liability	$ (0.7)	$ (0.4)

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Employee Stock and Incentive Plans - Performance Shares and Restricted Stock Units (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Performance Shares [Member]
Number of Shares [Abstract]
As of January 1,	107,899	128,333	128,333		122,489		121,825
Granted	41,332	33,525	38,764	[1]	39,312	[1]	49,302	[1]
Awarded	18,605		(41,009)		(32,368)		0
Unearned Grant Award			(17,575)		0		(22,909)
Forfeited			(614)		(1,100)		(25,729)
As of December 31,			107,899		128,333		122,489
Weighted Average Grant Date Fair Value [Abstract]
As of January 1,	$ 40.73	$ 36.54	$ 36.54		$ 38.15		$ 41.96
Granted			$ 44.70	[1]	$ 41.00	[1]	$ 35.44	[1]
Awarded			$ 34.25		$ 48.10		$ 0.00
Unearned Grant Award			$ 34.25		$ 0.00		$ 54.50
Forfeited			$ 34.49		$ 34.35		$ 36.45
As of December 31,			$ 40.73		$ 36.54		$ 38.15
Performance Period			3 years
Grants, Grant Date Fair Value	$ 2.2	$ 1.5
Awards, Grant Date Fair Value	0.7		1.4
Restricted Stock Units [Member]
Number of Shares [Abstract]
As of January 1,	56,415	63,464	63,464		43,803		28,983
Granted	19,193	16,355	18,162	[1]	20,136	[1]	26,589	[1]
Awarded	20,939		(24,707)		(215)		(3,091)
Forfeited			(504)		(260)		(8,678)
As of December 31,			56,415		63,464		43,803
Weighted Average Grant Date Fair Value [Abstract]
As of January 1,	$ 36.61	$ 32.57	$ 32.57		$ 30.61		$ 29.41
Granted			$ 40.83	[1]	$ 36.74	[1]	$ 31.83	[1]
Awarded			$ 29.43		$ 30.30		$ 29.75
Forfeited			$ 31.80		$ 29.41		$ 30.62
As of December 31,			$ 36.61		$ 32.57		$ 30.61
Performance Period			3 years
Grants, Grant Date Fair Value	0.8	0.7
Awards, Grant Date Fair Value	$ 0.7		$ 0.7

[1] Shares granted includes accrued dividends.

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$18.0	—		—		$18.0
Available-for-sale Securities – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5
Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$17.6	—		—		$17.6
Available-for-sale Securities – Corporate Debt Securities	—			$8.2	—	8.2
Cash Equivalents	11.4		—		—	11.4
Total Fair Value of Assets		$29.0		$8.2	—		$37.2
Liabilities:
Deferred Compensation	—			$12.8	—		$12.8
Derivatives – Interest Rate Swap	—			$0.4	—		$0.4
Total Fair Value of Liabilities	—			$13.2	—		$13.2
Total Net Fair Value of Assets (Liabilities)		$29.0	$(5.0)		—		$24.0

Recurring Fair Value Measures - Activity in Level 3 [Table Text Block]

Recurring Fair Value Measures Activity in Level 3	Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2010		$6.7
Redeemed During the Period (a)	(6.7		)
Balance as of December 31, 2011		$—

(a) The ARS were redeemed at carrying value on January 5, 2011.

Financial Instruments [Table Text Block]

Financial Instruments	Carrying Amount		Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2012		$1,018.1		$1,143.7
December 31, 2011		$863.3		$966.4

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Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 MW	Dec. 31, 2011	Dec. 31, 2010
Square Butte PPA [Member]
Power Purchase Agreements [Line Items]
Generating Unit Capacity (MW)	455
Output Entitlement	50.00%
PPA Counterparty Debt Outstanding	$ 416.9
Annual Debt Service	44
Power Purchased under Long-term Contracts	67.1	61.2	55.2
Interest Expense	11.1	11.1	10.2
Minnkota PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Oliver Wind I PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Term of Contract (Years)	25
Fixed Capacity Charges	0
Oliver Wind II PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	48
Term of Contract (Years)	25
Fixed Capacity Charges	$ 0
Manitoba Hydro PPA (expires April 2015) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Manitoba Hydro PPA (expires April 2022) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MWh)	1,000,000
Manitoba Hydro PPA (expires 2035) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	250
Term of Contract (Years)	15
Transmission Line Capacity (kV)	500

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Income Tax Expense

12 Months Ended

Dec. 31, 2012

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE

Income Tax Expense
Year Ended December 31	2012			2011			2010
Millions
Current Tax Expense (Benefit)
Federal (a)	—			$1.4			$(23.0)
State (a)	$0.5			(1.6		)	1.3
Total Current Tax Expense (Benefit)	0.5			(0.2		)	(21.7		)
Deferred Tax Expense
Federal (b)	38.1			27.3			61.4
State (b)	(1.7		)	9.5			5.3
Change in Valuation Allowance (c)	2.0			(0.1		)	0.2
Investment Tax Credit Amortization	(0.9		)	(0.9		)	(0.9		)
Total Deferred Tax Expense	37.5			35.8			66.0
Total Income Tax Expense		$38.0			$35.6			$44.3

(a) For the years ended December 31, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, a federal current tax benefit was recorded as a result of tax planning initiatives and the bonus depreciation provision in the Small Business Jobs Act of 2010. The 2010 federal NOL was partially utilized by carrying it back against prior years’ income with the remainder carried forward to offset future years’ income.

(b) For the year ended December 31, 2012, the state deferred tax benefit of $1.7 million is due to state renewable tax credits earned which will be carried forward to offset future state income tax expense. The year ended December 31, 2011, included an income tax benefit for the reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and a benefit of $2.9 million related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. Included in the year ended December 31, 2010, was a charge of $4.0 million as a result of the PPACA. (See Note 5. Regulatory Matters.)

(c) For the year ending December 31, 2012, the change in the valuation allowance is due to state renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2012			2011			2010
Millions
Income Before Non-Controlling Interest and Income Taxes		$135.1			$129.2			$119.1
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$47.3			$45.2			$41.7
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	1.2			6.0			4.5
Impact of the PPACA	—			—			4.0
Deferred Accounting for Retail Portion of the PPACA	—			(2.9		)	—
2010 Rate Case Stipulation Agreement - Deferred Tax Reversal	—			(6.2		)	—
Regulatory Differences for Utility Plant	(2.2		)	(1.2		)	(2.0		)
Production Tax Credits	(7.6		)	(4.3		)	(1.6		)
Other	(0.7		)	(1.0		)	(2.3		)
Total Income Tax Expense		$38.0			$35.6			$44.3

NOTE 14. INCOME TAX EXPENSE (Continued)

The effective tax rate on income was 28.1 percent for 2012 (27.6 percent for 2011; 37.2 percent for 2010). The 2012 effective rate was primarily impacted by renewable tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above). The 2011 effective tax rate was primarily impacted by the deduction for AFUDC-Equity, the reversal of a deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, renewable tax credits, and the MPUC’s approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. The 2010 effective tax rate was primarily impacted by the PPACA eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, the deduction for AFUDC-Equity, and renewable tax credits.

Deferred Tax Assets and Liabilities
As of December 31	2012			2011
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$120.2			$132.7
Property Related	59.8			56.4
NOL Carryforwards	90.8			61.7
Tax Credit Carryforwards	28.3			12.2
Other	24.6			20.4
Gross Deferred Tax Assets	323.7			283.4
Deferred Tax Asset Valuation Allowance	(2.4		)	(0.4		)
Total Deferred Tax Assets		$321.3			$283.0
Deferred Tax Liabilities
Property Related		$577.1			$482.7
Regulatory Asset for Benefit Obligations	104.3			117.9
Unamortized Investment Tax Credits	11.9			12.8
Partnership Basis Differences	28.6			24.4
Other	30.1			24.0
Total Deferred Tax Liabilities		$752.0			$661.8
Net Deferred Income Taxes		$430.7			$378.8
Recorded as:
Net Current Deferred Tax Liabilities (a)		$6.9			$5.2
Net Long-Term Deferred Tax Liabilities	423.8			373.6
Net Deferred Income Taxes		$430.7			$378.8

(a) Included in Other Current Liabilities.

NOL and Tax Credit Carryforwards
Year Ended December 31	2012		2011
Millions
Federal NOL carryforwards (a)		$244.1		$162.0
Federal tax credit carryforwards	$16.0		$8.4
State NOL carryforwards (a) (b)	$90.6		$73.1
State tax credit carryforwards (c)	$10.3		$3.8

(a) Pretax amounts

(b) Net of $0.4 million valuation allowance.

(c) Net of $2.0 million valuation allowance.

NOTE 14. INCOME TAX EXPENSE (Continued)

In 2012, we generated federal and various state NOLs and tax credit carryforwards primarily due to the bonus depreciation provisions of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 federal NOL will be utilized by carrying it forward to offset future years’ income. The federal NOL and tax credit carryforward periods expire between 2019 and 2032; included in the federal NOL carryforward are charitable contribution carryforwards which expire between 2014 and 2016. We expect to fully utilize the federal NOL, charitable contributions, and federal tax credit carryforwards; therefore no valuation allowance has been recognized as of December 31, 2012.

The state NOLs and tax credits will be carried forward to future tax years. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration. The state NOL and tax credit carryforward periods expire between 2024 and 2032; included in the state NOL carryforwards are charitable contribution carryforwards which expire between 2014 and 2016.

Gross Unrecognized Income Tax Benefits	2012			2011			2010
Millions
Balance at January 1		$11.4			$12.3			$9.5
Reductions for Tax Positions Related to the Current Year	—			—			(0.2		)
Additions for Tax Positions Related to Prior Years	—			—			4.4
Reductions for Tax Positions Related to Prior Years	(8.7		)	(0.9		)	—
Reductions for Settlements	—			—			(0.3		)
Reductions for Expired Statute of Limitations	—			—			(1.1		)
Balance as of December 31		$2.7			$11.4			$12.3

Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The gross unrecognized tax benefits as of December 31, 2012, includes $0.5 million of net unrecognized tax benefits that, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $8.7 million in 2012 was due to the removal of our uncertain tax position for our tax accounting method change for deductible repairs. During 2012, the IRS issued a directive from its Large Business and International Division to its local examination teams that led to the removal of the repairs uncertain tax position in 2012.

As of December 31, 2012, we had $0.5 million ($1.1 million for 2011 and $0.7 million for 2010) of accrued interest related to unrecognized tax benefits included in our Consolidated Balance Sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in our Consolidated Statement of Income. In 2012, we recognized a $0.6 million decrease in interest expense (interest expense of $0.4 million for 2011 and a reduction of interest expense of $0.2 million for 2010). There were no penalties recognized in 2012, 2011 or 2010.

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE is currently under examination by the IRS for the tax years 2005 through 2009. ALLETE is no longer subject to federal or state examination for years before 2005.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $2.5 million due to statute expirations and anticipated audit settlements. This amount is primarily due to temporary tax positions.

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Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Short-Term and Long-Term Debt [Abstract]

Long-term Debt [Table Text Block]

Long-Term Debt
As of December 31	2012		2011
Millions
First Mortgage Bonds
4.86% Series Due 2013		$60.0		$60.0
6.94% Series Due 2014	18.0		18.0
7.70% Series Due 2016	20.0		20.0
8.17% Series Due 2019	42.0		42.0
5.28% Series Due 2020	35.0		35.0
4.85% Series Due 2021	15.0		15.0
4.95% Pollution Control Series F Due 2022	111.0		111.0
6.02% Series Due 2023	75.0		75.0
4.90% Series Due 2025	30.0		30.0
5.10% Series Due 2025	30.0		30.0
3.20% Series Due 2026	75.0		—
5.99% Series Due 2027	60.0		60.0
5.69% Series Due 2036	50.0		50.0
6.00% Series Due 2040	35.0		35.0
5.82% Series Due 2040	45.0		45.0
4.08% Series Due 2042	85.0		—
SWL&P First Mortgage Bonds 7.25% Series Due 2013	10.0		10.0
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013 – 2020	27.5		28.2
Industrial Development Revenue Bonds 6.5% Due 2025	—		6.0
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025	27.8		27.8
Unsecured Term Loan Variable Rate Due 2014	75.0		75.0
Other Long-Term Debt, 1.0% – 8.0% Due 2013 – 2037	41.8		40.3
Total Long-Term Debt	1,018.1		863.3
Less: Due Within One Year	84.5		5.4
Net Long-Term Debt		$933.6		$857.9

On July 2, 2012, we issued $160.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in two series as follows:

Issue Date	Maturity Date	Principal Amount	Interest Rate
July 2, 2012	July 15, 2026	$75 Million	3.20%
July 2, 2012	July 15, 2042	$85 Million	4.08%

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Employee Stock and Incentive Plans - Stock Options, Range of Exercise Price (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
$23.79 to $26.91 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise Price Range, Lower Range Limit	$ 23.79
Exercise Price Range, Upper Range Limit	$ 26.91
Number Outstanding	1,340
Weighted Average Remaining Contractual Term (in Years)	1 month 6 days
Weighted Average Exercise Price	$ 23.79
Number Exercisable	1,340
Weighted Average Remaining Contractual Term (in Years)	1 month 6 days
Weighted Average Exercise Price	$ 23.79
$37.76 to $41.35 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise Price Range, Lower Range Limit	$ 37.76
Exercise Price Range, Upper Range Limit	$ 41.35
Number Outstanding	236,052
Weighted Average Remaining Contractual Term (in Years)	3 years 6 months
Weighted Average Exercise Price	$ 39.64
Number Exercisable	236,052
Weighted Average Remaining Contractual Term (in Years)	3 years 6 months
Weighted Average Exercise Price	$ 39.64
$44.15 to $48.65 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise Price Range, Lower Range Limit	$ 44.15
Exercise Price Range, Upper Range Limit	$ 48.65
Number Outstanding	158,286
Weighted Average Remaining Contractual Term (in Years)	3 years 7 months 6 days
Weighted Average Exercise Price	$ 46.38
Number Exercisable	158,286
Weighted Average Remaining Contractual Term (in Years)	3 years 7 months 6 days
Weighted Average Exercise Price	$ 46.38

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Employee Stock and Incentive Plans

12 Months Ended

Dec. 31, 2012

Employee Stock and Incentive Plans [Abstract]

Employee Stock and Incentive Plans [Text Block]

EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor a leveraged ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire. In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our newly issued common stock. The note was refinanced in 2006 at 6 percent. We make annual contributions to the ESOP equal to the ESOP’s debt service less available dividends received by the ESOP. The majority of dividends received by the ESOP are used to pay debt service, with the balance distributed to participants. The ESOP shares were initially pledged as collateral for the debt. As the debt is repaid, shares are released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares are released from collateral, we report compensation expense equal to the current market price of the shares less dividends on allocated shares. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings; available dividends on unallocated ESOP shares are recorded as a reduction of debt and accrued interest. ESOP compensation expense was $7.7 million in 2012 ($7.4 million in 2011; $7.1 million in 2010).

According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.

Year Ended December 31	2012		2011		2010
Millions
ESOP Shares
Allocated	2.2		2.2		2.2
Unallocated	0.7		1.0		1.3
Total	2.9		3.2		3.5
Fair Value of Unallocated Shares		$28.7		$42.0		$48.4

Stock-Based Compensation.Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, stock appreciation rights and other awards. There are 1.2 million shares of common stock reserved for issuance under the Executive Plan, with 0.6 million of these shares available for issuance as of December 31, 2012.

We had a Director Long-Term Stock Incentive Plan (Director Plan) which expired on January 1, 2006. No grants have been made since 2003 under the Director Plan. The 1,293 remaining options outstanding at December 31, 2011, were exercised during 2012. There were no options outstanding under the Director Plan at December 31, 2012.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

We currently have the following types of share-based awards outstanding:

Non-Qualified Stock Options. These options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to three months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are canceled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is retirement eligible. Stock options have not been granted under our Executive Plan since 2008.

The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the grant date. Expected volatility is estimated based on the historic volatility of our stock and the stock of our peer group companies. We utilize historical option exercise and employee pre-vesting termination data to estimate the option life. The dividend growth rate is based upon historical growth rates in our dividends.

Performance Shares. Under the performance share awards plan, the number of shares earned is contingent upon attaining specific market goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies. In the case of qualified retirement, death or disability during a performance period, a pro rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is determined by the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients.

Restricted Stock Units. Under the restricted stock units plan, shares for retirement eligible participants vest monthly over a three-year period. For non-retirement eligible participants, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients.

Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price. Because the discount is not greater than 5 percent, we are not required to apply fair value accounting to these awards.

RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.

The following share-based compensation expense amounts were recognized in our Consolidated Statement of Income for the periods presented.

Share-Based Compensation Expense
Year Ended December 31	2012		2011		2010
Millions
Stock Options	—		—			$0.1
Performance Shares		$1.4		$1.1	1.5
Restricted Stock Units	0.7		0.5		0.6
Total Share-Based Compensation Expense		$2.1		$1.6		$2.2
Income Tax Benefit		$0.9		$0.7		$0.9

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized stock-based compensation costs at December 31, 2012, 2011, or 2010.

As of December 31, 2012, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $1.3 million and $0.6 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years for performance share awards and 1.7 years for restricted stock units.

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options as of December 31, 2012.

	2012			2011			2010
	Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price
Outstanding as of January 1,	460,234		$41.68	560,887		$40.69	646,235		$40.05
Granted (a)	—	—		—	—		—	—
Exercised	49,075		$35.84	80,798		$34.25	40,769		$27.76
Forfeited	15,481		$44.86	19,855		$43.96	44,579		$43.16
Outstanding as of December 31,	395,678		$42.28	460,234		$41.68	560,887		$40.69
Exercisable as of December 31,	395,678		$41.71	460,234		$41.59	523,491		$39.76

(a) Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Cash received from non-qualified stock options exercised was less than $0.1 million in 2012. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.3 million during 2012 ($0.5 million in 2011; $0.3 million in 2010).

	Range of Exercise Price
As of December 31, 2012	$23.79 to $26.91		$37.76 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	1,340		236,052		158,286
Weighted Average Remaining Contractual Life (Years)	0.1		3.5		3.6
Weighted Average Exercise Price		$23.79		$39.64		$46.38

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2012.

	2012				2011				2010
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Non-vested as of January 1,	128,333			$36.54	122,489			$38.15	121,825			$41.96
Granted (a)	38,764			$44.70	39,312			$41.00	49,302			$35.44
Awarded	(41,009	)		$34.25	(32,368	)		$48.10	—		—
Unearned Grant Award	(17,575	)		$34.25	—		—		(22,909	)		$54.50
Forfeited	(614	)		$34.49	(1,100	)		$34.35	(25,729	)		$36.45
Non-vested as of December 31,	107,899			$40.73	128,333			$36.54	122,489			$38.15

(a)    Shares granted includes accrued dividends.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were 33,525 and 41,332 performance shares granted in January 2012 and 2013, for the three-year performance periods ending in 2014 and 2015, respectively. The ultimate issuance is contingent upon the attainment of certain future market goals of ALLETE during the performance periods. The grant date fair value of the performance shares granted was $1.5 million and $2.2 million, respectively.

There were 41,009 and 18,605 performance shares awarded in February 2012 and 2013, for the three-year performance periods ending in 2011 and 2012, respectively. The grant date fair value of the shares awarded was $1.4 million and $0.7 million, respectively.

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2012.

	2012				2011				2010
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Available as of January 1,	63,464			$32.57	43,803			$30.61	28,983			$29.41
Granted (a)	18,162			$40.83	20,136			$36.74	26,589			$31.83
Awarded	(24,707	)		$29.43	(215	)		$30.30	(3,091	)		$29.75
Forfeited	(504	)		$31.80	(260	)		$29.41	(8,678	)		$30.62
Available as of December 31,	56,415			$36.61	63,464			$32.57	43,803			$30.61

(a)    Shares granted includes accrued dividends.

There were 16,355 and 19,193 restricted stock units granted in January 2012 and 2013, for the vesting periods ending in 2014 and 2015, respectively. The grant date fair value of the restricted stock units granted was $0.7 million and $0.8 million, respectively.

There were 24,707 restricted stock units awarded in 2012. The grant date fair value of the shares awarded was $0.7 million.

There were 20,939 restricted stock units awarded in February 2013. The grant date fair value of the shares awarded was $0.7 million.

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Commitments, Guarantees and Contingencies - Leasing Agreements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Leasing Agreements [Line Items]
Operating Leases, Future Minimum Payments, Current	$ 11.5
Operating Leases, Future Minimum Payments, Due in Two Years	11.7
Operating Leases, Future Minimum Payments, Due in Three Years	11.4
Operating Leases, Future Minimum Payments, Due in Four Years	9.3
Operating Leases, Future Minimum Payments, Due in Five Years	8.5
Operating Leases, Future Minimum Payments, Due Thereafter	35.0
Operating Leases, Rent Expense	11.5	9.4	9.4
BNI Dragline [Member]
Leasing Agreements [Line Items]
Termination Fee	3.0
Operating Leases, Future Minimum Payments, Current	$ 2.8

XML

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Activities
Net Income	$ 97.1	$ 93.6	$ 74.8
Allowance for Funds Used During Construction - Equity	(5.1)	(2.5)	(4.2)
Income from Equity Investments, Net of Dividends	(3.7)	(3.2)	(3.1)
Gain on Real Estate Foreclosure	0	(0.5)	(0.7)
Loss (Gain) on Sale of Assets	0.2	(0.9)	0
Loss on Impairment of Assets	0	1.7	0
Depreciation Expense	100.2	90.4	80.5
Amortization of Debt Issuance Costs	1.0	0.9	0.9
Deferred Income Tax Expense	37.5	35.8	66.0
Share-Based Compensation Expense	2.1	1.6	2.2
ESOP Compensation Expense	7.7	7.4	7.1
Defined Benefit Pension and Other Postretirement Benefit Expense	27.5	23.6	18.0
Bad Debt Expense	1.0	1.2	1.1
Changes in Operating Assets and Liabilities
Accounts Receivable	(10.1)	18.6	17.9
Inventories	(0.7)	(9.1)	(3.0)
Prepayments and Other	(6.5)	1.5	(4.3)
Accounts Payable	(1.5)	(9.5)	5.8
Other Current Liabilities	21.8	15.4	5.2
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans	(8.8)	(24.7)	(39.3)
Changes in Regulatory and Other Non-Current Assets	(20.9)	(7.5)	4.2
Changes in Regulatory and Other Non-Current Liabilities	0.8	7.9	(0.4)
Cash from Operating Activities	239.6	241.7	228.7
Investing Activities
Proceeds from Sale of Available-for-sale Securities	1.5	7.8	0.6
Payments for Purchase of Available-for-sale Securities	(1.8)	(2.3)	(2.3)
Investment in ATC	(4.7)	(2.0)	(1.6)
Changes to Other Investments	(9.6)	(7.4)	1.3
Additions to Property, Plant and Equipment	(405.8)	(239.2)	(248.9)
Proceeds from Sale of Assets	0.3	2.2	0
Cash for Investing Activities	(420.1)	(240.9)	(250.9)
Financing Activities
Proceeds from Issuance of Common Stock	77.0	39.1	20.5
Proceeds from Issuance of Long-Term Debt	180.6	81.4	155.0
Changes in Notes Payable	(1.1)	0.1	(0.9)
Reductions of Long-Term Debt	(25.9)	(3.1)	(71.0)
Debt Issuance Costs	(1.3)	0	(1.4)
Dividends on Common Stock	(69.1)	(62.1)	(60.8)
Cash from Financing Activities	160.2	55.4	41.4
Change in Cash and Cash Equivalents	(20.3)	56.2	19.2
Cash and Cash Equivalents at Beginning of Period	101.1	44.9	25.7
Cash and Cash Equivalents at End of Period	$ 80.8	$ 101.1	$ 44.9

XML

Consolidated Balance Sheet Parentheticals (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.0	$ 0.9
Common Stock [Abstract]
Common Stock, Par Value	$ 0	$ 0
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	39.4	37.5

XML

Fair Value

12 Months Ended

Dec. 31, 2012

Fair Value [Abstract]

Fair Value [Text Block]

FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

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

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

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 December 31, 2012 and December 31, 2011. 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, which may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the tables below.

NOTE 9. FAIR VALUE (Continued)

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$18.0	—		—		$18.0
Available-for-sale Securities – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5
Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

There was no activity in Level 3 during the year ended December 31, 2012.

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$17.6	—		—		$17.6
Available-for-sale Securities – Corporate Debt Securities	—			$8.2	—	8.2
Cash Equivalents	11.4		—		—	11.4
Total Fair Value of Assets		$29.0		$8.2	—		$37.2
Liabilities:
Deferred Compensation	—			$12.8	—		$12.8
Derivatives – Interest Rate Swap	—			$0.4	—		$0.4
Total Fair Value of Liabilities	—			$13.2	—		$13.2
Total Net Fair Value of Assets (Liabilities)		$29.0	$(5.0)		—		$24.0

Recurring Fair Value Measures Activity in Level 3	Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2010		$6.7
Redeemed During the Period (a)	(6.7		)
Balance as of December 31, 2011		$—

(a) The ARS were redeemed at carrying value on January 5, 2011.

The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. For the years ended December 31, 2012 and 2011, there were no transfers in or out of Levels 1, 2 or 3.

NOTE 9. FAIR VALUE (Continued)

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

Financial Instruments	Carrying Amount		Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2012		$1,018.1		$1,143.7
December 31, 2011		$863.3		$966.4

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Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures, Activity in Level 3 (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension [Member] | Equity Securities (ARS) [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance		$ 6.7
Actual Return on Plan Assets		0
Purchases, sales and settlements, net		(6.7)
Ending Balance		0
Pension [Member] | Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	69.0	50.7
Actual Return on Plan Assets	(9.7)	30.9
Purchases, sales and settlements, net	(0.4)	(12.6)
Ending Balance	58.9	69.0
Pension [Member] | Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	21.7	20.1
Actual Return on Plan Assets	3.4	3.5
Purchases, sales and settlements, net	(0.2)	(1.9)
Ending Balance	24.9	21.7
Postretirement Health and Life [Member] | Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	14.0	12.4
Actual Return on Plan Assets	0.2	1.1
Purchases, sales and settlements, net	(0.7)	0.5
Ending Balance	$ 13.5	$ 14.0

XML

Pension and Other Postretirement Benefit Plans - Plan Asset Allocations (Details)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plans, Company Stock Contributed (in Shares)			500,000
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	100.00%		100.00%
Defined Benefit Plans, Company Stock Contributed (in Shares)	0
Target Plan Asset Allocation	100.00%
Pension [Member] | Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	54.00%		52.00%
Target Plan Asset Allocation	52.00%
Pension [Member] | Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	28.00%		27.00%
Target Plan Asset Allocation	30.00%
Pension [Member] | Real Estate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	5.00%		5.00%
Target Plan Asset Allocation	9.00%
Pension [Member] | Private Equity [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	13.00%		16.00%
Target Plan Asset Allocation	9.00%
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	100.00%	[1]	100.00%	[1]
Target Plan Asset Allocation	100.00%	[1]
Postretirement Health and Life [Member] | Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	56.00%	[1]	51.00%	[1]
Target Plan Asset Allocation	48.00%	[1]
Postretirement Health and Life [Member] | Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	35.00%	[1]	39.00%	[1]
Target Plan Asset Allocation	34.00%	[1]
Postretirement Health and Life [Member] | Real Estate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	0.00%	[1]	0.00%	[1]
Target Plan Asset Allocation	9.00%	[1]
Postretirement Health and Life [Member] | Private Equity [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocation	9.00%	[1]	10.00%	[1]
Target Plan Asset Allocation	9.00%	[1]

[1] Includes VEBAs and irrevocable grantor trusts.

XML

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2012	Feb. 01, 2013	Jun. 30, 2012
Document Information [Line Items]
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,591,836,880
Entity Common Stock, Shares Outstanding		39,468,463
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012

XML

Short-term and Long-term Debt

12 Months Ended

Dec. 31, 2012

Short-Term and Long-Term Debt [Abstract]

Short-Term and Long-Term Debt [Text Block]

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. Total short-term debt outstanding as of December 31, 2012, was $84.5 million ($6.5 million at December 31, 2011) and consisted of long-term debt due within one year and notes payable. As of December 31, 2012, short-term debt increased from December 31, 2011, primarily due to $60.0 million of long-term debt maturing in April 2013.

As of December 31, 2012, we had bank lines of credit aggregating $406.4 million ($256.4 million at December 31, 2011), of which $150.0 million expires in January 2014, and $250.0 million expires in June 2015. These bank lines of credit are available to provide short-term bank loans and liquidity support for ALLETE’s commercial paper program and to issue up to $50.0 million in letters of credit. We had no outstanding draws on our lines of credit as of December 31, 2012 ($1.1 million at December 31, 2011).

On February 1, 2012, ALLETE entered into a $150.0 million credit agreement (Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and several other lenders that are parties thereto. The Agreement is unsecured and has a maturity date of January 31, 2014, which may be extended for one year, subject to bank approvals. Advances under the Agreement may be used for general corporate purposes, to provide liquidity support for ALLETE’s commercial paper program and to issue up to $10.0 million in letters of credit.

Long-Term Debt. Total long-term debt outstanding as of December 31, 2012, was $933.6 million ($857.9 million at December 31, 2011). The aggregate amount of long-term debt maturing during 2013 is $84.5 million ($94.8 million in 2014; $17.4 million in 2015; $21.7 million in 2016; $51.2 million in 2017; and $748.5 million thereafter). Substantially all of our electric plant is subject to the lien of the mortgage collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

On July 2, 2012, we issued $160.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in two series as follows:

Issue Date	Maturity Date	Principal Amount	Interest Rate
July 2, 2012	July 15, 2026	$75 Million	3.20%
July 2, 2012	July 15, 2042	$85 Million	4.08%

We have the option to prepay all or a portion of the 3.20 percent Bonds at our discretion at any time prior to January 15, 2026, subject to a make-whole provision, and at any time on or after January 15, 2026, at par, including, in each case, accrued and unpaid interest. We also have the option to prepay all or a portion of the 4.08 percent Bonds at our discretion at any time prior to January 15, 2042, subject to a make-whole provision, and at any time on or after January 15, 2042, at par, including, in each case, accrued and unpaid interest. The Bonds are subject to the additional terms and conditions of our utility mortgage. In July 2012, we used a portion of the proceeds from the sale of the Bonds to redeem $6.0 million of our 6.50 percent Industrial Development Revenue Bonds and to repay $14.0 million in outstanding borrowings on our $150.0 million line of credit. The remaining proceeds were used to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to certain institutional accredited investors.

NOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt
As of December 31	2012		2011
Millions
First Mortgage Bonds
4.86% Series Due 2013		$60.0		$60.0
6.94% Series Due 2014	18.0		18.0
7.70% Series Due 2016	20.0		20.0
8.17% Series Due 2019	42.0		42.0
5.28% Series Due 2020	35.0		35.0
4.85% Series Due 2021	15.0		15.0
4.95% Pollution Control Series F Due 2022	111.0		111.0
6.02% Series Due 2023	75.0		75.0
4.90% Series Due 2025	30.0		30.0
5.10% Series Due 2025	30.0		30.0
3.20% Series Due 2026	75.0		—
5.99% Series Due 2027	60.0		60.0
5.69% Series Due 2036	50.0		50.0
6.00% Series Due 2040	35.0		35.0
5.82% Series Due 2040	45.0		45.0
4.08% Series Due 2042	85.0		—
SWL&P First Mortgage Bonds 7.25% Series Due 2013	10.0		10.0
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013 – 2020	27.5		28.2
Industrial Development Revenue Bonds 6.5% Due 2025	—		6.0
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025	27.8		27.8
Unsecured Term Loan Variable Rate Due 2014	75.0		75.0
Other Long-Term Debt, 1.0% – 8.0% Due 2013 – 2037	41.8		40.3
Total Long-Term Debt	1,018.1		863.3
Less: Due Within One Year	84.5		5.4
Net Long-Term Debt		$933.6		$857.9

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 covenant requires ALLETE to maintain a ratio of its 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 December 31, 2012, our ratio was approximately 0.46 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of December 31, 2012, ALLETE was in compliance with its financial covenants.

XML

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 11.4	$ 12.3	$ 9.5
Reductions for Tax Positions Related to the Current Year	0	0	(0.2)
Additions for Tax Positions Related to Prior Years	0	0	4.4
Reduction for Tax Positions Related to Prior Years	(8.7)	(0.9)	0
Reductions for Settlements	0	0	(0.3)
Reductions for Expired Statute of Limitations	0	0	(1.1)
Balance as of December 31	2.7	11.4	12.3
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.5
Unrecognized Tax Benefits, Accrued Interest	0.5	1.1	0.7
Unrecognized Tax Benefits, Penalties	0	0	0
Unrecognized Tax Benefits, Interest Expense (Reduction)	(0.6)	0.4	(0.2)
Reasonably Possible Change in Unrecognized Tax Benefits in Next 12 Months	$ 2.5

XML

Pension and Other Postretirement Benefit Plans - Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates (Details) (Postretirement Health and Life [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Effect of One Percent Increase on Total of Postretirement Health and Life Service and Interest Cost	$ 2.0
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(1.6)
Effect of One Percent Increase on Postretirement Health and Life Obligation	18.2
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (15.1)

XML

Consilidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenue	$ 961.2	$ 928.2	$ 907.0
Operating Expenses
Fuel and Purchased Power	308.7	306.6	325.1
Operating and Maintenance	397.1	381.2	365.6
Depreciation	100.2	90.4	80.5
Total Operating Expenses	806.0	778.2	771.2
Operating Income	155.2	150.0	135.8
Other Income (Expense)
Interest Expense	(45.5)	(43.6)	(39.2)
Equity Earnings in ATC	19.4	18.4	17.9
Other	6.0	4.4	4.6
Total Other Expense	(20.1)	(20.8)	(16.7)
Income Before Non-Controlling Interest and Income Taxes	135.1	129.2	119.1
Income Tax Expense	38.0	35.6	44.3
Net Income	97.1	93.6	74.8
Less: Non-Controlling Interest in Subsidiaries	0	(0.2)	(0.5)
Net Income Attributable to ALLETE	$ 97.1	$ 93.8	$ 75.3
Average Shares of Common Stock
Basic (in shares)	37.6	35.3	34.2
Diluted (in shares)	37.6	35.4	34.3
Basic Earnings Per Share of Common Stock	$ 2.59	$ 2.66	$ 2.20
Diluted Earnings Per Share of Common Stock	$ 2.58	$ 2.65	$ 2.19
Dividends Per Share of Common Stock	$ 1.84	$ 1.78	$ 1.76

XML

Jointly-Owned Facilities

12 Months Ended

Dec. 31, 2012

Jointly-Owned Facilities [Abstract]

Jointly-Owned Facilities [Text Block]

JOINTLY-OWNED FACILITIES

Following are our investments in jointly-owned facilities and the related ownership percentages as of December 31, 2012:

Regulated Utility Plant	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
Boswell Unit 4		$413.1		$188.1		$25.0	80
CapX2020	22.8		0.4		25.4		9.3 - 14.7
Total		$435.9		$188.5		$50.4

We own 80 percent of the 585 MW Boswell Unit 4. While we operate the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which we and WPPI Energy, the owner of the remaining 20 percent of Boswell Unit 4, have equal representation and voting rights. Each of us must provide our own financing and is obligated to pay our ownership share of operating costs. Our share of direct operating expenses of Boswell Unit 4 is included in operating expense on our Consolidated Statement of Income. We are a participant in the CapX2020 initiative to ensure reliable electric transmission and distribution in the region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and investor-owned utilities. We are currently participating in three CapX2020 projects with varying ownership percentages.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
As of December 31	2012			2011
Millions
Regulated Utility		$3,232.9			$2,794.8
Construction Work in Progress	151.8			155.0
Accumulated Depreciation	(1,102.8		)	(1,024.6		)
Regulated Utility Plant - Net	2,281.9			1,925.2
Non-Rate Base Energy Operations	118.0			106.4
Construction Work in Progress	4.2			2.3
Accumulated Depreciation	(56.7		)	(51.4		)
Non-Rate Base Energy Operations Plant - Net	65.5			57.3
Other Plant - Net	0.2			0.2
Property, Plant and Equipment - Net		$2,347.6			$1,982.7

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.

Estimated Useful Lives of Property, Plant and Equipment
Regulated Utility –	Generation	3 to 35 years	Non-Rate Base Operations	3 to 61 years
	Transmission	42 to 61 years	Other Plant	5 to 25 years
	Distribution	14 to 65 years

Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction or development and/or normal operation of the asset. Asset retirement obligations (ARO) relate primarily to the decommissioning of our coal-fired and wind generating facilities and land reclamation at BNI Coal, and are included in other non-current liabilities on our Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.

Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, removal costs have not been recognized because they are considered immaterial to our consolidated financial statements.

Long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-ARO obligations. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with the guidance for AROs. (See Note 5. Regulatory Matters.)

Asset Retirement Obligation
Millions
Obligation as of December 31, 2010		$50.3
Accretion Expense	6.4
Additional Liabilities Incurred in 2011	0.3
Obligation as of December 31, 2011	57.0
Accretion Expense	3.8
Additional Liabilities Incurred in 2012	17.1
Obligation as of December 31, 2012		$77.9

XML

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2012

Pension and Other Postretirement Benefit Plans [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. In 2012, we made total contributions of $7.3 million ($33.8 million in 2011, of which $20.0 million was contributed in shares of ALLETE common stock). We also have a defined contribution pension plan covering substantially all employees. The 2012 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $7.7 million ($7.3 million for the 2011 plan year.) (See Note 12. Common Stock and Earnings Per Share and Note 16. Employee Stock and Incentive Plans).

In 2006, the non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and to close the plan to new participants. In conjunction with those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.

We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to age 55 with 10 years of participation in the plan. The postretirement health plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and an irrevocable grantor trust. In 2012, $1.5 million was contributed to the VEBAs. In 2011, we contributed $10.9 million to the VEBAs. There were no contributions made to the grantor trust in 2012 and 2011.

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 pension plans. Contributions are based on estimates and assumptions which are subject to change. We do not expect to make any contributions to the defined benefit pension plan in 2013. In January 2013, we contributed $4.8 million to the defined benefit postretirement health and life plan, of which $2.0 million was contributed to an irrevocable grantor trust and $2.8 million was contributed to the VEBAs. We do not expect to make any additional contributions to the defined benefit postretirement health and life plan in 2013.

Accounting for defined benefit pension and postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their Consolidated Balance Sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

The defined benefit pension and postretirement health and life benefit costs recognized annually by our regulated companies are expected to be recovered through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset on our Consolidated Balance Sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit costs associated with our other non-rate base operations are recognized in accumulated other comprehensive income.

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Obligation and Funded Status
Year Ended December 31	2012			2011
Millions
Accumulated Benefit Obligation		$598.7			$550.6
Change in Benefit Obligation
Obligation, Beginning of Year		$597.5			$525.6
Service Cost	9.1			7.6
Interest Cost	26.4			27.4
Actuarial Loss	38.5			54.6
Benefits Paid	(30.9		)	(28.6		)
Participant Contributions	11.5			10.9
Obligation, End of Year		$652.1			$597.5
Change in Plan Assets
Fair Value, Beginning of Year		$432.4			$382.0
Actual Return on Plan Assets	38.7			33.2
Employer Contribution	19.9			45.8
Benefits Paid	(30.9		)	(28.6		)
Fair Value, End of Year		$460.1			$432.4
Funded Status, End of Year	$(192.0)			$(165.1)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(190.9)			$(164.0)

The pension costs that are reported as a component within our Consolidated Balance Sheet, reflected in long-term regulatory assets and accumulated other comprehensive income, consist of the following:

Unrecognized Pension Costs
Year Ended December 31	2012		2011
Millions
Net Loss		$286.8		$269.0
Prior Service Cost	0.7		1.1
Total Unrecognized Pension Costs		$287.5		$270.1

Components of Net Periodic Pension Expense
Year Ended December 31	2012			2011			2010
Millions
Service Cost		$9.1			$7.6			$6.2
Interest Cost	26.4			27.4			26.2
Expected Return on Plan Assets	(35.4		)	(34.6		)	(33.7		)
Amortization of Loss	17.5			12.1			6.6
Amortization of Prior Service Cost	0.3			0.3			0.5
Net Pension Expense		$17.9			$12.8			$5.8

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2012			2011
Millions
Net Loss		$35.2			$56.1
Amortization of Prior Service Cost	(0.3		)	(0.3		)
Amortization of Loss	(17.5		)	(12.2		)
Total Recognized in Other Comprehensive Income and Regulatory Assets		$17.4			$43.6

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 31	2012		2011
Millions
Projected Benefit Obligation		$652.1		$597.5
Accumulated Benefit Obligation		$598.7		$550.6
Fair Value of Plan Assets		$460.1		$432.4

Postretirement Health and Life Obligation and Funded Status
Year Ended December 31	2012			2011
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$210.6			$204.1
Service Cost	4.2			3.8
Interest Cost	9.4			10.8
Actuarial Gain	(43.2		)	(2.9		)
Participant Contributions	2.6			2.5
Plan Amendments	(5.3		)	—
Benefits Paid	(9.5		)	(7.7		)
Obligation, End of Year		$168.8			$210.6
Change in Plan Assets
Fair Value, Beginning of Year		$121.0			$114.7
Actual Return on Plan Assets	14.3			—
Employer Contribution	2.3			11.4
Participant Contributions	2.5			2.5
Benefits Paid	(9.1		)	(7.6		)
Fair Value, End of Year		$131.0			$121.0
Funded Status, End of Year	$(37.8)			$(89.6)
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(0.8)			$(0.9)
Non-Current Liabilities	$(37.0)			$(88.7)

According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the above table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $22.1 million in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at December 31, 2012 ($20.3 million at December 31, 2011).

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

The postretirement health and life costs that are reported as a component within our Consolidated Balance Sheet, reflected in regulatory long-term assets and accumulated other comprehensive income, consist of the following:

Unrecognized Postretirement Health and Life Costs
Year Ended December 31	2012			2011
Millions
Net Loss		$23.5			$78.5
Prior Service Credit	(13.1		)	(9.5		)
Transition Obligation	—			0.1
Total Unrecognized Postretirement Health and Life Costs		$10.4			$69.1

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2012			2011			2010
Millions
Service Cost		$4.2			$3.8			$4.8
Interest Cost	9.4			10.8			10.9
Expected Return on Plan Assets	(9.9		)	(9.7		)	(9.5		)
Amortization of Prior Service Credit	(1.7		)	(1.7		)	(0.1		)
Amortization of Loss	7.5			8.5			4.8
Amortization of Transition Obligation	0.1			0.1			2.5
Net Postretirement Health and Life Expense		$9.6			$11.8			$13.4

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2012		2011
Millions
Net (Gain) Loss	$(47.5)			$6.9
Prior Service Credit Arising During the Period	(5.3	)	—
Amortization of Prior Service Credit	1.7		1.7
Amortization of Transition Obligation	(0.1	)	(0.1		)
Amortization of Loss	(7.5	)	(8.5		)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(58.7)		—

Estimated Future Benefit Payments
			Postretirement
	Pension		Health and Life
Millions
2013		$31.2		$7.6
2014		$32.1		$8.2
2015		$33.2		$8.9
2016		$34.4		$9.4
2017		$35.5		$9.7
Years 2018 – 2022		$189.4		$52.0

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

The pension and postretirement health and life costs recorded in regulatory long-term assets and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2013, are as follows:

	Pension		Postretirement Health and Life
Millions
Net Loss		$21.4		$1.6
Prior Service Cost (Credit)	0.3		(2.5		)
Total Pension and Postretirement Health and Life Cost (Credit)		$21.7	$(0.9)

Weighted-Average Assumptions Used to Determine Benefit Obligation
As of December 31	2012	2011
Discount Rate
Pension	4.10%	4.54%
Postretirement Health and Life	4.13%	4.56%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%
Health Care Trend Rates
Trend Rate	9.25%	10%
Ultimate Trend Rate	5%	5%
Year Ultimate Trend Rate Effective	2019	2018

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2012	2011	2010
Discount Rate	4.54 - 4.56%	5.36 - 5.40%	5.81%
Expected Long-Term Return on Plan Assets
Pension	8.25%	8.5%	8.5%
Postretirement Health and Life	6.6 - 8.25%	6.8 - 8.5%	6.8 - 8.5%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%	4.3 - 4.6%

In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return.

The discount rate is computed using a yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension obligation.

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent		One Percent
	Increase		Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$2.0	$(1.6)
Effect on Postretirement Health and Life Obligation		$18.2	$(15.1)

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Actual Plan Asset Allocations
	Pension				Postretirement Health and Life (a)
	2012		2011		2012		2011
Equity Securities	54	%	52	%	56	%	51	%
Debt Securities	28	%	27	%	35	%	39	%
Private Equity	13	%	16	%	9	%	10	%
Real Estate	5	%	5	%	—		—
	100	%	100	%	100	%	100	%

(a) Includes VEBAs and irrevocable grantor trusts.

There were no shares of ALLETE common stock included in pension plan equity securities at December 31, 2012 ($20.0 million, approximately 0.5 million shares, in 2011).

To achieve strong returns within managed risk, we diversify our asset portfolio to approximate the target allocations in the table below. Equity securities are diversified among domestic companies with large, mid and small market capitalizations, as well as investments in international companies. The majority of debt securities are made up of investment grade bonds.

Plan Asset Target Allocations
			Postretirement
	Pension		Health and Life (a)
Equity Securities	52	%	48	%
Debt Securities	30	%	34	%
Real Estate	9	%	9	%
Private Equity	9	%	9	%
	100	%	100	%

(a) Includes VEBAs and irrevocable grantor trusts.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes various U.S. equity securities, public mutual funds, and futures. These instruments are valued using the closing price from the applicable exchange or whose value is quoted and readily traded daily.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs. This category includes various bonds and non-public funds whose underlying investments may be level 1 or level 2 securities.

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.

Pension Fair Value

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$43.0		$36.0	—			$79.0
U.S. Mid-cap Growth (a)	18.3		15.3		—		33.6
U.S. Small-cap (a)	18.3		15.3		—		33.6
International	50.5		45.9		—		96.4
Debt Securities:
Mutual Funds	72.5		—		—		72.5
Fixed Income	10.4		50.8		—		61.2
Other Types of Investments:
Private Equity Funds	—		—			$58.9	58.9
Real Estate	—		—		24.9		24.9
Total Fair Value of Assets		$213.0		$163.3		$83.8		$460.1

(a) The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2011		$69.0			$21.7
Actual Return on Plan Assets	(9.7		)	3.4
Purchases, sales, and settlements, net	(0.4		)	(0.2		)
Balance as of December 31, 2012		$58.9			$24.9

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$37.3	—			$69.4
U.S. Mid-cap Growth (a)	13.5		15.8		—		29.3
U.S. Small-cap (a)	13.1		15.2		—		28.3
International	—		75.1		—		75.1
ALLETE	21.3		—		—		21.3
Debt Securities:
Mutual Funds	72.8		—		—		72.8
Fixed Income	—		45.5		—		45.5
Other Types of Investments:
Private Equity Funds	—		—			$69.0	69.0
Real Estate	—		—		21.7		21.7
Total Fair Value of Assets		$152.8		$188.9		$90.7		$432.4

(a) The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

Recurring Fair Value Measures
Activity in Level 3	Equity Securities (ARS)			Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2010		$6.7			$50.7			$20.1
Actual Return on Plan Assets	—			30.9			3.5
Purchases, sales, and settlements, net	(6.7		)	(12.6		)	(1.9		)
Balance as of December 31, 2011	—				$69.0			$21.7

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Postretirement Health and Life Fair Value

	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$16.7	—		—			$16.7
U.S. Mid-cap Growth (a)	13.2		—		—		13.2
U.S. Small-cap (a)	13.3		—		—		13.3
International	30.3		—		—		30.3
Debt Securities:
Mutual Funds	25.5		—		—		25.5
Fixed Income	0.2			$18.3	—		18.5
Other Types of Investments:
Private Equity Funds	—		—			$13.5	13.5
Total Fair Value of Assets		$99.2		$18.3		$13.5		$131.0

(a) The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2011		$14.0
Actual Return on Plan Assets	0.2
Purchases, sales, and settlements, net	(0.7		)
Balance as of December 31, 2012		$13.5

	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$15.9	—		—			$15.9
U.S. Mid-cap Growth (a)	11.5		—		—		11.5
U.S. Small-cap (a)	11.2		—		—		11.2
International	25.1		—		—		25.1
Debt Securities:
Mutual Funds	24.1		—		—		24.1
Fixed Income	0.3			$18.9	—		19.2
Other Types of Investments:
Private Equity Funds	—		—			$14.0	14.0
Total Fair Value of Assets		$88.1		$18.9		$14.0		$121.0

(a) The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2010		$12.4
Actual Return on Plan Assets	1.1
Purchases, sales, and settlements, net	0.5
Balance as of December 31, 2011		$14.0

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health benefit, including a prescription drug benefit, which qualifies us for a federal subsidy under the Act. The federal subsidy is reflected in the premiums charged to us by the insurance company.

XML

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments, Guarantees and Contingencies [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

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 December 31, 2012, Square Butte had total debt outstanding of $416.9 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the next five years, 2013 through 2017, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during 2012 was $67.1 million ($61.2 million in 2011; $55.2 million in 2010). 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 $11.1 million in 2012 ($11.1 million in 2011; $10.2 million in 2010). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

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

No power will be sold under the 2009 agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late 2013. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, which in turn will enable Minnesota Power the ability to transmit additional wind generation on the existing DC transmission line.

Minnkota Power PPA. On December 12, 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity over the term June 1, 2016 through May 31, 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

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

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in April 2015. Under this agreement Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

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

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and is subject to construction of additional transmission capacity between Manitoba and 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.

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

North Dakota Wind Development. 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.

Our Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity. Bison 1 is an 82 MW wind facility in North Dakota, which was completed in two phases. The first phase was completed in 2010, and the second phase was completed in January 2012. The project also included construction of a 22-mile, 230 kV transmission line. Bison 1 had a total project cost of $174.9 million through December 31, 2012, including additional costs related to land restoration and completion of remaining associated upgrades to the 250 kV DC transmission line.

The 105 MW Bison 2 and 105 MW Bison 3 wind facilities in North Dakota were completed in December 2012. Total project costs for Bison 2 and Bison 3 were $148.6 million and $149.8 million, respectively, through December 31, 2012. In September 2011 and November 2011, the MPUC approved Minnesota Power’s petitions seeking cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively.

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated with Bison 1. We anticipate filing a cost recovery petition with the MPUC in the first half of 2013 to update customer billing rates for Bison 1 and to include investments and expenditures associated with Bison 2 and Bison 3.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through 2014. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements is $51.4 million for 2013 and $0.8 million for 2014. Our minimum annual payment obligation will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is $11.5 million in 2013, $11.7 million in 2014, $11.4 million in 2015, $9.3 million in 2016, $8.5 million in 2017 and $35.0 million thereafter. Total rent and lease expense was $11.5 million in 2012 ($9.4 million in 2011; $9.4 million in 2010).

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

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

Transmission Investments. We have an approved cost recovery rider in place for certain transmission investments and expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In June 2011, we filed an updated billing factor that includes additional transmission expenditures, which we expect to be approved in the first quarter of 2013.

CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region’s transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

Minnesota Power is participating in three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. The 28-mile 345 kV line between Monticello and St. Cloud was placed into service in December 2011 and the 70-mile 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process was completed on August 12, 2012. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.

Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between $100 million and $110 million in the CapX2020 initiative through 2015. A total of $48.2 million was spent through December 31, 2012, of which $37.3 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($27.8 million as of December 31, 2011 of which $20.4 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $7.4 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Environmental Matters

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

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

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information becomes 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 heavily regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses and low NO_X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits. Resolution of the NOVs could result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to estimate the expenditures, or range of expenditures that may be required upon resolution. Any costs of installing additional pollution control equipment would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, which replaced the EPA’s 2005 CAIR. However, on August 21, 2012, a three judge panel of the District of Columbia Circuit Court of Appeals vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. The EPA and other parties to the case have until April 24, 2013, to request that the Supreme Court review the matter. The CSAPR would have required states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR did not directly require the installation of controls. Instead, the rule would have required facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would have been allocated to facilities from each state’s annual budget and would also have been able to be bought and sold.

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

Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Based on our expected generation, these emission reductions would have satisfied Minnesota Power’s SO₂ and NO_X emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2012. Minnesota Power will continue to track the EPA activity related to promulgation of a CSAPR replacement rule. We are unable to predict any additional compliance costs we might incur if the CSAPR is reinstated or if a CSAPR replacement rule is promulgated.

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

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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 on February 16, 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 they have approved Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas addressing the MATS requirements.

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. On January 9, 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released on December 21, 2012. Major sources have three years to achieve compliance with the final rule. Minnesota Power is in the process of assessing the impact of this rule on our affected units including the Hibbard Renewable Energy Center and Rapids Energy Center. Costs for complying with the final rule cannot be estimated at this time.

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

Proposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with a 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 2013.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM_2.5) standard; the annual PM_2.5 standard and the 24-hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM_2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM_2.5 standards on June 14, 2012.

On December 14, 2012, the EPA confirmed in a final rule that the current annual PM_2.5 standard, which has been in place since 1997, will be lowered, while retaining the current 24-hour PM_2.5 standard. To implement the new lower annual PM_2.5 standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects and permits must comply with the new lower standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling. To bridge the transition to the lower standard, the EPA is finalizing a grandfathering provision to ensure that projects and pending permits already underway are not unduly delayed.

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

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

In late 2011, the MPCA initiated modeling activities that included approximately 65 sources within Minnesota that emit greater than 100 tons of SO₂ per year. However, on April 12, 2012, the MPCA notified Minnesota Power that such modeling had been suspended as a result of the EPA’s announcement that the June 2013 SIP submittals would no longer require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The MPCA is awaiting updated EPA guidance and will communicate with affected sources once the MPCA has more information on how the state will meet the EPA’s SIP requirements. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.

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

• Expand our renewable energy supply;

• Provide energy conservation initiatives for our customers and engage in other demand side efforts;

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

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

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, at existing facilities that undergo major modifications and at 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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 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.

On March 28, 2012, the EPA announced its proposed rule to apply CO₂ emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The proposed NSPS apply only to new or re-powered units and were open for public comment through June 25, 2012. It is anticipated that the EPA will issue NSPS for existing fossil fuel-fired generating units in the future. We cannot predict what CO₂ control measures, if any, may be required by such NSPS.

Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. On June 26, 2012, the United States District Court for the District of Columbia upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. Comments to the permitting guidance were submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

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

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA published in the Federal Register proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes and have a design intake flow of greater than 2 million gallons per day to limit the number of aquatic organisms that are killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011 and the EPA is obligated to finalize the rule by June 27, 2013. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Steam Electric Power Generating Effluent Guidelines. In late 2009, the EPA announced that it will be reviewing and reissuing the federal effluent guidelines for steam electric stations. These are the underlying federal water discharge rules that apply to all steam electric stations. It is expected that the EPA will publish the proposed new rule in April 2013 and a final rule in 2014. As part of the review phase for this new rule, the EPA issued an Information Collection Request (ICR) in June 2010, to most thermal electric generating stations in the country, including all five of Minnesota Power’s generating stations. The ICR was completed and submitted to the EPA in September 2010, for Boswell, Laskin, Taconite Harbor, Hibbard and Rapids Energy Center. The ICR was designed to gather extensive information on the nature and extent of all water discharge and related wastewater handling at power plants. The information gathered through the ICR will form a basis for development of the eventual new rule, which could include more restrictive requirements on wastewater discharge, flue gas desulfurization, and wet ash handling operations. We are unable to predict the costs we might incur to comply with potential future water discharge regulations at this time.

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

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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. Comments on the proposed rule were due in November 2010. It is estimated that the final rule will be published in 2013. We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Other Matters

BNI Coal. As of December 31, 2012, BNI Coal had surety bonds outstanding of $29.8 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit with CoBANK ACB for an additional $2.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $32.4 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 December 31, 2012, 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, of which $0.6 million is the contractual obligation of land purchasers. 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 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 December 31, 2012, we owned 73 percent of the assessable land in the Town Center District (73 percent at December 31, 2011) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2011). At these ownership levels, our annual assessments are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20.0 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of December 31, 2012, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance coverage for any potential loss.

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

XML

Pension and Other Postretirement Benefit Plans - Components of Net Periodic Benefit Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost	$ 9.1	$ 7.6	$ 6.2
Interest Cost	26.4	27.4	26.2
Expected Return on Plan Assets	(35.4)	(34.6)	(33.7)
Amortization of Loss	17.5	12.1	6.6
Amortization of Prior Service Cost (Credit)	0.3	0.3	0.5
Net Expense	17.9	12.8	5.8
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost	4.2	3.8	4.8
Interest Cost	9.4	10.8	10.9
Expected Return on Plan Assets	(9.9)	(9.7)	(9.5)
Amortization of Loss	7.5	8.5	4.8
Amortization of Prior Service Cost (Credit)	(1.7)	(1.7)	(0.1)
Amortization of Transition Obligation	0.1	0.1	2.5
Net Expense	$ 9.6	$ 11.8	$ 13.4

XML

Investments

12 Months Ended

Dec. 31, 2012

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. At December 31, 2012, our long-term investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits, and other assets consisting primarily of cash equivalents and land in Minnesota.

Investments
As of December 31	2012		2011
Millions
ALLETE Properties		$91.1		$91.3
Available-for-sale Securities	26.8		24.7
Other	25.6		16.3
Total Investments		$143.5		$132.3

NOTE 7. INVESTMENTS (Continued)

ALLETE Properties
As of December 31	2012			2011
Millions
Land Inventory Beginning Balance		$86.0			$86.0
Deeds to Collateralized Property	0.5			1.8
Land Impairment	—			(1.7		)
Cost of Sales	(0.2		)	(0.3		)
Capitalized Improvements and Other	0.2			0.2
Land Inventory Ending Balance	86.5			86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4			2.0
Other	3.2			3.3
Total Real Estate Assets		$91.1			$91.3

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. In 2012, impairment analysis’ of estimated future undiscounted cash flows was conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. Consequently, there was no impairment recorded for the year ended December 31, 2012. For the year ended December 31, 2011, a 1.7 million impairment charge was recorded.

Long-Term Finance Receivables. As of December 31, 2012, long-term finance receivables were $1.4 million net of allowance ($2.0 million net of allowance as of December 31, 2011). The decrease is primarily the result of the transfer of properties back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term finance receivables. 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 December 31, 2012, we had allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2011).

If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. Contract purchasers may incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they may have substantially more at risk than the deposit.

Available-for-Sale Investments.We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities. Our auction rate securities of $6.7 million were redeemed at carrying value on January 5, 2011.

Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	(Loss)	Fair Value
2012	$27.4	$0.5	$(1.1)	$26.8
2011	$27.3	$0.1	$(2.7)	$24.7
2010	$27.4	$0.2	$(2.4)	$25.2

	Net	Gross Realized		Net Unrealized Gain (Loss) in Other
Year Ended December 31	Proceeds	Gain	(Loss)	Comprehensive Income
2012	$1.5	—	—	$1.2
2011	$7.8	—	—	$(0.3)
2010	$0.6	—	—	$0.8

XML

Fair Value - Recurring Fair Value Measures (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Liabilities [Abstract]
Fair Value Activity in Level 3	$ 0
Fair Value Hierarchy Transfers, All Levels	0	0
Recurring Fair Value Measures [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	18.0	17.6
Available-for-sale Securities - Corporate Debt Securities	8.8	8.2
Cash Equivalents	20.7	11.4
Total Fair Value of Assets	47.5	37.2
Liabilities [Abstract]
Deferred Compensation	14.0	12.8
Derivatives - Interest Rate Swap	0.7	0.4
Total Fair Value of Liabilities	14.7	13.2
Total Net Fair Value of Assets (Liabilities)	32.8	24.0
Recurring Fair Value Measures [Member] | Level 1 [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	18.0	17.6
Available-for-sale Securities - Corporate Debt Securities	0	0
Cash Equivalents	20.7	11.4
Total Fair Value of Assets	38.7	29.0
Liabilities [Abstract]
Deferred Compensation	0	0
Derivatives - Interest Rate Swap	0	0
Total Fair Value of Liabilities	0	0
Total Net Fair Value of Assets (Liabilities)	38.7	29.0
Recurring Fair Value Measures [Member] | Level 2 [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	0	0
Available-for-sale Securities - Corporate Debt Securities	8.8	8.2
Cash Equivalents	0	0
Total Fair Value of Assets	8.8	8.2
Liabilities [Abstract]
Deferred Compensation	14.0	12.8
Derivatives - Interest Rate Swap	0.7	0.4
Total Fair Value of Liabilities	14.7	13.2
Total Net Fair Value of Assets (Liabilities)	(5.9)	(5.0)
Recurring Fair Value Measures [Member] | Level 3 [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	0	0
Available-for-sale Securities - Corporate Debt Securities	0	0
Cash Equivalents	0	0
Total Fair Value of Assets	0	0
Liabilities [Abstract]
Deferred Compensation	0	0
Derivatives - Interest Rate Swap	0	0
Total Fair Value of Liabilities	0	0
Total Net Fair Value of Assets (Liabilities)	$ 0	$ 0

XML

Regulatory Matters

12 Months Ended

Dec. 31, 2012

Regulatory Matters [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

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

2010 Minnesota Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). On February 14, 2012, the Court granted the petition for review and oral arguments were held before the Court on October 9, 2012. A decision is expected in early 2013; however, we cannot predict the outcome at this time.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. Minnesota Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July 1, 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 City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on December 31, 2011, this customer submitted a cancellation notice with termination effective on December 31, 2013. The 17 MW of average monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in 2014.

2012 Wisconsin Rate Case.During 2012, SWL&P’s retail rates were based on a 2010 PSCW retail rate order, which was effective January 1, 2011. SWL&P’s 2013 retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, and allows for a 10.9 percent return on common equity. The new rates reflect an average overall increase of 2.4 percent for retail customers (a 13.8 percent increase in water rates, a 1.2 percent increase in electric rates, and a 2.0 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $1.7 million in additional revenue.

NOTE 5. REGULATORY MATTERS (Continued)

Rapids Energy Center. On December 19, 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill (Blandin). Minnesota Power and Blandin entered into a new electric service agreement in September 2012 which is also subject to MPUC approval. We expect a decision from the MPUC on these filings in mid-2013.

ALLETE Clean Energy. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships between the parties, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. On July 23, 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction and the Federal MATS rule. On August 31, 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be between $350 million and $400 million. The MPCA has 180 days to comment on the mercury emissions reduction plan, which then is reviewed by the MPUC for a decision. We expect a decision by the MPUC on the plan in the third quarter of 2013. After approval by the MPUC we anticipate filing a petition to include investments and expenditures in customer billing rates.

The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, the PPACA was signed into law. One of the provisions changed the tax treatment for retiree prescription drug expenses by eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, beginning January 1, 2013. Based on this provision, we are subject to additional taxes in the future and were required to reverse previously recorded tax benefits which resulted in a non-recurring charge to net income of $4.0 million in 2010. In October 2010, we submitted a filing with the MPUC requesting deferral of the retail portion of the tax charge taken in 2010 resulting from the PPACA. In May 2011, the MPUC approved our request for deferral until the next rate case and as a result we recorded an income tax benefit of $2.9 million and a related regulatory asset of $5.0 million in the second quarter of 2011.

Pension. In December 2011, the Company filed a petition with the MPUC requesting a mechanism to recover the cost of capital associated with the prepaid pension asset (or liability) created by the required contributions under the pension plan in excess of (or less than) annual pension expense. The Company further requested a mechanism to defer pension expenses in excess of (or less than) those currently being recovered in base rates. On February 14, 2013, the MPUC denied the Company's petition for recovery of the pension asset and deferral of expenses outside of a general rate case. The MPUC decision does not impact the results of operations for the year ended December 31, 2012.

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 liabilitiesrepresent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.

NOTE 5. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities
As of December 31	2012		2011
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.5		$17.5
Total Current Regulatory Assets	22.5		17.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans	260.7		292.8
Income Taxes	36.0		28.6
Asset Retirement Obligation	12.1		9.8
Cost Recovery Riders (b)	18.5		0.7
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	4.3		4.6
Other	3.7		4.4
Total Non-Current Regulatory Assets	340.3		345.9
Total Regulatory Assets		$362.8		$363.4
Non-Current Regulatory Liabilities
Income Taxes		$19.5		$21.9
Plant Removal Obligations	18.1		15.0
Wholesale and Retail Contra AFUDC	15.5		1.5
Other	7.0		5.1
Total Non-Current Regulatory Liabilities		$60.1		$43.5

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

(b) The increase in cost recovery rider regulatory assets in 2012 is primarily due to revenues related to our Bison Wind Energy Center.

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Investment in ATC

12 Months Ended

Dec. 31, 2012

Investment in ATC [Abstract]

Investment in ATC [Text Block]

INVESTMENT IN ATC

Investment in ATC. Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATC rates are FERC-approved and are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, 2012, our equity investment in ATC was $107.3 million ($98.9 million at December 31, 2011). On January 30, 2013, we invested an additional $0.4 million in ATC. In total, we expect to invest approximately $2.0 million throughout 2013.

ALLETE’s Interest in ATC
Year Ended December 31	2012			2011
Millions
Equity Investment Beginning Balance		$98.9			$93.3
Cash Investments	4.7			2.0
Equity in ATC Earnings	19.4			18.4
Distributed ATC Earnings	(15.7		)	(14.8		)
Equity Investment Ending Balance		$107.3			$98.9

NOTE 6. INVESTMENT IN ATC (Continued)

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2012		2011
Millions
Current Assets		$63.1		$58.7
Non-Current Assets	3,274.7		3,053.7
Total Assets		$3,337.8		$3,112.4
Current Liabilities		$251.5		$298.5
Long-Term Debt	1,550.0		1,400.0
Other Non-Current Liabilities	95.8		82.6
Members’ Equity	1,440.5		1,331.3
Total Liabilities and Members’ Equity		$3,337.8		$3,112.4

Income Statement Data
Year Ended December 31	2012		2011		2010
Millions
Revenue		$603.2		$567.2		$556.7
Operating Expense	281.0		261.6		251.1
Other Expense	84.8		81.7		85.9
Net Income		$237.4		$223.9		$219.7
ALLETE’s Equity in Net Income		$19.4		$18.4		$17.9

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Derivatives

12 Months Ended

Dec. 31, 2012

Derivatives [Abstract]

Derivatives [Text Block]

DERIVATIVES

During the third quarter of 2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 8 percent of the Company’s outstanding long-term debt as of December 31, 2012. (See Note 10. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting with respect to that derivative. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in value of the Swap designated as the hedging instrument will be deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the year ended December 31, 2012. The mark-to-market fluctuation on the cash flow hedge was recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. As of December 31, 2012, the fair value of the swap was a $0.7 million liability (a $0.4 million liability as of December 31, 2011) and is included in other non-current liabilities on the Consolidated Balance Sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.

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Short-term and Long-term Debt - Schedule of Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Long-term Debt	$ 1,018.1	$ 863.3
Less: Due Within One Year	84.5	5.4
Net Long-Term Debt	933.6	857.9
4.86% Series Due 2013 [Member]
Debt Instrument [Line Items]
Long-term Debt	60.0	60.0
Less: Due Within One Year	60.0
6.94% Series Due 2014 [Member]
Debt Instrument [Line Items]
Long-term Debt	18.0	18.0
7.70% Series Due 2016 [Member]
Debt Instrument [Line Items]
Long-term Debt	20.0	20.0
8.17% Series Due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt	42.0	42.0
5.28% Series Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	35.0	35.0
4.85% Series Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt	15.0	15.0
4.95% Pollution Control Series F Due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt	111.0	111.0
6.02% Series Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	75.0	75.0
4.90% Series Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	30.0	30.0
5.10% Series Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	30.0	30.0
3.20% Series Due 2026 [Member]
Debt Instrument [Line Items]
Long-term Debt	75.0	0
5.99% Series Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt	60.0	60.0
5.69% Series Due 2036 [Member]
Debt Instrument [Line Items]
Long-term Debt	50.0	50.0
6.00% Series Due 2040 [Member]
Debt Instrument [Line Items]
Long-term Debt	35.0	35.0
5.82% Series Due 2040 [Member]
Debt Instrument [Line Items]
Long-term Debt	45.0	45.0
4.08% Series Due 2042 [Member]
Debt Instrument [Line Items]
Long-term Debt	85.0	0
SWL&P First Mortgage Bonds 7.25% Series Due 2013 [Member]
Debt Instrument [Line Items]
Long-term Debt	10.0	10.0
Senior Unsecured Notes 5.99% Due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt	50.0	50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013-2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	27.5	28.2
Industrial Development Revenue Bonds 6.5% Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	0	6.0
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	27.8	27.8
Unsecured Term Loan Variable Rate Due 2014 [Member]
Debt Instrument [Line Items]
Long-term Debt	75.0	75.0
Other Long-Term Debt, 1.0%-8.0% Due 2013-2037 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 41.8	$ 40.3

XML

Pension and Other Postretirement Benefit Plans - Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ 35.2	$ 56.1
Amortization of Prior Service (Cost) Credit	(0.3)	(0.3)
Amortization of Loss	(17.5)	(12.2)
Total Recognized in Other Comprehensive Income and Regulatory Assets	17.4	43.6
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	(47.5)	6.9
Prior Service Credit Arising During the Period	(5.3)	0
Amortization of Prior Service (Cost) Credit	1.7	1.7
Amortization of Transition Obligation	(0.1)	(0.1)
Amortization of Loss	(7.5)	(8.5)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$ (58.7)	$ 0

XML

Commitments, Guarantees and Contingencies - North Dakota Wind Development (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Miles kV
DC Transmission Line from Square Butte [Member]
North Dakota Wind Development [Line Items]
Transmission Line Length (Miles)	465
Transmission Line Capacity (kV)	250
Bison Wind Energy Center [Member]
North Dakota Wind Development [Line Items]
Generating Unit Capacity (MW)	292
Bison 1 [Member]
North Dakota Wind Development [Line Items]
Transmission Line Length (Miles)	22
Transmission Line Capacity (kV)	230
Generating Unit Capacity (MW)	82
Capital Cost Spent to Date	174.9
Bison 2 [Member]
North Dakota Wind Development [Line Items]
Generating Unit Capacity (MW)	105
Capital Cost Spent to Date	148.6
Bison 3 [Member]
North Dakota Wind Development [Line Items]
Generating Unit Capacity (MW)	105
Capital Cost Spent to Date	149.8

XML

Short-Term and Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended									12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Lines of Credit [Member]	Dec. 31, 2011 Lines of Credit [Member]	Dec. 31, 2012 ALLETE LOC January 2014 [Member]	Jun. 30, 2012 ALLETE LOC January 2014 [Member]	Feb. 01, 2012 ALLETE LOC January 2014 [Member]	Dec. 31, 2012 ALLETE LOC June 2015 [Member]	Dec. 31, 2012 ALLETE Bonds 4.86% Due 2013 [Member]	Dec. 31, 2012 ALLETE Bonds 3.20% Due July 2026 [Member]	Dec. 31, 2012 ALLETE Bonds 4.08% Due July2042 [Member]	Dec. 31, 2012 Industrial Development Revenue Bonds 6.5% Due 2025 [Member]
Financial Covenants [Abstract]
Required Indebtedness to Total Capital Ratio	0.65
Actual Indebtedness to Total Capital Ratio	0.46
Maturities of Long-term Debt [Abstract]
Long-Term Debt	$ 933.6	$ 857.9
Long-Term Debt Due Within One Year	84.5	5.4							60.0
Long-Term Debt, 2014 Maturities	94.8
Long-Term Debt, 2015 Maturities	17.4
Long-Term Debt, 2016 Maturities	21.7
Long-Term Debt, 2017 Maturities	51.2
Long-Term Debt, Thereafter Maturities	748.5
Debt Instrument [Line Items]
Short-Term Debt	84.5	6.5
Line of Credit Facility, Maximum Borrowing Capacity			406.4	256.4	150.0		150.0	250.0
Letter of Credit Maximum Issuances	50.0						10.0
Lines of Credit, Current	0	1.1
Proceeds from Issuance of First Mortgage Bond	160.0									75.0	85.0
First Mortgage Bonds, Interest Rate										3.20%	4.08%	6.50%
Redemption of Bond												6.0
Line of Credit Facility, Amount Outstanding						$ 14.0

XML

Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Pension [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	$ 460.1		$ 432.4		$ 382.0
Pension [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	213.0		152.8
Pension [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	163.3		188.9
Pension [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	83.8		90.7
Pension [Member] | U.S. Large-Cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	79.0	[1]	69.4	[1]
Pension [Member] | U.S. Large-Cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	43.0	[1]	32.1	[1]
Pension [Member] | U.S. Large-Cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	36.0	[1]	37.3	[1]
Pension [Member] | U.S. Large-Cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0	[1]	0	[1]
Pension [Member] | U.S. Mid-Cap Growth [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	33.6	[1]	29.3	[1]
Pension [Member] | U.S. Mid-Cap Growth [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	18.3	[1]	13.5	[1]
Pension [Member] | U.S. Mid-Cap Growth [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	15.3	[1]	15.8	[1]
Pension [Member] | U.S. Mid-Cap Growth [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0	[1]	0	[1]
Pension [Member] | U.S. Small Cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	33.6	[1]	28.3	[1]
Pension [Member] | U.S. Small Cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	18.3	[1]	13.1	[1]
Pension [Member] | U.S. Small Cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	15.3	[1]	15.2	[1]
Pension [Member] | U.S. Small Cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0	[1]	0	[1]
Pension [Member] | International [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	96.4		75.1
Pension [Member] | International [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	50.5		0
Pension [Member] | International [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	45.9		75.1
Pension [Member] | International [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | ALLETE [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets			21.3
Pension [Member] | ALLETE [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets			21.3
Pension [Member] | ALLETE [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets			0
Pension [Member] | ALLETE [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets			0
Pension [Member] | Mutual Funds [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	72.5		72.8
Pension [Member] | Mutual Funds [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	72.5		72.8
Pension [Member] | Mutual Funds [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | Mutual Funds [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | Fixed Income [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	61.2		45.5
Pension [Member] | Fixed Income [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	10.4		0
Pension [Member] | Fixed Income [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	50.8		45.5
Pension [Member] | Fixed Income [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | Private Equity Funds [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	58.9		69.0
Pension [Member] | Private Equity Funds [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | Private Equity Funds [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | Private Equity Funds [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	58.9		69.0
Pension [Member] | Real Estate [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	24.9		21.7
Pension [Member] | Real Estate [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | Real Estate [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Pension [Member] | Real Estate [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	24.9		21.7
Postretirement Health and Life [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	131.0		121.0		114.7
Postretirement Health and Life [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	99.2		88.1
Postretirement Health and Life [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	18.3		18.9
Postretirement Health and Life [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	13.5		14.0
Postretirement Health and Life [Member] | U.S. Large-Cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	16.7		15.9
Postretirement Health and Life [Member] | U.S. Large-Cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	16.7	[2]	15.9	[2]
Postretirement Health and Life [Member] | U.S. Large-Cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | U.S. Large-Cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | U.S. Mid-Cap Growth [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	13.2		11.5
Postretirement Health and Life [Member] | U.S. Mid-Cap Growth [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	13.2	[2]	11.5	[2]
Postretirement Health and Life [Member] | U.S. Mid-Cap Growth [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | U.S. Mid-Cap Growth [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | U.S. Small Cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	13.3		11.2
Postretirement Health and Life [Member] | U.S. Small Cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	13.3	[2]	11.2	[2]
Postretirement Health and Life [Member] | U.S. Small Cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | U.S. Small Cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | International [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	30.3		25.1
Postretirement Health and Life [Member] | International [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	30.3		25.1
Postretirement Health and Life [Member] | International [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | International [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | Mutual Funds [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	25.5		24.1
Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	25.5		24.1
Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | Fixed Income [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	18.5		19.2
Postretirement Health and Life [Member] | Fixed Income [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0.2		0.3
Postretirement Health and Life [Member] | Fixed Income [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	18.3		18.9
Postretirement Health and Life [Member] | Fixed Income [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | Private Equity Funds [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	13.5		14.0
Postretirement Health and Life [Member] | Private Equity Funds [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | Private Equity Funds [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	0		0
Postretirement Health and Life [Member] | Private Equity Funds [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Plan Assets	$ 13.5		$ 14.0

[1] The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

[2] The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

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Investments (Tables)

12 Months Ended

Dec. 31, 2012

Investments [Abstract]

Investments and ALLETE Properties [Table Text Block]

Investments
As of December 31	2012		2011
Millions
ALLETE Properties		$91.1		$91.3
Available-for-sale Securities	26.8		24.7
Other	25.6		16.3
Total Investments		$143.5		$132.3

NOTE 7. INVESTMENTS (Continued)

ALLETE Properties
As of December 31	2012			2011
Millions
Land Inventory Beginning Balance		$86.0			$86.0
Deeds to Collateralized Property	0.5			1.8
Land Impairment	—			(1.7		)
Cost of Sales	(0.2		)	(0.3		)
Capitalized Improvements and Other	0.2			0.2
Land Inventory Ending Balance	86.5			86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4			2.0
Other	3.2			3.3
Total Real Estate Assets		$91.1			$91.3

Available-for-sale Securities [Table Text Block]

Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	(Loss)	Fair Value
2012	$27.4	$0.5	$(1.1)	$26.8
2011	$27.3	$0.1	$(2.7)	$24.7
2010	$27.4	$0.2	$(2.4)	$25.2

Available-for-sale Securities [Table Text Block]

	Net	Gross Realized		Net Unrealized Gain (Loss) in Other
Year Ended December 31	Proceeds	Gain	(Loss)	Comprehensive Income
2012	$1.5	—	—	$1.2
2011	$7.8	—	—	$(0.3)
2010	$0.6	—	—	$0.8

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Regulatory Matters - Electric Rates (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Municipal Customers [Member] Customers	Dec. 31, 2012 Non-Affiliated Private Utility [Member] Customers	Jun. 01, 2011 MPUC 2010 MN Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Dec. 31, 2012 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Years Customers	Dec. 31, 2012 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Non-Affiliated Private Utility [Member] Years MW Customers	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Retail Customers [Member]	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Natural Gas Rates [Member] Retail Customers [Member]	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Water Rates [Member] Retail Customers [Member]
Rate Regulation [Line Items]
Approved Rate of Return on Common Equity			10.38%			10.90%
Approved Percentage of Capital Structure Related to Equity			54.29%
Number of Customers	16	1		16	1
Length of Notice Required to Terminate (Years)				3	2
Average Monthly Demand (in MWs)					17
Approved Rate Increase or Decrease						2.40%	(2.00%)	1.20%	13.80%
Amount Of Estimated Additional Revenue						$ 1.7

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Other Income (Expense)

12 Months Ended

Dec. 31, 2012

Other Income (Expense) [Abstract]

Other Income (Expense) [Text Block]

OTHER INCOME (EXPENSE)

Year Ended December 31	2012		2011		2010
Millions
AFUDC – Equity		$5.1		$2.5		$4.2
Investment and Other Income	0.9		1.9		0.4
Total Other Income		$6.0		$4.4		$4.6

XML

Schedule II

12 Months Ended

Dec. 31, 2012

Schedule II [Abstract]

Valuation and Qualifying Accounts and Reserves [Text Block]

Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves

	Balance at Beginning of Period		Additions			Deductions from Reserves (a)		Balance at End of Period
			Charged to Income		Other Charges
Millions
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2010 Trade Accounts Receivable		$0.9		$1.1	—		$1.1		$0.9
Finance Receivables – Long-Term		$0.4		$0.8	—		$0.4		$0.8
2011 Trade Accounts Receivable		$0.9		$1.3	—		$1.3		$0.9
Finance Receivables – Long-Term		$0.8		$0.1	—		$0.3		$0.6
2012 Trade Accounts Receivable		$0.9		$1.0	—		$0.9		$1.0
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
Deferred Asset Valuation Allowance
2010 Deferred Tax Assets		$0.3	$0.2		—	—			$0.5
2011 Deferred Tax Assets		$0.5	$(0.1)		—	—			$0.4
2012 Deferred Tax Assets		$0.4		$2.0	—	—			$2.4

(a) Includes uncollectible accounts written off.

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Employee Stock and Incentive Plans - Stock-Based Compensation (Details)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants	0	[1]	0	[1]	0	[1]
Exercised	49,075		80,798		40,769
Options Outstanding	395,678		460,234		560,887		646,235
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years
Employee Stock Purchase Plan (ESPP) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ESPP Discount	5.00%
Executive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock Reserved	1,200,000
Shares Available for Issuance	600,000
Director Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants	0
Exercised	1,293
Options Outstanding	0

[1] Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

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Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment - Net	$ 2,347.6	$ 1,982.7
Asset Retirement Obligation [Roll Forward]
Beginning Obligation	57.0	50.3
Accretion Expense	3.8	6.4
Additional Liabilities Incurred	17.1	0.3	2.8
Ending Obligation	77.9	57.0	50.3
Regulated Utiity [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	3,232.9	2,794.8
Construction Work in Progress	151.8	155.0
Accumulated Depreciation	(1,102.8)	(1,024.6)
Property, Plant and Equipment - Net	2,281.9	1,925.2
Estimated Useful Life - Generation	3 to 35 years
Estimated Useful Life - Transmission	42 to 61 years
Estimated Useful Life - Distribution	14 to 65 years
Non-Rate Base Energy Operations and Other Plant [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	118.0	106.4
Construction Work in Progress	4.2	2.3
Accumulated Depreciation	(56.7)	(51.4)
Property, Plant and Equipment - Net	65.5	57.3
Other Plant - Net	$ 0.2	$ 0.2
Estimated Useful Life - Non-Rate Base Operations	3 to 61 years
Estimated Useful Life - Other Plant	5 to 25 years

XML

Employee Stock and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2012

Employee Stock and Incentive Plans [Abstract]

Employee Stock Ownership Plan [Table Text Block]

Year Ended December 31	2012		2011		2010
Millions
ESOP Shares
Allocated	2.2		2.2		2.2
Unallocated	0.7		1.0		1.3
Total	2.9		3.2		3.5
Fair Value of Unallocated Shares		$28.7		$42.0		$48.4

Share-Based Compensation Expense [Table Text Block]

The following share-based compensation expense amounts were recognized in our Consolidated Statement of Income for the periods presented.

Share-Based Compensation Expense
Year Ended December 31	2012		2011		2010
Millions
Stock Options	—		—			$0.1
Performance Shares		$1.4		$1.1	1.5
Restricted Stock Units	0.7		0.5		0.6
Total Share-Based Compensation Expense		$2.1		$1.6		$2.2
Income Tax Benefit		$0.9		$0.7		$0.9

Non-Qualified Stock Options [Table Text Block]

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options as of December 31, 2012.

	2012			2011			2010
	Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price
Outstanding as of January 1,	460,234		$41.68	560,887		$40.69	646,235		$40.05
Granted (a)	—	—		—	—		—	—
Exercised	49,075		$35.84	80,798		$34.25	40,769		$27.76
Forfeited	15,481		$44.86	19,855		$43.96	44,579		$43.16
Outstanding as of December 31,	395,678		$42.28	460,234		$41.68	560,887		$40.69
Exercisable as of December 31,	395,678		$41.71	460,234		$41.59	523,491		$39.76

(a) Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Stock Options, by Exercise Price Range [Table Text Block]

	Range of Exercise Price
As of December 31, 2012	$23.79 to $26.91		$37.76 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	1,340		236,052		158,286
Weighted Average Remaining Contractual Life (Years)	0.1		3.5		3.6
Weighted Average Exercise Price		$23.79		$39.64		$46.38

Performance Shares [Table Text Block]

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2012.

	2012				2011				2010
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Non-vested as of January 1,	128,333			$36.54	122,489			$38.15	121,825			$41.96
Granted (a)	38,764			$44.70	39,312			$41.00	49,302			$35.44
Awarded	(41,009	)		$34.25	(32,368	)		$48.10	—		—
Unearned Grant Award	(17,575	)		$34.25	—		—		(22,909	)		$54.50
Forfeited	(614	)		$34.49	(1,100	)		$34.35	(25,729	)		$36.45
Non-vested as of December 31,	107,899			$40.73	128,333			$36.54	122,489			$38.15

(a)    Shares granted includes accrued dividends.

Restricted Stock Units [Table Text Block]

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2012.

	2012				2011				2010
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Available as of January 1,	63,464			$32.57	43,803			$30.61	28,983			$29.41
Granted (a)	18,162			$40.83	20,136			$36.74	26,589			$31.83
Awarded	(24,707	)		$29.43	(215	)		$30.30	(3,091	)		$29.75
Forfeited	(504	)		$31.80	(260	)		$29.41	(8,678	)		$30.62
Available as of December 31,	56,415			$36.61	63,464			$32.57	43,803			$30.61

(a)    Shares granted includes accrued dividends.

XML

Consolidated Statement of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net Income	$ 97.1	$ 93.6	$ 74.8
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities - Net of Income Taxes of $0.8, $(0.1) and $0.6	1.2	(0.3)	0.8
Unrealized Loss on Derivatives - Net of Income Taxes of $(0.1), $(0.2) and $-	(0.2)	(0.3)	0
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Taxes of $3.9, $(3.6), and $-	5.9	(5.1)	0
Total Other Comprehensive Income (Loss)	6.9	(5.7)	0.8
Total Comprehensive Income	104.0	87.9	75.6
Less: Non-Controlling Interest in Subsidiaries	0	(0.2)	(0.5)
Comprehensive Income Attributable to ALLETE	$ 104.0	$ 88.1	$ 76.1

XML

Pension and Other Postretirement Benefit Plans - Costs Recorded in Other Long-Term Assets and AOCI Expected to be Recognized as a Component of Net Pension and Postretirement Benefit Costs in the Next Fiscal Year (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 21.4
Prior Service Cost (Credit)	0.3
Total Pension and Postretirement Health and Life Cost (Credit)	21.7
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	1.6
Prior Service Cost (Credit)	(2.5)
Total Pension and Postretirement Health and Life Cost (Credit)	$ (0.9)

XML

Business Segments

12 Months Ended

Dec. 31, 2012

Business Segments [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,100 acres of land in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.

	Consolidated			Regulated Operations			Investments and Other
Millions
2012
Operating Revenue		$961.2			$874.4			$86.8
Fuel and Purchased Power Expense	308.7			308.7			—
Operating and Maintenance Expense	397.1			310.0			87.1
Depreciation Expense	100.2			93.9			6.3
Operating Income (Loss)	155.2			161.8			(6.6		)
Interest Expense	(45.5		)	(39.8		)	(5.7		)
Equity Earnings in ATC	19.4			19.4			—
Other Income	6.0			5.1			0.9
Income (Loss) Before Non-Controlling Interest and Income Taxes	135.1			146.5			(11.4		)
Income Tax Expense (Benefit)	38.0			50.4			(12.4		)
Net Income	97.1			96.1			1.0
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE		$97.1			$96.1			$1.0
Total Assets		$3,253.4			$2,962.4			$291.0
Capital Additions		$432.2			$418.2			$14.0

NOTE 2. BUSINESS SEGMENTS (Continued)

	Consolidated			Regulated Operations			Investments and Other
Millions
2011
Operating Revenue		$928.2			$851.9			$76.3
Fuel and Purchased Power Expense	306.6			306.6			—
Operating and Maintenance Expense	381.2			301.5			79.7
Depreciation Expense	90.4			85.4			5.0
Operating Income (Loss)	150.0			158.4			(8.4		)
Interest Expense	(43.6		)	(35.8		)	(7.8		)
Equity Earnings in ATC	18.4			18.4			—
Other Income	4.4			2.6			1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	129.2			143.6			(14.4		)
Income Tax Expense (Benefit)	35.6			43.2			(7.6		)
Net Income (Loss)	93.6			100.4			(6.8		)
Less: Non-Controlling Interest in Subsidiaries	(0.2		)	—			(0.2		)
Net Income (Loss) Attributable to ALLETE		$93.8			$100.4		$(6.6)
Total Assets		$2,876.0			$2,579.8			$296.2
Capital Additions		$246.8			$228.0			$18.8

	Consolidated			Regulated Operations			Investments and Other
Millions
2010
Operating Revenue		$907.0			$835.5			$71.5
Fuel and Purchased Power Expense	325.1			325.1			—
Operating and Maintenance Expense	365.6			292.3			73.3
Depreciation Expense	80.5			76.1			4.4
Operating Income (Loss)	135.8			142.0			(6.2		)
Interest Expense	(39.2		)	(32.3		)	(6.9		)
Equity Earnings in ATC	17.9			17.9			—
Other Income	4.6			3.8			0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	119.1			131.4			(12.3		)
Income Tax Expense (Benefit)	44.3			51.6			(7.3		)
Net Income (Loss)	74.8			79.8			(5.0		)
Less: Non-Controlling Interest in Subsidiaries	(0.5		)	—			(0.5		)
Net Income (Loss) Attributable to ALLETE		$75.3			$79.8		$(4.5)
Total Assets		$2,609.1			$2,375.4			$233.7
Capital Additions		$260.0			$256.4			$3.6

XML

Derivatives - Hedged Items (Details) (Term Loan [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Sep. 30, 2011
Term Loan [Member]
Debt Instrument [Line Items]
Term Loan Principal Amount		$ 75.0
Term Loan Variable Rate Basis	one-month LIBOR
Term Loan Basis Spread on Variable Rate	1.00%

XML

Pension and Other Postretirement Benefit Plans - Obligation and Funded Status (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Change in Plan Assets [Roll Forward]
Non-Current Liabilities	$ 228.2	$ 253.5
Other Investments, Grantor Trust	143.5	132.3
Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	598.7	550.6
Change in Benefit Obligation [Roll Forward]
Obligation, Beginning of Year	597.5	525.6
Service Cost	9.1	7.6	6.2
Interest Cost	26.4	27.4	26.2
Actuarial Loss (Gain)	38.5	54.6
Benefits Paid	(30.9)	(28.6)
Participant Contributions	11.5	10.9
Obligation, End of Year	652.1	597.5	525.6
Change in Plan Assets [Roll Forward]
Fair Value, Beginning of Year	432.4	382.0
Actual Return on Plan Assets	38.7	33.2
Employer Contribution	19.9	45.8
Participant Contributions	11.5	10.9
Benefits Paid	(30.9)	(28.6)
Fair Value, End of Year	460.1	432.4	382.0
Funded Status, End of Year	(192.0)	(165.1)
Current Liabilities	(1.1)	(1.1)
Non-Current Liabilities	(190.9)	(164.0)
Postretirement Health and Life [Member]
Change in Benefit Obligation [Roll Forward]
Obligation, Beginning of Year	210.6	204.1
Service Cost	4.2	3.8	4.8
Interest Cost	9.4	10.8	10.9
Actuarial Loss (Gain)	(43.2)	(2.9)
Benefits Paid	(9.5)	(7.7)
Participant Contributions	2.6	2.5
Plan Amendments	(5.3)	0
Obligation, End of Year	168.8	210.6	204.1
Change in Plan Assets [Roll Forward]
Fair Value, Beginning of Year	121.0	114.7
Actual Return on Plan Assets	14.3	0
Employer Contribution	2.3	11.4
Participant Contributions	2.6	2.5
Participant Contributions, Excluding Key Employees	2.5	2.5
Benefits Paid	(9.5)	(7.7)
Benefits Paid, Excluding Key Employees	(9.1)	(7.6)
Fair Value, End of Year	131.0	121.0	114.7
Funded Status, End of Year	(37.8)	(89.6)
Current Liabilities	(0.8)	(0.9)
Non-Current Liabilities	(37.0)	(88.7)
Grantor Trust [Member]
Change in Plan Assets [Roll Forward]
Other Investments, Grantor Trust	$ 22.1	$ 20.3

XML

Commitments, Guarantees and Contingencies - Transmission (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
CapX2020 [Member]
Transmission [Line Items]
Number of Projects	3
Minimum Amount Expected to be Invested in Transmission Projects	$ 100
Maximum Amount Expected to be Invested in Transmission Projects	110
Capital Cost Spent to Date	48.2	27.8
CapX2020 Fargo to Monticello Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	238
Transmission Line Capacity (kV)	345
Capital Cost Spent to Date	37.3	20.4
CapX2020 Monticello to St. Cloud Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	28
Transmission Line Capacity (kV)	345
CapX2020 Bemidji to Grand Rapids Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	70
Transmission Line Capacity (kV)	230
Capital Cost Spent to Date	$ 10.9	$ 7.4

XML

Operations and Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Operations and Significant Accounting Policies [Abstract]

Financial Statement Preparation [Policy Text Block]

Financial Statement Preparation. References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue, and expenses. Actual results could differ from those estimates.

Subsequent Events [Policy Text Block]

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

Principles of Consolidation [Policy Text Block]

Principles of Consolidation. Our consolidated financial statements include the accounts of ALLETE and all of our majority-owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.

Business Segments [Policy Text Block]

Business Segments. Our Regulated Operations and Investments and Other segments were determined in accordance with the guidance on segment reporting. Segmentation is based on the manner in which we operate, assess, and allocate resources to the business. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Land Inventory [Policy Text Block]

Land inventories are accounted for in accordance with the accounting standards for property, plant and equipment, and are included in Other Investments on our Consolidated Balance Sheet. Real estate costs include the cost of land acquired, subsequent development costs and costs of improvements, capitalized development period interest, real estate taxes and payroll costs of certain employees devoted directly to the development effort. These real estate costs incurred are capitalized to the cost of real estate parcels based upon the relative sales value of parcels within each development project in accordance with the accounting standards for real estate. The cost of real estate sold includes the actual costs incurred and the estimate of future completion costs allocated to the real estate sold based upon the relative sales value method. Whenever events or circumstances indicate that the carrying value of the real estate may not be recoverable, impairments are recorded and the related assets are adjusted to their estimated fair value.

Cash and Cash Equivalents [Policy Text Block]

Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.

Accounts Receivable [Policy Text Block]

Accounts Receivable. Accounts receivable are reported on the balance sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses.

Long-Term Finance Receivables [Policy Text Block]

Long-Term Finance Receivables. Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals.

Available-for-Sale Securities [Policy Text Block]

Available-for-Sale Securities. Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as the share price trends and the impact of overall market conditions.

Inventories [Policy Text Block]

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

Property, Plant and Equipment [Policy Text Block]

Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the balance sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on non-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for Regulated Operations. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. The MPUC has approved cost recovery for several large capital projects recently, at which time the recognition of AFUDC ceases.

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.

Impairment of Long-Lived Assets [Policy Text Block]

Impairment of Long-Lived Assets. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.

In the event that projected future undiscounted cash flows are not adequate to recover the carrying value of an asset, impairment is indicated and may require a write down to the asset’s fair value. Fair value is determined based on best available evidence including comparable sales, current appraised values, property tax assessed values, and discounted cash flow analysis. If fair value is less than cost, the carrying value of our investments is reduced and an impairment charge is recorded in the current period.

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels into bulk sales, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, and may vary among each land parcel or bulk sale.If the excess of undiscounted cash flows over the carrying value of a property is small, there is a greater risk of future impairment in the event of such changes and any resulting impairment charges could be material.

Derivatives [Policy Text Block]

Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage interest rate risk related to certain variable-rate borrowings.

Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.

Accounting for Stock-Based Compensation [Policy Text Block]

Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate.

Environmental Liabilities [Policy Text Block]

Environmental Liabilities. We review environmental matters for disclosure on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the 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 operating expense unless recoverable in rates from customers.

Revenue Recognition [Policy Text Block]

Revenue Recognition. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for service provided but not billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. BNI recognizes revenue when coal is delivered.

Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue and net purchases in Fuel and Purchased Power Expense on our Consolidated Statement of Income. The revenues and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.

Full profit recognition is recorded on sales upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. In certain cases, where there are obligations to perform significant development activities after the date of sale, we recognize profit on a percentage-of-completion basis. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

In certain cases, we pay fees or construct improvements to mitigate offsite traffic impacts. In return, we receive traffic impact fee credits as a result of some of these expenditures. We recognize revenue from the sale of traffic impact fee credits when payment is received.

Unamortized Discount and Premium on Debt [Policy Text Block]

Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using the straight-line method which approximates the effective interest method.

Income Taxes [Policy Text Block]

Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return and combined and separate state income tax returns. We account for income taxes using the liability method in accordance with the accounting standards for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with the accounting standards for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than 50 percent likely.

Excise Taxes [Policy Text Block]

Excise Taxes. We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.

Asset Retirement Obligations [Policy Text Block]

Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction or development and/or normal operation of the asset.

Regulatory Assets and Liabilities [Policy Text Block]

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 liabilitiesrepresent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.

Fair Value Transfers [Policy Text Block]

The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer.

Pension and Other Postretirement Benefit Plans [Policy Text Block]

Accounting for defined benefit pension and postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their Consolidated Balance Sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

The defined benefit pension and postretirement health and life benefit costs recognized annually by our regulated companies are expected to be recovered through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset on our Consolidated Balance Sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit costs associated with our other non-rate base operations are recognized in accumulated other comprehensive income.

Employee Stock Ownership Plan (ESOP) [Policy Text Block]

We make annual contributions to the ESOP equal to the ESOP’s debt service less available dividends received by the ESOP. The majority of dividends received by the ESOP are used to pay debt service, with the balance distributed to participants. The ESOP shares were initially pledged as collateral for the debt. As the debt is repaid, shares are released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares are released from collateral, we report compensation expense equal to the current market price of the shares less dividends on allocated shares. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings; available dividends on unallocated ESOP shares are recorded as a reduction of debt and accrued interest.

According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.

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Common Stock and Earnings Per Share - Reconciliation of Basic and Diluted Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 28.9	$ 29.4	$ 14.4	$ 24.4	$ 19.1	$ 20.5	$ 17.0	$ 37.2	$ 97.1	$ 93.8	$ 75.3
Average Common Shares									37.6	35.3	34.2
Earnings Per Share	$ 0.76	$ 0.78	$ 0.39	$ 0.66	$ 0.53	$ 0.57	$ 0.49	$ 1.07	$ 2.59	$ 2.66	$ 2.20
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE									$ 97.1	$ 93.8	$ 75.3
Average Common Shares									37.6	35.4	34.3
Earnings Per Share	$ 0.75	$ 0.78	$ 0.39	$ 0.66	$ 0.53	$ 0.57	$ 0.48	$ 1.07	$ 2.58	$ 2.65	$ 2.19
Dilutive Securities (Shares)									0	0.1	0.1

XML

Other Income (Expense) (Tables)

12 Months Ended

Dec. 31, 2012

Other Income (Expense) [Abstract]

Other Income (Expense) [Table Text Block]

Year Ended December 31	2012		2011		2010
Millions
AFUDC – Equity		$5.1		$2.5		$4.2
Investment and Other Income	0.9		1.9		0.4
Total Other Income		$6.0		$4.4		$4.6

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Common Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2012

Common Stock and Earnings Per Share [Abstract]

Common Stock and Earnings Per Share [Text Block]

COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2009	35,221		$613.4
Employee Stock Purchase Program	19	0.6
Invest Direct	346	11.7
Options and Stock Awards	51	4.4
Equity Issuance Program	180	6.0
Balance as of December 31, 2010	35,817		$636.1
Employee Stock Purchase Program	20	0.8
Invest Direct	437	17.2
Options and Stock Awards	109	6.7
Equity Issuance Program	400	16.0
Purchase of Non-Controlling Interest	222	8.8
Contributions to Pension	508	20.0
Balance as of December 31, 2011	37,513		$705.6
Employee Stock Purchase Program	20	0.8
Invest Direct	474	19.2
Options and Stock Awards	95	6.0
Equity Issuance Program	1,275	53.1
Balance as of December 31, 2012	39,377		$784.7

Equity Issuance Program. We entered into a distribution agreement with KCCI, Inc., in February 2008, as amended most recently on August 3, 2012, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 4.5 million remain available for issuance. For the year ended December 31, 2012, 1.3 million shares of common stock were issued under this agreement resulting in net proceeds of $53.1 million. During 2011, 0.4 million shares of common stock were issued for net proceeds of $16.0 million. The shares issued in 2012 and 2011 were, and the remaining shares may be, offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-170289.

Earnings Per Share. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock, and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. In 2012, in accordance with accounting standards for earnings per share, 0.2 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive (0.3 million shares were excluded in 2011 and 0.5 million in 2010).

Purchase of Non-Controlling Interest. In 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased at book value for $8.8 million by issuing 0.2 million unregistered shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss is recognized in net income or comprehensive income.

Contributions to Pension. In 2011, ALLETE contributed approximately 0.5 million shares of ALLETE common stock to its pension plan. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933 and had an aggregate value of $20.0 million when contributed.

NOTE 12. COMMON STOCK AND EARNINGS PER SHARE (Continued)

Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2012
Net Income Attributable to ALLETE		$97.1			$97.1
Average Common Shares	37.6		—	37.6
Earnings Per Share		$2.59			$2.58
2011
Net Income Attributable to ALLETE		$93.8			$93.8
Average Common Shares	35.3		0.1	35.4
Earnings Per Share		$2.66			$2.65
2010
Net Income Attributable to ALLETE		$75.3			$75.3
Average Common Shares	34.2		0.1	34.3
Earnings Per Share		$2.20			$2.19

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Schedule II (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Trade Accounts Receivable [Member]
Valuation and Qualifying Accounts and Reserves [Line Items]
Balance at Beginning of Period	$ 0.9		$ 0.9		$ 0.9
Additions, Charged to Income	1.0		1.3		1.1
Additions, Other Charges	0		0		0
Deductions from Reserves	0.9	[1]	1.3	[1]	1.1	[1]
Balance at End of Period	1.0		0.9		0.9
Finance Receivables - Long-Term [Member]
Valuation and Qualifying Accounts and Reserves [Line Items]
Balance at Beginning of Period	0.6		0.8		0.4
Additions, Charged to Income	0		0.1		0.8
Additions, Other Charges	0		0		0
Deductions from Reserves	0	[1]	0.3	[1]	0.4	[1]
Balance at End of Period	0.6		0.6		0.8
Deferred Tax Assets [Member]
Valuation and Qualifying Accounts and Reserves [Line Items]
Balance at Beginning of Period	0.4		0.5		0.3
Additions, Charged to Income	2.0		(0.1)		0.2
Additions, Other Charges	0		0		0
Deductions from Reserves	0	[1]	0	[1]	0	[1]
Balance at End of Period	$ 2.4		$ 0.4		$ 0.5

[1] Includes uncollectible accounts written off.