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, 2014
	£	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
		For the transition period from ______________ to ______________

Commission File Number 1-3548

ALLETE, Inc.

(Exact name of registrant as specified in its charter)

Minnesota	41-0418150
(State or other jurisdiction of incorporation or organization)	(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 x     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 x

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 x     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 x     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. x

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

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

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

The aggregate market value of voting stock held by nonaffiliates on June 30, 2014, was $2,175,249,161.

As of February 1, 2015, there were 45,953,851 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference

Portions of the Proxy Statement for the 2015 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
		Seasonality	11
		Power Supply	11
		Transmission and Distribution	14
		Investment in ATC	15
		Properties	15
		Regulatory Matters	15
		Regional Organizations	18
		Minnesota Legislation	18
		Competition	19
		Franchises	19
	Investments and Other		19
		ALLETE Clean Energy	19
		BNI Coal	20
		ALLETE Properties	20
		Non-Rate Base Generation	21
	Environmental Matters		21
	Employees		27
	Availability of Information		27
	Executive Officers of the Registrant		28
Item 1A.	Risk Factors		29
Item 1B.	Unresolved Staff Comments		34
Item 2.	Properties		34
Item 3.	Legal Proceedings		34
Item 4.	Mine Safety Disclosures		34
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		34
Item 6.	Selected Financial Data		35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		36
	Overview		36
	2014 Compared to 2013		37
	2013 Compared to 2012		39
	Critical Accounting Policies		41
	Outlook		43
	Liquidity and Capital Resources		49
	Capital Requirements		54
	Environmental and Other Matters		54
	Market Risk		54
	Recently Adopted Accounting Standards		55
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		55
Item 8.	Financial Statements and Supplementary Data		55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		56
Item 9A.	Controls and Procedures		56

ALLETE, Inc. 2014 Form 10-K

2

Index

Item 9B.	Other Information	56
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	57
Item 11.	Executive Compensation	57
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
Item 13.	Certain Relationships and Related Transactions, and Director Independence	58
Item 14.	Principal Accounting Fees and Services	58
Part IV
Item 15.	Exhibits and Financial Statement Schedules	58
Signatures		64
Consolidated Financial Statements		67

ALLETE, Inc. 2014 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
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. and its subsidiaries
ALLETE Properties	ALLETE Properties, LLC and its subsidiaries
ArcelorMittal	ArcelorMittal USA, Inc.
ATC	American Transmission Company LLC
Basin	Basin Electric Power Cooperative
Bison Wind Energy Center	Bison 1, 2, 3 & 4 Wind Facilities
Bison 4	Bison 4 Wind Facility
BNI Coal	BNI Coal, Ltd.
Boswell	Boswell Energy Center
CO2	Carbon Dioxide
Company	ALLETE, Inc. and its subsidiaries
CSAPR	Cross-State Air Pollution Rule
DC	Direct Current
EPA	Environmental Protection Agency
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Form 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
GNTL	Great Northern Transmission Line
IBEW	International Brotherhood of Electrical Workers
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
Item ___	Item ___ of this Form 10-K
kV	Kilovolt(s)
kWh	Kilowatt-hour
Laskin	Laskin Energy Center
LIBOR	London Interbank Offered Rate
MACT	Maximum Achievable Control Technology
Magnetation	Magnetation, LLC
Manitoba Hydro	Manitoba Hydro-Electric Board
MATS	Mercury and Air Toxics Standards
MBtu	Million British thermal units
Mesabi Nugget	Mesabi Nugget Delaware, LLC
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.
MISO	Midcontinent Independent System Operator, Inc.

ALLETE, Inc. 2014 Form 10-K

4

Definitions (continued)

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
SIP	State Implementation Plan
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
Thomson	Thomson Energy Center
Town Center	Town Center at Palm Coast development project in Florida
Town Center District	Town Center at Palm Coast Community Development District
U.S.	United States of America
U.S. Water Services	U.S. Water Services, Inc.
USS Corporation	United States Steel Corporation

ALLETE, Inc. 2014 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;

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

• wholesale power market conditions;

• federal and state regulatory and legislative actions that impact regulated utility economics, including 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 and utility infrastructure, recovery of purchased power, capital investments and other expenses, including present or prospective environmental matters;

• changes in and compliance with laws and regulations;

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

• effects of restructuring initiatives in the electric industry;

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

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

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

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

• weather conditions, natural disasters and pandemic diseases;

• our ability to access capital markets and bank financing;

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

• 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 and our ability to recover these costs;

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

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

• effects of emerging technology;

• war, acts of terrorism and cyber attacks;

• our ability to manage expansion and integrate acquisitions;

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

• population growth rates and demographic patterns; and

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

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 29 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, Inc. 2014 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 144,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Otheris comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, our business which acquired four wind energy facilities in 2014 and is developing a wind facility to be sold in 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. Our Energy Infrastructure and Related Services businesses will also include U.S. Water Services, which we acquired in February 2015. (See Outlook – Investments and Other.)

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2014, 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	2014			2013			2012
Consolidated Operating Revenue – Millions		$1,136.8			$1,018.4			$961.2
Percentage of Consolidated Operating Revenue
Regulated Operations	88		%	91		%	91		%
Investments and Other	12		%	9		%	9		%
	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	2014	%	2013	%	2012	%
Millions of Kilowatt-hours
Retail and Municipal
Residential	1,204	9	1,177	9	1,132	9
Commercial	1,468	10	1,455	11	1,436	11
Industrial	7,487	54	7,338	55	7,502	57
Municipal	864	6	999	8	1,020	8
Total Retail and Municipal	11,023	79	10,969	83	11,090	85
Other Power Suppliers	2,904	21	2,278	17	1,999	15
Total Regulated Utility Electric Sales	13,927	100	13,247	100	13,089	100

ALLETE, Inc. 2014 Form 10-K

7

Regulated Operations (Continued)

Industrial Customers. In 2014, our industrial customers represented 54 percent of total Regulated Utility kilowatt-hour sales. Our industrial customers are primarily in the taconite mining, iron concentrate, paper, pulp and secondary wood products, and pipeline industries.

Industrial Customer Electric Sales
Year Ended December 31	2014	%	2013	%	2012	%
Millions of Kilowatt-hours
Taconite/Iron Concentrate	4,880	65	4,851	66	4,968	66
Paper, Pulp and Secondary Wood Products	1,499	20	1,505	21	1,571	21
Pipelines and Other Industrial	1,108	15	982	13	963	13
Total Industrial Customer Electric Sales	7,487	100	7,338	100	7,502	100

Seven Minnesota Power taconite and iron concentrate customers produce approximately 77 percent of the iron ore produced in theU.S. according to the U.S. Geological Survey’s 2012 Minerals Yearbook published in September 2014. Sales to taconite customers and iron concentrate customers represented 4,880 million kilowatt-hours, or 65 percent, of our total industrial sales in 2014. 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.

Five of Minnesota Power’s 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. Also, two of Minnesota Power’s iron concentrate customers have the capability to produce up to approximately 2 million metric tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets.

During 2014, 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 77 percent of capacity in 2014 (77 percent in 2013 and 75 percent in 2012).

The past four years, annual taconite production in Minnesota has remained strong at, or near, full production. The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years.

Minnesota Power Taconite Customer Production
Year	Tons (Millions)
2014*	39
2013	37
2012	39
2011	39
2010	35
2009	17
2008	39
2007	38
2006	39
2005	40
Source: Minnesota Department of Revenue 2014 Mining Tax Guide for years 2005 - 2013.
* Preliminary data from the Minnesota Department of Revenue.

ALLETE, Inc. 2014 Form 10-K

8

Regulated Operations (Continued)

Industrial Customers (Continued)

In addition to serving the taconite industry, Minnesota Power also serves a number of customers in the paper, pulp and secondary wood products industry, which represented 1,499 million kilowatt-hours, or 20 percent, of our total industrial sales in 2014. Three of the four major paper mills we serve reported operating at, or near, full capacity in 2014. In October 2013, Boise, Inc. (Boise) permanently shut down two paper machines representing approximately 20 percent of its paper making capacity. Boise’s reduction in paper making capacity did not have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. On September 12, 2014, Boise provided the required one-year written notice of its intent to install additional generation at its International Falls, Minnesota, mill in late 2015. Boise’s reduction in demand is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Large Power Customer Contracts. Minnesota Power has 10 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, one concentrate reclamation facility, 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.)

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.

ALLETE, Inc. 2014 Form 10-K

9

Regulated Operations (Continued)

Large Power Customer Contracts (Continued)

Contract Status for Minnesota Power Large Power Customers

As of February 1, 2015

Customer	Industry	Location	Ownership	Earliest Termination Date
ArcelorMittal USA, Inc. – Minorca Mine (a)	Taconite	Virginia, MN	ArcelorMittal S.A.	January 31, 2019
Hibbing Taconite Co. (a)	Taconite	Hibbing, MN	62.3% ArcelorMittal S.A. 23.0% Cliffs Natural Resources Inc. 14.7% USS Corporation	January 31, 2019
United Taconite LLC (a)	Taconite	Eveleth, MN	Cliffs Natural Resources Inc.	January 31, 2019
USS Corporation (USS – Minnesota Ore) (a,b)	Taconite	Mt. Iron, MN and Keewatin, MN	USS Corporation	January 31, 2019
Mesabi Nugget Delaware, LLC	Iron Nugget	Hoyt Lakes, MN	80% Steel Dynamics, Inc. 20% Kobe Steel USA, Inc.	December 31, 2023
Boise, Inc.	Paper	International Falls, MN	Packaging Corporation of America	December 31, 2023
UPM, Blandin Paper Mill (a)	Paper	Grand Rapids, MN	UPM-Kymmene Corporation	January 31, 2019
Verso Corporation (c)	Paper and Pulp	Duluth, MN	Verso Corporation	December 31, 2022
Sappi Cloquet LLC (a)	Paper and Pulp	Cloquet, MN	Sappi Limited	January 31, 2019
Magnetation, LLC (d)	Iron Concentrate	Coleraine, MN	50.1% Magnetation, Inc. 49.9% AK Steel Corporation	December 31, 2025

(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, 2019.

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

(c) On January 7, 2015, Verso Corporation acquired NewPage Corporation. This acquisition will not impact Minnesota Power’s electric service agreement with NewPage Corporation.

(d) Production at this facility commenced in December 2014. (See Outlook – Regulated Operations – Industrial Customers and Prospective Additional Loads.)

Residential and Commercial Customers. In 2014, our residential and commercial customers represented 19 percent of total regulated utility kilowatt-hour sales. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 144,000 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 2014, our municipal customers represented 6 percent of total regulated utility kilowatt-hour sales, which included 16 municipals in Minnesota.

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 expires in April 2020. 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.

Minnkota Power Sales Agreement. Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced June 1, 2014. Under the power sales agreement, Minnesota Power is selling 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 12. Commitments, Guarantees and Contingencies.)

ALLETE, Inc. 2014 Form 10-K

10

Regulated Operations (Continued)

Seasonality

The operations of our industrial customers, which make up a large portion of our sales portfolio as reflected 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.

Power Supply

In order to meet our customers’ electric requirements, we utilize a mix of Company generation and purchased power. At December 31, 2014, the Company’s generation is primarily coal-fired, but also includes approximately 105 MW of hydroelectric generation from ten hydro stations in Minnesota, 522 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, 2014, and total electrical output for 2014. Minnesota Power had an annual net peak load of 1,637 MW on December 30, 2014.

ALLETE, Inc. 2014 Form 10-K

11

Regulated Operations (Continued)

Power Supply (Continued)

				Year Ended
	Unit	Year	Net	December 31, 2014
Regulated Utility Power Supply	No.	Installed	Capability	Generation and Purchases
			MW	MWh	%
Coal-Fired
Boswell Energy Center	1	1958	67
in Cohasset, MN	2	1960	68
	3	1973	362
	4	1980	468	(a)
			965	6,543,143	46.3
Laskin Energy Center	1	1953	43	(b)
in Hoyt Lakes, MN	2	1953	38	(b)
			81	347,844	2.4
Taconite Harbor Energy Center	1	1957	76
in Schroeder, MN	2	1957	74
	3	1967	81	(b)
			231	1,089,924	7.7
Total Coal-Fired			1,277	7,980,911	56.4
Biomass/Coal/Natural Gas
Hibbard Renewable Energy Center in Duluth, MN	3 & 4	1949, 1951	58	19,635	0.1
Cloquet Energy Center in Cloquet, MN	5	2001	23	119,025	0.8
Total Biomass/Coal/Natural Gas			81	138,660	0.9
Hydro (c)
Group consisting of ten stations in MN	Multiple	Multiple	105	238,293	1.7
Wind (d)
Taconite Ridge Energy Center in Mt. Iron, MN	Multiple	2008	25	66,609	0.5
Bison Wind Energy Center in Oliver and Morton Counties, ND	Multiple	2010-2014	497	962,275	6.8
Total Wind			522	1,028,884	7.3
Total Company Generation			1,985	9,386,748	66.3
Long-Term Purchased Power
Lignite Coal - Square Butte near Center, ND				1,378,008	9.7
Wind - Oliver County, ND				365,940	2.6
Hydro - Manitoba Hydro in Manitoba, Canada				320,609	2.3
Total Long-Term Purchased Power				2,064,557	14.6
Other Purchased Power (e)				2,705,942	19.1
Total Purchased Power				4,770,499	33.7
Total			1,985	14,157,247	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 and Projects.)

(b) Future plans for our Laskin Energy Center and Taconite Harbor Unit 3 are included in our “EnergyForward” plan which includes the conversion of Laskin from coal to natural gas in the second quarter of 2015 and the retiring of Taconite Harbor Unit 3 in the second quarter of 2015. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

(c) The Thomson Energy Center returned to partial generation in the fourth quarter of 2014. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – Hydro Operations.)

(d) Taconite Ridge consists of 10 wind turbine generator units with a total nameplate capacity of 25 MW. The Bison Wind Energy Center consists of 165 wind turbine generator units, with a total nameplate capacity of 497 MW. Bison 4 was placed in service in the fourth quarter of 2014 and approximately 45,000 MWh generated by Bison 4 is included in the table above. 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 change.

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

ALLETE, Inc. 2014 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 2014 for electric generation at Minnesota Power’s coal-fired generating stations was 4.8 million tons. As of December 31, 2014, Minnesota Power had a coal inventory of 1.0 million tons (0.4 million tons as of December 31, 2013). Fuel inventory was low throughout much of 2014 due to rail service delays. Minnesota Power filed a notice of fuel supply emergency with the U.S. Department of Energy on September 22, 2014, in response to inadequate rail deliveries. Rail deliveries increased late in 2014, building inventories to normal levels by year end 2014. Minnesota Power’s coal supply agreements have expiration dates through 2015. In 2015, 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. Minnesota Power is currently in discussions regarding the extension of our coal supply and transportation contracts beyond 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	2014		2013		2012
Average Price per Ton		$26.52		$28.90		$29.58
Average Price per MBtu		$1.47		$1.60		$1.64

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

Square Butte PPA. Under the long-term agreement with Square Butte, which expires at the end of 2026, Minnesota Power is entitled to 50 percent of the output of a 455-MW coal-fired generating unit located near Center, North Dakota. (See Note 12. 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 2014 was approximately $1.63 per MBtu. (See Electric Sales/Customers–Minnkota Power Sales Agreement.)

Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity from June 2016 through May 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. 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 that expire in 2031 and 2032, respectively. Each agreement provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges, and we only pay for energy as it is delivered to us.

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2020. Under this agreement, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. (See Item 1. Business – Regulated Operations – Transmission and Distribution.) The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

ALLETE, Inc. 2014 Form 10-K

13

Regulated Operations (Continued)

Long-Term Purchased Power (Continued)

In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index as well as market prices. Both PPAs are subject to MPUC approval.

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 345 kV (107 miles), 250 kV (465 miles), 230 kV (714 miles), 161 kV (43 miles), 138 kV (130 miles), 115 kV (1,271 miles) and less than 115 kV (6,276 miles). We own and operate 174 substations with a total capacity of 10,651 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 and municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020.

Minnesota Power is currently participating in the construction of one CapX2020 transmission line project. Minnesota Power also participated in two CapX2020 projects which were previously completed and placed into service in 2011 and 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project, of which the final phase is currently under construction and expected to be in service in the second quarter of 2015.

Based on projected costs of the three transmission line projects and the allocation agreements among participating utilities, in total Minnesota Power plans to invest approximately $105 million in the CapX2020 initiative through 2015, of which $99 million was spent through December 31, 2014. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220-mile 500 kV transmission line, between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line.

ALLETE, Inc. 2014 Form 10-K

14

Regulated Operations (Continued)

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 based on a FERC-approved 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, 2014, our equity investment in ATC was $121.1 million ($114.6 million at December 31, 2013). (See Note 6. Investment in ATC.)

In November 2013, several customer groups located within the MISO service area filed a complaint with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15 percent. ATC's current authorized return on equity is 12.2 percent. In the fourth quarter of 2014, FERC ordered formal hearing proceedings to begin and established a date for potential refunds from November 12, 2013. An initial decision in the complaint is expected by November 30, 2015. In the fourth quarter of 2014, ATC recorded approximately an$18 million refund liability as ATC believes that it is probable that a refund will be required upon ultimate resolution of this matter. The refund liability is subject to adjustment in future periods if assumptions in the estimate change. ATC’s refund liability negatively impacted our Equity Earnings in ATC by approximately $1 million after-tax in 2014. We own approximately 8 percent of ATC and estimate that for every 50 basis point reduction in ATC’s allowed return on equity our equity earnings in ATC would be impacted annually by approximately $0.5 million on an after-tax basis.

In October 2014, ATC updated its 10-year transmission assessment covering the years 2014 through 2023 which identifies a need for between $3.3 and $3.9 billion in transmission system investments. These investments by ATC are expected to be funded through a combination of internally generated cash, debt and investor contributions. As opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro rata ownership interest in ATC.

In 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, various independent system operators and state regulatory authorities.

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 and Projects.)

Regulatory Matters

We are subject to the jurisdiction of various regulatory authorities and other organizations. The MPUC has regulatory authority over Minnesota Power’s retail 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 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. 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 generation and transmission 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.

ALLETE, Inc. 2014 Form 10-K

15

Regulated Operations (Continued)

Regulatory Matters (Continued)

Information published by the Edison Electric Institute (Typical Bills and Average Rates Report – Summer 2014 and Rankings – July 1, 2014) ranked Minnesota Power as having the second lowest average retail rates out of 169 utilities in the U.S. and the lowest rates in Minnesota.

Minnesota Public Utilities Commission. The MPUC has regulatory authority over Minnesota Power’s retail 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 allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

Renewable Cost Recovery Rider. Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills.

On January 29, 2015, the MPUC approved our petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider. The total project investment for Thomson is estimated to be approximately $90 million, net of insurance. (See Note 12. Commitments, Guarantees and Contingencies.)

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward), and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Significant elements of the “EnergyForward” plan include major wind investments in North Dakota which were completed in the fourth quarter of 2014 (see Renewable Cost Recovery Rider), installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in the second quarter of 2015 and retiring Taconite Harbor Unit 3 in the second quarter of 2015. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, and establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014. On November 26, 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015.

ALLETE, Inc. 2014 Form 10-K

16

Regulated Operations (Continued)

Regulatory Matters (Continued)

Great Northern Transmission Line (GNTL). Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500 kV transmission line, between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. (See Item 1. Business – Regulated Operations – Transmission and Distribution.)

Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of net gross operating revenues from service provided in the state on energy CIPs each year. These investments are recovered from certain 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 included, in addition to the minimum spending requirements, an energy-saving goal of 1.5 percent of net gross annual retail electric energy sales beginning with program year 2010. Minnesota Power refers to the collective conservation programs as the “Power of One”. In June 2013, Minnesota Power submitted a triennial filing for 2014 through 2016, which was subsequently approved by the Minnesota Department of Commerce. Minnesota Power’s CIP investment goal was $6.9 million for 2014 ($6.0 million for 2013 and 2012), with actual spending of $7.2 million in 2014 ($6.4 million in 2013; $6.8 million in 2012). The investment goal for 2015 and 2016 is $7.1 and $7.3 million, respectively.

As a result of the energy savings goal in the Next Generation Energy Act of 2007, the MPUC revised the utility performance incentive to recognize utilities for making progress toward and meeting the energy-savings goals established. This revised incentive mechanism became effective beginning with the 2010 program year. On April 1, 2014, Minnesota Power submitted its 2013 CIP filing that requested a CIP financial incentive of $8.7 million based upon MPUC procedures. The requested CIP financial incentive was approved by the MPUC in a hearing held on July 24, 2014, and was recorded as revenue and as a regulatory asset. The approved financial incentive will be recovered through customer billing rates in 2014 and 2015. In 2013, the CIP financial incentive of $7.1 million was recognized in the fourth quarter. CIP financial incentives are recognized in the period in which the MPUC approves the filing. The MPUC implemented certain limitation of amounts recoverable for the utility performance incentive program for plan years beginning in 2014.

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 subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. The electric service agreements with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2023. Under the agreements with the remaining 15 municipal customers and SWL&P, no termination notices may be given prior to June 30, 2016.

ALLETE, Inc. 2014 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.

SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity.

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

Regional Organizations

Midcontinent Independent System Operator, Inc. 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 15 states and the Canadian province of Manitoba, and over 150,000 MW of generating capacity.

North American Electric Reliability Corporation. The NERC has been certified by the FERC as the national electric reliability organization. The NERC ensures the reliability 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 non-compliance.

Midwest Reliability Organization (MRO).MinnesotaPoweris a member of the MRO, one of the eight regional entities overseen by the NERC. MRO's primary responsibilities are to: ensure compliance with mandatory reliability standards by entities who own, operate, or use the interconnected, international Bulk Power System; conduct assessments of the grid's ability to meet electricity demand in the region; and analyze regional system events.

The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, and all or parts of the states of Illinois, Iowa, Minnesota, Michigan, Montana, Nebraska, North Dakota, South Dakota and Wisconsin. The region includes more than 130 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, transmission system operators, a federal power marketing agency, Canadian Crown corporations, and independent power producers.

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 to be from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits.

Minnesota Power continues to execute its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. Our wind energy facilities consist of our 497 MW Bison Wind Energy Center located in North Dakota placed in service in various phases between 2010 and 2014, and our 25 MW Taconite Ridge Energy Center located in northeastern Minnesota. We also have two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) located in North Dakota. Through the strategy outlined in Minnesota Power’s 2013 Integrated Resource Plan, 18 percent of the Company’s total retail and municipal energy sales were supplied by renewable energy sources in 2014. We expect 28 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2015.

ALLETE, Inc. 2014 Form 10-K

18

Regulated Operations (Continued)

Minnesota Legislation (Continued)

Minnesota Solar Energy Standard. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain industrial customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Minnesota Power is in the process of evaluating the potential impact of this legislation on our operations; however, any costs are expected to be recovered in customer rates.

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 11 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, 2014, 6 percent of the Company’s electric energy sales were to municipal customers in Minnesota 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 91 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 or towns.

Investments and Other

Investments and Otheris comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy and BNI Coal. Investments and Other also includes ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. Our Energy Infrastructure and Related Services businesses will also include U.S. Water Services, which we acquired in February 2015. (See Outlook.)

ALLETE Clean Energy

ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements.

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015.

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

ALLETE, Inc. 2014 Form 10-K

19

Investments and Other (Continued)

ALLETE Clean Energy (Continued)

On November 20, 2014, ALLETE Clean Energy acquired a business for $27.0 million which is developing a wind facility near Hettinger, North Dakota. ALLETE Clean Energy will develop and construct a 107 MW wind farm using 43 turbines which will then be sold to Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approvals.

On December 17, 2014, ALLETE Clean Energy acquired a wind facility in Storm Lake, Iowa (Storm Lake I) for $15.0 million, subject to a working capital adjustment. Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II which was acquired in January 2014. The wind facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire wind facilities in southern Minnesota for approximately $47.5 million. The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility acquired in January 2014. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015.

BNI Coal

BNI Coal is a supplier of lignite in North Dakota, producing about 4 million tons annually and has lignite reserves of an estimated 650 million tons. Two electric generating cooperatives, Minnkota Power and Square Butte, presently consume virtually all of BNI Coal’s production of lignite under cost-plus fixed fee coal supply agreements extending to December 31, 2037. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 12. 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, 2014, BNI Coal had a $20.3 million asset reclamation obligation ($12.4 million at December 31, 2013) 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 12. Commitments, Guarantees and Contingencies.)

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, 2014, outstanding finance receivables were $1.2 million, net of reserves, with maturities through 2015. 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, Inc. 2014 Form 10-K

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Investments and Other (Continued)

Non-Rate Base Generation

As of December 31, 2014, non-rate base generationconsists of 29 MW of generation at Rapids Energy Center. In 2014, we sold 0.1 million MWh of non-rate base generation (0.1 million MWh in 2013 and 2012).

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.

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

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserted that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that Boswell Unit 4’s Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated.

Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota (Court) on September 29, 2014. The Consent Decree covers Minnesota Power’s Boswell, Laskin, Taconite Harbor, and Rapids Energy Centers. The Consent Decree provides for more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at some units, and the addition of 200 MW of wind energy. Minnesota Power is required to spend $4.2 million on environmental mitigation projects over the next five years. Under the terms of the Consent Decree, Minnesota Power also paid a $1.4 million civil penalty which was recognized as an expense in 2013. In 2014, the Company recorded an expense associated with the environmental mitigation projects.

ALLETE, Inc. 2014 Form 10-K

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Environmental Matters (Continued)

Air (Continued)

Since 2005, the Company has, and will, invest more than $600 million to reduce sulfur dioxide, nitrogen oxide, mercury and particulate matters emissions at its thermal generation facilities, and between 2010 and 2014 placed in service nearly 500 MW of renewable wind energy, which fulfills certain obligations under the Consent Decree. In addition, Minnesota Power’s EnergyForward plan addresses many of the requirements included in the Consent Decree. Under the EnergyForward plan, Minnesota Power intends to: 1) retire Taconite Harbor Unit 3, 2) convert Laskin from coal to natural gas, and 3) install emission controls at Boswell Unit 4.

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

Cross-State Air Pollution Rule (CSAPR). On April 29, 2014, the U.S. Supreme Court issued an opinion reversing an August 2012 U.S. Court of Appeals for the D.C. Circuit decision that had vacated the CSAPR. The EPA filed a motion with the U.S. Court of Appeals for the D.C. Circuit on June 26, 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion, allowing the first compliance period, Phase I, to begin on January 1, 2015, with Phase II beginning in 2017. 

CSAPR requires five states in the eastern half of the United States, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone or fine particulate pollution in other states. These states are required to make summertime NO_x reductions under the CSAPR ozone season control program. CSAPR does not require installation of controls; rather it requires that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances will be allocated to facilities from each state’s annual budget and can be bought and sold.

In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017-2020) have not been distributed. Based on our initial accounting of the NO_x and SO₂ Phase I allowances already issued, and our review of the CSAPR Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will be in compliance in both Phase I and Phase II.

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

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

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

ALLETE, Inc. 2014 Form 10-K

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Environmental Matters (Continued)

Air (Continued)

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $250 million through 2016, of which $145 million was spent through December 31, 2014. Boswell Unit 3 is also subject to the MATS rule; however, the emission reduction investments completed in 2009 at our Boswell Unit 3 generating unit substantially meet the requirements of the MATS rule. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in a November 2013 order, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015 to position the Company for MATS compliance. On January 9, 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS to June 1, 2015, in order to align the Unit 3 retirement with MISO’s resource planning year.

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

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT) became effective in December 2012. Major existing sources have until January 31, 2016, to achieve compliance with the final rule. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. We expect compliance to consist largely of adjustments to our operating practices; therefore costs for complying with the final rule are not expected to be material at this time.

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

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. On November 25, 2014, the EPA proposed a 65 to 70 parts per billion (ppb) NAAQS for ground level ozone. The EPA is proposing to update both the primary ozone standard and the secondary standard. Both standards would be 8-hour standards set within a range of 65 to 70 ppb. The EPA is also seeking comment on levels for the primary standard as low as 60 ppb. The EPA has announced it will accept comments on all aspects of the proposal, including retaining the existing standard. A final rule is expected to be issued in the fourth quarter of 2015. The costs for complying with the final ozone NAAQS cannot be estimated at this time.

ALLETE, Inc. 2014 Form 10-K

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Environmental Matters (Continued)

Proposed and Finalized National Ambient Air Quality Standards (NAAQS) (Continued)

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in September 2006. Since then, the EPA has established more stringent 24-hour and annual average fine particulate matter (PM_2.5) standards; the 24-hour coarse particulate matter standard has remained unchanged. In December 2012, the EPA issued a final rule implementing a more stringent annual PM_2.5 standard, while retaining the current 24-hour PM_2.5 standard. To implement the new annual PM_2.5 standard, the EPA is also revising aspects of relevant monitoring, designation and permitting requirements. New projects and permits must comply with the new standard, which is generally demonstrated by modeling at the facility level.

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by December 2013, based on already available monitoring data. The EPA issued designations of 2012 fine particulate attainment status on December 18, 2014. Minnesota retained attainment status; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly, the costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

SO₂ and NO₂ NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO₂ and NO₂. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO₂ NAAQS also may require the EPA to evaluate modeling data to determine attainment. In April 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by June 2013. However, the State of Minnesota has delayed completing the documents pending EPA guidance to states for preparing the SIP submittal. The MPCA has indicated it will communicate with affected sources once it has more information on how the state will meet the EPA’s SIP requirements. Guidance was expected in 2013 but has been delayed. 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.

In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Band) announced that it had petitioned the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Band does not currently possess authority to directly regulate air quality. Federal Class I air shed status, if granted, would allow the Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have applied for and received Class I status. A public hearing was held by the Band on October 2, 2014, and the public comment period on the petition expired on November 10, 2014. The Band is now preparing responses to the comments after which the Band will make a formal submittal request to the EPA. There is no deadline for the approval, denial, or modification of the request by the EPA. The Company has requested additional clarification from the Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation. We are unable to determine the impact of potential Class I status on the Company’s operations at this time. 

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

• Expanding our renewable energy supply;

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

• Improving efficiency of our energy generating facilities;

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

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

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

ALLETE, Inc. 2014 Form 10-K

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Environmental Matters (Continued)

Climate Change (Continued)

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

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

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

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

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

The EPA proposed that BSER is comprised of four building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, 3) building more or preserving existing zero- and low-emitting power sources, including renewable and nuclear energy, and 4) more efficient electricity use by consumers.

The EPA then established state goals, expressed as a carbon intensity target in CO₂ tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company. We submitted comments on the CPP to the EPA.

Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its “EnergyForward” strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Regulated Operations - EnergyForward.)

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.

ALLETE, Inc. 2014 Form 10-K

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Environmental Matters (Continued)

Climate Change (Continued)

Minnesota’s Next Generation Energy Act of 2007. On April 14, 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO₂-producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO₂ emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit on May 16, 2014.

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule was published in the Federal Register on August 15, 2014, with an effective date of October 14, 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDEC permits have been re-issued containing 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance; however, our preliminary assessment suggests costs of compliance could be up to approximately $15 million. We would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In April 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register in June 2013, and public comments were due in September 2013. The EPA is expected to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. We would seek recovery of any additional costs through cost recovery riders or in a general rate case

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 (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).

ALLETE, Inc. 2014 Form 10-K

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Environmental Matters (Continued)

Solid and Hazardous Waste (Continued)

The EPA issued the final CCR rule on December 19, 2014 under Subtitle D (non-hazardous) of RCRA. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. The final rule also includes provisions that could incentivize early closure of existing impoundments within a three-year window. Costs of compliance, primarily for Boswell and Laskin, could be up to approximately $130 million. The Company continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. We would seek recovery of any additional costs through a general rate case.

Employees

At December 31, 2014, ALLETE had 1,625 employees, of which 1,581 were full-time.

Minnesota Power and SWL&P have an aggregate of 586 employees who are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. The current labor agreements with IBEW Local 31 expire on January 31, 2018.

BNI Coal has 172 employees, of which 125 are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2019.

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, Inc. 2014 Form 10-K

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Executive Officers of the Registrant

As of February 17, 2015, these are the executive officers of ALLETE:

Executive Officers	Initial Effective Date
Alan R. Hodnik, Age 55
Chairman, President and Chief Executive Officer	May 10, 2011
President and Chief Executive Officer	May 1, 2010
President	May 1, 2009
Robert J. Adams, Age 52
Vice President – Energy-Centric Businesses and Chief Risk Officer	June 23, 2014
Vice President – Business Development and Chief Risk Officer	May 13, 2008
Deborah A. Amberg, Age 49
Senior Vice President, General Counsel and Secretary	January 1, 2006
Steven Q. DeVinck, Age 55
Senior Vice President and Chief Financial Officer	March 3, 2014
Controller and Vice President – Business Support	December 5, 2009
David J. McMillan, Age 53
Senior Vice President – External Affairs	January 1, 2012
Senior Vice President – Marketing, Regulatory and Public Affairs	January 1, 2006
Executive Vice President – Minnesota Power	January 1, 2006
Steven W. Morris, Age 53
Controller	March 3, 2014
Donald W. Stellmaker, Age 57
Vice President and 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 or management positions. Prior to election to the position listed above, Mr. Morris held the following positions with the Company during the preceding five years: Director - Accounting; Director - Internal Audit.

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 12, 2015.

ALLETE, Inc. 2014 Form 10-K

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Item 1A. Risk Factors

The risks and uncertainties discussed below could materially affect our business, financial position 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, financial position, results of operations and cash flows. Accordingly, the risks described below should be carefully considered together with other information set forth in this report and in future reports that are filed with the SEC.

Our results of operations could be negatively impacted if our Large Power Customers experience an economic downturn,incurwork stoppages, fail to compete effectively in the economy or experience decreased demand for their product.

Minnesota Power’s 10 Large Power Customers accounted for 28 percent of our 2014 consolidated operating revenue (31 percent in 2013; 33 percent in 2012), of which one of these customers accounted for 10.8 percent of consolidated revenue in 2014 (12.0 percent in 2013; 12.3 percent in 2012). 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 experience decreased demand for their product, there could be material adverse effects on their operations and, consequently, this 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 MPCA, 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. Energy policy initiatives at the state or federal level could increase incentives for distributed generation, municipal utility ownership, or local initiatives could introduce generation or distribution requirements, that could change the current integrated utility model. 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 it was determined that we were not 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.

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 and other organizations. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our results of operations.

Our ability to obtain rate adjustments to maintain reasonable rates of return depends upon regulatory action under applicable statutes and regulations, and we cannot provide assurance that rate adjustments will be obtained or reasonable 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 granted at the requested level, we may experience a material adverse impact on our financial position, 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.

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Item 1A. Risk Factors (Continued)

Our operations pose certain environmental risks that could materially adversely affect our financial position and results of operations, including effects of environmental laws and regulations, physical risks associated with climate change and initiatives designed to reduce the impact of GHG emissions.

We are subject to extensive environmental laws and regulations affecting many aspects of our present and future operations, including air quality, water quality and usage, waste management, reclamation, hazardous wastes, avian mortality 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, water discharge and wind generation facilities.

These laws and regulations could restrict the output of some existing facilities, limit the use of some fuels in the production of electricity, require the installation of 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.

The scientific community generally accepts that emissions of GHG 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 materially adversely affect our business and operations.

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. In June 2013, President Obama announced a Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions. The implementation of the CAP could have a material impact on our results of operations if additional capital expenditures and operating costs are required and if those costs are not fully recovered from customers.

In June 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants (CPP). In the CPP, the EPA proposes to set state-specific rate-based goals for CO₂ emissions from the power sector that the EPA maintains are achievable if a state undertakes a combination of measures across its power sector that constitute the EPA’s guideline for a Best System of Emission Reductions. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. The implementation of the CPP could have a material impact on our results of operations if additional capital expenditures and operating costs are required and if those costs are not fully recovered from customers.

There is significant uncertainty regarding whether new laws or regulations will be adopted to reduce GHGs and what effect any such laws or regulations would have on us. In 2014, coal was the primary fuel source for 85 percent of the energy produced by our generating facilities. Future limits on GHG emissions would likely require us to incur significant increases in capital expenditures and operating costs, which if significant, 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.

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Item 1A. Risk Factors (Continued)

We cannot predict the amount or timing of all future expenditures related to environmental matters because of 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.

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 materially adversely affected.

We rely on access to financing sources and 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, or at all, the ability to maintain our business or to implement our business plans may be materially adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or materially adversely affect our ability to access capital markets. Such disruptions could include a significant economic downturn, the financial distress of non-affiliated electric utility companies or financial services companies, a deterioration in capital market conditions, or volatility in commodity prices.

The operation and maintenance of our electric generation and transmission facilities are subject to operational risks that could materially adversely affect our financial position, results of operations and cash flows.

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. A significant portion of our 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. Generation and transmission facilities and equipment are also likely to require periodic upgrades and improvements due to changing environmental standards and technological advances. We could be subject to costs associated with any unexpected failure to produce and/or deliver 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.

Our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables.

We are, or may be, engaged in significant capital improvements to its existing electric generation facilities, including the installation of pollution control equipment and the conversion of certain coal-fired electric generation facilities to natural gas. We are also engaged in development and/or construction of new wind and transmission facilities. Should any such efforts be unsuccessful or not completed in a timely manner, we could be subject to additional costs or impairments which could have a material adverse impact on our financial position and results of operation.

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

We depend on our 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 limited. 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, which could have a material impact on our business, operations or results of operations.

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Item 1A. Risk Factors (Continued)

The price of electricity and fuel may be volatile.

Volatility in market prices for electricity and fuel could materially adversely impact our financial position and results of operations 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 our 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.

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 a material 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, 2018, and March 31, 2019, 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 materially 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 significantly decrease demand for our current products and services.

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Item 1A. Risk Factors (Continued)

We may be vulnerable to acts of terrorism or cyber attacks.

Our generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities, including cybersecurity attacks, which could result in the disruption of our ability to produce or distribute some portion of our energy products. We could be subject to computer viruses, terrorism, theft and sabotage, which may also disrupt our operations and/or materially adversely impactour results of operations. 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 financial position, results of operations and cash flows.

The inability to successfully manage and grow our Energy Infrastructure and Related Services businesses could materially adversely affect our results of operations.

Our Energy Infrastructure and Related Services businesses consist of ALLETE Clean Energy, U.S. Water Services and BNI Coal. If we are unable to successfully integrate the U.S. Water Services’ business we acquired in February 2015, this could materially adversely affect our results of operations. U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. If U.S. Water Services is unable to retain its existing customers and to add new industrial customers, this would prevent us from profitably operating this business and prevent us from achieving our future growth expectations.

In addition, ALLETE Clean Energy’s wind facilities are parties to long-term PPAs which expire prior to the end of the estimated useful lives of the facilities. If there is not a market for this energy subsequent to the expiration of the PPAs, this could adversely affect our results of operations.

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 materially adversely affect our financial position and results of operations.

Acquisitions are subject to uncertainties. If we are unable to successfully manage future acquisitions or strategic investments, this could have a material 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.

We may not be able to successfully implement our strategic objectives of growing load at our utilities if current or potential industrial or municipal customers are unable to successfully implement expansion plans, including the inability to obtain necessary governmental permits.

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 does not obtain any necessary governmental (including environmental) permits and approvals, our long-term strategy and thus our results of operations could be materially adversely impacted. Furthermore, even if the necessary permits and approvals are obtained, our long-term strategy could be materially adversely impacted if these customers are unable to successfully implement expansion plans.

Real estate market conditions where our Florida real estate investment is located may affect our strategy to sell our Florida real estate.

We intend to sell our Florida land assets when opportunities arise. However, adverse market conditions could impact our future operations, which could result in little to no sales while still incurring operating expenses such as community development district assessments and property taxes, as well as continued annual net operating losses at ALLETE Properties. Furthermore, weak market conditions could put the properties at risk for impairment which could materially adversely impact our results of operations.

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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 regulatory proceedings is included in Item 1. Business and is incorporated by reference herein.

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act, which it supplemented in March 2014. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of December 31, 2014, because a potential loss is not currently probable or reasonably estimable.

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

Item 4. Mine Safety Disclosures

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

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 $0.505 per share on our common stock is payable on March 1, 2015, to the shareholders of record on February 16, 2015. The timing and amount of future dividends will depend upon earnings, cash requirements, the financial condition of the Company, applicable government regulations and other factors deemed relevant by the ALLETE Board of Directors.

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:

		2014				2013
	Price Range		Dividends		Price Range		Dividends
Quarter	High	Low	Declared		High	Low	Declared
First	$52.73	$47.96		$0.49	$49.50	$41.39		$0.475
Second	$52.54	$47.51	0.49		$52.25	$46.85	0.475
Third	$51.56	$44.39	0.49		$54.14	$45.78	0.475
Fourth	$57.97	$44.19	0.49		$51.72	$47.48	0.475
Annual Total				$1.96				$1.90

At February 1, 2015, there were approximately 25,000 common stock shareholders of record.

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Item 6. Selected Financial Data

	2014			2013			2012			2011			2010
Millions
Operating Revenue		$1,136.8			$1,018.4			$961.2			$928.2			$907.0
Operating Expenses	948.0			864.3			806.0			778.2			771.2
Net Income	125.5			104.7			97.1			93.6			74.8
Less: Non-Controlling Interest in Subsidiaries (a)	0.7			—			—			(0.2		)	(0.5		)
Net Income Attributable to ALLETE		$124.8			$104.7			$97.1			$93.8			$75.3
Common Stock Dividends		$83.8			$75.2			$69.1			$62.1			$60.8
Earnings Retained in Business		$41.0			$29.5			$28.0			$31.7			$14.5
Shares Outstanding – Millions
Year-End	45.9			41.4			39.4			37.5			35.8
Average (b)
Basic	42.9			39.7			37.6			35.3			34.2
Diluted	43.1			39.8			37.6			35.4			34.3
Diluted Earnings Per Share		$2.90			$2.63			$2.58			$2.65			$2.19
Total Assets		$4,360.8			$3,476.8			$3,253.4			$2,876.0			$2,609.1
Long-Term Debt		$1,272.8			$1,083.0			$933.6			$857.9			$771.6
Return on Common Equity	8.6		%	8.3		%	8.6		%	9.1		%	7.8		%
Common Equity Ratio	54		%	55		%	54		%	56		%	56		%
Dividends Declared per Common Share		$1.96			$1.90			$1.84			$1.78			$1.76
Dividend Payout Ratio	68		%	72		%	71		%	67		%	80		%
Book Value Per Share at Year-End		$35.04			$32.43			$30.50			$28.77			$27.25
Capital Expenditures by Segment
Regulated Operations		$583.5			$326.3			$418.2			$228.0			$256.4
Investments and Other	20.8			13.2			14.0			18.8			3.6
Total Capital Expenditures		$604.3			$339.5			$432.2			$246.8			$260.0

(a) The 2014 non-controlling interest in subsidiaries relates to the January 2014 acquisition made by ALLETE Clean Energy. (See Note 7. Acquisitions.) In 2011, the ALLETE Properties non-controlling interest was purchased.

(b) Excludes unallocated ESOP shares.

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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 the Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the risks set forth 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 144,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Investments and Otheris comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, our business which acquired four wind energy facilities in 2014 and is developing a wind facility to be sold in 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. Our Energy Infrastructure and Related Services businesses will also include U.S. Water Services, which we acquired in February 2015.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2014, 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.

2014 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2014, to the year ended December 31, 2013.

Net income attributable to ALLETE for 2014 was $124.8 million, or $2.90 per diluted share, compared to $104.7 million, or $2.63 per diluted share, for 2013. Net income for 2014 reflected a $1.4 million after-tax expense, or $0.03 per share, of acquisition costs for ALLETE Clean Energy’s wind energy facilities acquisition which closed in January 2014. (See Note 7. Acquisitions.) In addition, net income for 2014 reflected a $2.5 million after-tax expense, or $0.06 per share, reflecting a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. (See Note 12. Commitments, Guarantees and Contingencies.) Net income for 2014 reflected higher net income at Minnesota Power and ALLETE Clean Energy. Earnings per share dilution was $0.23 due to additional shares of common stock outstanding as of December 31, 2014. (See Note 13. Common Stock and Earnings Per Share.)

Regulated Operations net income attributable to ALLETE was $124.4 million in 2014, compared to $104.9 million in 2013. Net income for 2014 reflected a $2.5 million after-tax expense, or $0.06 per share, reflecting a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. Net income for 2014 reflected higher net income at Minnesota Power primarily due to higher cost recovery rider revenue and production tax credits, and higher power marketing sales as the Square Butte resale agreement with Minnkota Power commenced June 1, 2014. These increases were partially offset by higher operating and maintenance, depreciation, and interest expenses.

Investments and Other reflected net income attributable to ALLETE of $0.4 million in 2014, compared to a net loss of $0.2 million in 2013. Net income in 2014 reflected a $1.4 million after-tax expense, or $0.03 per share, of acquisition costs for ALLETE Clean Energy’s wind energy facilities acquisition in January 2014. Net income for 2014 reflected net income at ALLETE Clean Energy of $3.3 million (net loss of $3.4 million in 2013). BNI Coal recorded net income of $6.1 million in 2014 ($5.6 million in 2013). ALLETE Properties recorded a net loss of $2.3 million in 2014 (net loss of $2.7 million in 2013).

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2014 Compared to 2013

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

Regulated Operations

Operating Revenueincreased$78.0 million, or 8 percent, from 2013 primarily due to a 5.1 percent increase in kilowatt-hour sales, higher cost recovery rider revenue, transmission revenue, gas sales, and fuel adjustment clause recoveries.

Revenue from Regulated Operations increased $30.5 million due to a 5.1 percentincrease in kilowatt-hour sales. The increase was due primarily to a 27.5 percent increase in kilowatt-hour sales to Other Power Suppliers. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations, and increased due to the commencement of the Minnkota Power sales agreement on June 1, 2014. (See Note 12. Commitments, Guarantees and Contingencies.) Also contributing to the increase were higher sales to industrial customers resulting from increased industrial production. The decrease in sales to our municipal customers reflects a wholesale customer contract expiration effective December 31, 2013.

Kilowatt-hours Sold	2014	2013	Quantity Variance		% Variance
Millions
Regulated Utility
Retail and Municipal
Residential	1,204	1,177	27		2.3
Commercial	1,468	1,455	13		0.9
Industrial	7,487	7,338	149		2.0
Municipal	864	999	(135	)	(13.5	)
Total Retail and Municipal	11,023	10,969	54		0.5
Other Power Suppliers	2,904	2,278	626		27.5
Total Regulated Utility Kilowatt-hours Sold	13,927	13,247	680		5.1

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

Cost recovery rider revenue increased $29.4 million primarily due to higher capital expenditures related to the Bison Wind Energy Center and the Boswell Unit 4 environmental upgrade.

Transmission revenue increased $7.7 million primarily due to the commencement of recovery of our transmission investment related to the 230 kV transmission system upgrade that was placed into service in March 2013 (see Outlook– Industrial Customers and Prospective Additional Load – Nashwauk Public Utilities Commission) and higher MISO related revenue.

Revenue from gas sales at SWL&P increased $4.6 million as a result of the unseasonably cold weather during the first four months of 2014. (See Operating Expenses – Operating and Maintenance Expense.)

Fuel adjustment clause recoveries increased $4.6 million due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses – Fuel and Purchased Power Expense.)

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2014 Compared to 2013 (Continued)

Regulated Operations (Continued)

Operating Expenses increased $52.3 million, or 7 percent, from 2013.

Fuel and Purchased Power Expenseincreased$21.3 million, or 6 percent, from 2013 primarily due to an increase in purchased power resulting from higher kWh sales and higher wholesale prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue.)

Operating and Maintenance Expenseincreased$23.2 million, or 7 percent, from 2013. In 2014, a $4.2 million expense was recorded to reflect a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. Operating and maintenance expense was also higher due to higher transmission expense, purchased gas, and property taxes partially offset by lower benefit expense. Transmission expense increased primarily due to higher MISO related expenses. Purchased gas expense increased due to higher gas sales in 2014; purchased gas expenses are recovered from our customers through a purchased gas adjustment clause. (See Operating Revenue.) Property tax expense increased as a result of higher taxable plant and rates. Benefit expense was lower due to higher discount rates in 2014 attributable to our defined benefit pension and other postretirement benefit plans.

Depreciation Expenseincreased$7.8 million, or 7 percent, from 2013 reflecting additional property, plant and equipment in service.

Interest Expenseincreased$4.8 million, or 11 percent, from 2013 primarily due to higher average long-term debt balances.

Other Incomeincreased$3.1 million, or 66 percent, from 2013 primarily due to higher AFUDC-Equity.

Income Tax Expenseincreased$3.8 million, or 11 percent, from 2013 primarily due to higher pretax income in 2014, partially offset by higher federal production tax credits in 2014.

Investments and Other

Operating Revenueincreased$40.4 million, or 43 percent, from 2013 primarily due to a $33.2 million increase in revenue from ALLETE Clean Energy due to the 2014 wind facility acquisitions. Also contributing to the increase was a $2.7 million increase in revenue at BNI Coal, which operates under cost-plus fixed fee contracts, resulting from increased coal deliveries and higher expenses in 2014. (See Operating Expenses.) ALLETE Properties revenue increased $1.8 million primarily due to higher wetland mitigation bank credit sales.

Operating Expenses increased $31.4 million, or 32 percent, from 2013 primarily due to higher operating and depreciation expenses of $20.3 million as a result of the ALLETE Clean Energy wind energy facilities acquisitions in 2014. Also contributing to the increase were higher expenses of $1.0 million at BNI Coal primarily due to higher salaries and repair expenses, which are recovered through the cost-plus fixed fee contracts. (See Operating Revenue.) ALLETE Properties had higher expense due to increased wetland mitigation bank credit sales. 2013 included a gain as a result of the termination of a legacy benefit plan.

Interest Expensedecreased$0.3 million, or 4 percent, from 2013 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.

Other Incomedecreased$3.8 million, or 83 percent, from 2013 primarily due to gains on sales of investments in 2013.

Income Tax Benefits decreased $4.2 million, or 57 percent, from 2013 primarily due to a decrease in pretax losses.

Income Taxes – Consolidated

For the year ended December 31, 2014, the effective tax rate was 22.6 percent (21.5 percent for the year ended December 31, 2013). The increase from the year ended December 31, 2013, was primarily due to higher pretax income in 2014, partially offset by increased federal production tax credits in 2014 related to additional wind generation. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, federal production tax credits, state income tax credits and depletion. (See Note 15. Income Tax Expense.)

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2013 Compared to 2012

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

Regulated Operations

Operating Revenueincreased $51.1 million, or 6 percent, from 2012 primarily due to a 1.2 percent increase in kilowatt-hour sales, and higher fuel adjustment clause recoveries, transmission revenue, cost recovery rider revenue, gas sales, and municipal rates.

Fuel adjustment clause recoveries increased $13.5 million due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses – Fuel and Purchased Power Expense.)

Transmission revenue increased $6.3 million primarily due to the commencement of recovery of our transmission investment related to the 230 kV transmission system upgrade that was placed into service in March 2013 (see Outlook– Prospective Additional Load – Nashwauk Public Utilities Commission) and higher MISO Regional Expansion Criteria and Benefits (RECB) revenue related to CapX2020 transmission projects.

Cost recovery rider revenue increased $5.3 million primarily due to higher capital expenditures related to our Bison Wind Energy Center, CapX2020 projects and the Boswell Unit 4 environmental upgrade. Our Bison 1, 2 and 3 wind facilities were completed in various phases through December 2012. Cost recovery for our Boswell Unit 4 mercury emissions reduction plan was approved by the MPUC in November 2013.

Revenue from gas sales at SWL&P increased $4.8 million as heating degree days in 2013 were approximately 22 percent higher than 2012. The increase was also due to higher purchased gas expenses. (See Operating Expenses – Operating and Maintenance Expense.)

Revenue from our municipal customers increased $3.8 million as a result of higher rates under the cost-based formula primarily due to higher capital expenditures, as well as 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 increased $13.8 million due to a 1.2 percent increase in kilowatt-hour sales. The increase was due primarily to a 14.0 percent increase in kilowatt-hour sales to Other Power Suppliers. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. Also contributing to the increase was higher sales to residential and commercial customers. Heating degree days in Duluth, Minnesota were approximately 22 percent higher in 2013 than 2012. Kilowatt-hour sales to industrial customers decreased 2.2 percent from 2012 primarily due to 154 million kilowatt-hours sold in 2012 through a short-term, fixed price contract.

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2013 Compared to 2012 (Continued)

Regulated Operations (Continued)

Kilowatt-hours Sold	2013	2012	Quantity Variance		% Variance
Millions
Regulated Utility
Retail and Municipal
Residential	1,177	1,132	45		4.0
Commercial	1,455	1,436	19		1.3
Industrial	7,338	7,502	(164	)	(2.2	)
Municipal	999	1,020	(21	)	(2.1	)
Total Retail and Municipal	10,969	11,090	(121	)	(1.1	)
Other Power Suppliers	2,278	1,999	279		14.0
Total Regulated Utility Kilowatt-hours Sold	13,247	13,089	158		1.2

Revenue from electric sales to taconite customers accounted for 25 percent of consolidated operating revenue in 2013 (26 percent in 2012). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 8 percent of consolidated operating revenue in 2013 (9 percent in 2012). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2013 (6 percent in 2012).

Operating Expenses increased $54.8 million, or 8 percent, from 2012.

Fuel and Purchased Power Expenseincreased$26.1 million, or 8 percent, from 2012 primarily due to higher company generation, kilowatt-hours sold and purchased power prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue.) A scheduled major outage in 2013 also increased costs under the Square Butte purchased power contract.

Operating and Maintenance Expenseincreased$12.4 million, or 4 percent, from 2012 primarily due to higher property tax expenses as a result of higher taxable plant and rates, higher transmission expense primarily due to higher MISO RECB expense, higher operating and maintenance expenses related to our Bison 1, 2 and 3 wind facilities, which were in service in 2013, and higher purchased gas expenses. Purchased gas expenses increased due to higher gas sales at SWL&P in 2013 as heating degree days in 2013 were approximately 22 percent higher than 2012; purchased gas costs are recovered from our customers through a purchased gas adjustment clause from customers. (See Operating Revenue.)

Depreciation Expenseincreased$16.3 million, or 17 percent, from 2012 reflecting additional property, plant and equipment in service.

Interest Expenseincreased$2.3 million, or 6 percent, from 2012 primarily due to higher average long-term debt balances.

Income Tax Expensedecreased$14.3 million, or 28 percent, from 2012 primarily due to higher federal production tax credits in 2013 as our Bison Wind Energy Center was completed in various phases through December 2012 and in service in 2013.

Investments and Other

Operating Revenueincreased$6.1 million, or 7 percent, from 2012 primarily due to a $3.6 million increase in revenue at BNI Coal and a $2.3 million increase in revenue at ALLETE Properties. BNI Coal, which operates under a cost-plus fixed fee contract, recorded higher revenue as a result of higher expenses in 2013 (see Operating Expenses), which was partially offset by fewer tons sold in 2013. The increase at ALLETE Properties was primarily due to land sales in 2013.

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2013 Compared to 2012 (Continued)

Investments and Other (Continued)

ALLETE Properties	2013			2012
Revenue and Sales Activity	Acres (a)	Amount		Acres (a)	Amount
Dollars in Millions
Revenue from Land Sales	293		$3.5	—	—
Other Revenue (b)		0.9				$2.1
Total ALLETE Properties Revenue			$4.4			$2.1

(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 $1.1 million.

Operating Expenses increased $3.5 million, or 4 percent, from 2012 reflecting higher expenses at BNI Coal of $5.0 million primarily due to higher repairs, fuel and labor costs; these costs are recovered through the cost-plus contract. (See Operating Revenue.) Operating expenses in 2013 also included $1.0 million of acquisition costs for the January 2014 ALLETE Clean Energy acquisition and higher cost of land sales at ALLETE Properties. These increases were partially offset by gains as a result of the termination of a legacy benefit plan and lower operating expenses related to our non-rate base generation.

Interest Expense increased $2.5 million from 2012 primarily due to 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.

Other Income increased $3.7 million from 2012 primarily due to gains on sales of investments.

Income Tax Benefits decreased $5.0 million, or 40 percent, from 2012 primarily due to a decrease in pretax losses and higher state tax expense. State income tax expense was higher in 2013 as more North Dakota income tax credits attributable to our North Dakota capital investments were recognized in 2012.

Income Taxes – Consolidated

For the year ended December 31, 2013, the effective tax rate was 21.5 percent (28.1 percent for the year ended December 31, 2012). The decrease from the year ended December 31, 2012, was primarily due to increased federal production tax credits in 2013 related to additional wind generation assets in service during 2013. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, federal production tax credits, state income tax credits and depletion. (See Note 15. 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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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, the discount rate, and mortality assumptions, 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, 2014 was approximately 48 percent equity securities, 39 percent debt, 8 percent private equity, and 5 percent real estate. Our postretirement health and life asset allocation at December 31, 2014, was approximately 58 percent equity securities, 34 percent debt, and 8 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2014, we used expected long-term rates of return of 8.00 percent in our actuarial determination of our pension expense and 6.40 percent to 8.00 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 $1.5 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 2014, we used discount rates of 4.93 percent and 4.96 percent in our actuarial determination of our pension and other postretirement expense, respectively. We review our discount rates annually and will adjust them 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 $1.3 million, pretax.

The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2014 considered a modified RP-2014 mortality table and an updated mortality projection scale. (See Note 17. 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, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net 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, may vary among each land parcel or bulk sale, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future 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.

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Critical Accounting Policies (Continued)

Taxation (Continued)

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 or change in tax rates could require new or increased valuation allowances which could result in a material impact on our results of operations.

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 long-term objectives of achieving minimum average earnings per share growth of 5 percent per year and providing a dividend payout competitive with our industry.

ALLETE is predominantly a regulated utility through Minnesota Power, SWL&P and an investment in ATC. Minnesota Power believes it is well positioned for the future as it executes on its EnergyForward initiative and serves a potentially growing industrial customer base. 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 regulators to earn a fair rate of return. We believe that ATC is poised for future growth both organically and through its partnership with Duke Energy.

In February 2015, ALLETE acquired U.S. Water Services, consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. ALLETE will now focus its energy infrastructure and related service efforts on ALLETE Clean Energy, U.S. Water Services and BNI Coal. ALLETE Clean Energy has a growing portfolio of wind generating facilities, and U.S. Water Services provides integrated water management to a growing base of industrial and commercial customers. ALLETE’s Energy Infrastructure and Related Services businesses primarily have contracted or recurring revenues.

ALLETE is focused on providing sustainable solutions to our customers, as exemplified by the EnergyForward and Power of One initiatives at Minnesota Power, renewable energy investments at ALLETE Clean Energy, and investment in U.S. Water Services.

Regulated Operations. Minnesota Power’s long-term strategy is to be the leading electric energy provider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable requirements. Keeping the cost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain customer viability. As part of maintaining cost competitiveness, Minnesota Power intends to reduce its exposure to possible future carbon and GHG legislation by reshaping its generation portfolio, over time, to reduce its reliance on coal. (See Regulated Operations – EnergyForward.) We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with regulators to earn a fair rate of return. We project that Minnesota Power will not earn its allowed rate of return in 2015.

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

Industrial Customers and Prospective Additional Load

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and secondary wood products, and pipeline industries. In 2014, 54 percent (55 percent in 2013) of our Regulated Utility kWh sales were made to our industrial customers in these industries.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load (Continued)

Five of Minnesota Power’s 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. Also, two of Minnesota Power’s iron concentrate customers have the capability to produce up to approximately 2 million metric tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets.

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 2015 will be similar to 2014. The American Iron and Steel Institute (AISI), an association of North American steel producers, reported that U.S. raw steel production operated at approximately 77 percent of capacity in 2014 (77 percent in 2013; 75 percent in 2012). Based on these projections, 2015 taconite production levels in Minnesota are expected to be similar to 2014.

Minnesota Power Taconite Customer Production
Year	Tons (Millions)
2014*	39
2013	37
2012	39
2011	39
2010	35
2009	17
2008	39
2007	38
2006	39
2005	40
Source: Minnesota Department of Revenue 2014 Mining Tax Guide for years 2005 - 2013.
* 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 expected power marketing sales at 2014 year-end prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Long-term reductions in taconite 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, three of four major paper and pulp mills we serve reported operations at, or near, full capacity in 2014 and similar levels are expected in 2015. Boise, Inc. (Boise) operates a paper mill in International Falls, Minnesota. On September 12, 2014, Boise provided the required one-year written notice of its intent to install additional generation at its mill in late 2015. Boise’s reduction in demand is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

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 pipeline industries and include Essar Steel Minnesota LLC (Essar), PolyMet Mining Corporation (PolyMet), Magnetation, LLC (Magnetation), and Enbridge, Inc. (Enbridge). We cannot predict the outcome of these projects.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load (Continued)

Nashwauk Public Utilities Commission. In April 2014, the Company amended its formula-based wholesale electric sales agreement with the Nashwauk Public Utilities Commission for all of its electric service requirements, extending the term through June 30, 2026. A new Essar taconite facility is currently under construction in the city of Nashwauk, and the Nashwauk Public Utilities Commission also amended and extended its electric service agreement with Essar. Upon completion, this facility would result in approximately 110 MW of additional load for Minnesota Power. Under the terms of a facilities construction agreement, Minnesota Power constructed a 230 kV transmission system upgrade to serve the Essar load which was placed into service in March 2013. This upgrade will allow the Nashwauk Public Utilities Commission to provide electric service for Essar’s new taconite facility. Billings to Essar to recover our transmission investments began in April 2013. In October 2014, Essar announced the completion of project financing and stated that initial pellet production would commence in the second half of 2015.

PolyMet. Minnesota Power has executed a long-term contract with PolyMet, which is planning to start a new copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. PolyMet began work on a Supplemental Draft Environmental Impact Statement (SDEIS) in 2010. The SDEIS addressed environmental issues, including those dealing with the land exchange between PolyMet and the U.S. Forest Service (USFS), which is critical to the mine site development. In December 2013, the Minnesota Department of Natural Resources (DNR) released PolyMet’s SDEIS. The Minnesota DNR has estimated that the SDEIS process could be completed in the first half of 2015. Minnesota Power could begin to supply between 45 MW and 50 MW of load through a ten-year power supply contract period that would begin upon start-up of the mining operations.

Magnetation. Magnetation produces iron ore concentrate from low-grade natural ore tailing basins, already mined stockpiles and newly mined iron formations. Magnetation’s facility near Taconite, Minnesota, is fully operational, and its new concentrate facility near Coleraine, Minnesota, commenced production in December 2014. On January 27, 2014, Minnesota Power and Magnetation entered into a new ten-year electric service agreement, which was approved by the MPUC on May 1, 2014, for the facility near Coleraine, Minnesota. This agreement is effective through December 31, 2025. In addition, a transmission service extension was required to be constructed by Minnesota Power. On June 19, 2014, Minnesota Power received MPUC approval of a transmission route for the service extension, permits were received on July 2, 2014, and construction was completed in the fourth quarter of 2014. Minnesota Power expects to supply approximately 20 MW of power to this new facility, making it a Large Power Customer of Minnesota Power. The new facility is expected to supply iron ore concentrate to Magnetation’s new pellet plant in Reynolds, Indiana, which is designed to produce about 3 million tons of taconite pellets annually for AK Steel. On September 29, 2014, Magnetation announced the Reynolds pellet plant commenced production.

Enbridge.Minnesota Power has a long-term contract with Enbridge that extends through December 31, 2020. Enbridge owns and operates generation and distribution systems within the energy industry in North America, including a crude oil and liquids transportation system. Enbridge plans to expand the capacity at two pumping stations located in Minnesota Power’s service territory in Deer River and Floodwood, Minnesota. The project is expected to be complete by 2016. Upon completion, Minnesota Power expects to supply between 5 to 10 MW of additional load. Enbridge also plans to construct a pipeline connecting its Beaver Lodge Station, near Tioga, North Dakota, to an existing terminal in Superior, Wisconsin by 2017. Upon completion of the pipeline, SWL&P expects to supply between 15 to 20 MW of additional load.

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

• Major wind investments in North Dakota. Our Bison Wind Energy Center added 205 MW of capacity in the fourth quarter of 2014, bringing total capacity to 497 MW. (See Renewable Energy.)

• Planned installation of approximately $250 million in emissions control technology at Boswell Unit 4 to further reduce emissions of SO₂, particulates and mercury. (See Boswell Mercury Emission Reduction Plan.)

• Planning for the proposed GNTL to deliver hydroelectric power from northern Manitoba by 2020. (See Transmission.)

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

• Retiring Taconite Harbor Unit 3, one of three coal-fired units at Taconite Harbor, in the second quarter of 2015.

Integrated Resource Plan.In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

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Outlook (Continued)

Energy Forward (Continued)

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and municipal energy sales in Minnesota to be from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits.

Minnesota Power continues to execute its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. Through the strategy outlined in Minnesota Power’s 2013 Integrated Resource Plan, 18 percent of the Company’s total retail and municipal energy sales were supplied by renewable energy sources in 2014. We expect 28 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2015.

Minnesota Solar Energy Standard. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain industrial customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Minnesota Power is in the process of evaluating the potential impact of this legislation on our operations; however, any costs are expected to be recovered in customer rates.

Wind Energy.Our wind energy facilities consist of the 497 MW Bison Wind Energy Center located in North Dakota, which was placed in service in various phases between 2010 and 2014, and our 25 MW Taconite Ridge Energy Center located in northeastern Minnesota. We also have two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) located in North Dakota.

On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills.

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

Manitoba Hydro. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2020. Under this agreement Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. 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. (See Regulated Operations – Transmission.)

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Outlook (Continued)

Energy Forward (Continued)

In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota, and surrounding areas. The flooding impacted Minnesota Power’s St. Louis River hydro system, particularly Thomson, which had damage to the forebay canal and flooding at the facility. The forebay rebuild is complete and Minnesota Power commenced filling the forebay canal on October 9, 2014. Thomson returned to partial generation in the fourth quarter of 2014 and work is ongoing towards returning to full generation early in 2015. Total project costs are estimated to be approximately $90 million, net of insurance. On January 29, 2015, the MPUC approved our petition seeking cost recovery of investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014. On November 26, 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills.

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

Investments and Other

Investments and Otheris comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, U.S. Water Services and BNI Coal. Investments and Other also includes ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

ALLETE Clean Energy.ALLETE Clean Energy aims to develop or acquire capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects.

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015.

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

ALLETE, Inc. 2014 Form 10-K

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Outlook (Continued)

ALLETE Clean Energy (Continued)

On November 20, 2014, ALLETE Clean Energy acquired a business for $27.0 million which is developing a wind facility near Hettinger, North Dakota. ALLETE Clean Energy will develop and construct a 107 MW wind farm using 43 turbines which will then be sold to Montana-Dakota Utilities Co. for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approvals.

On December 17, 2014, ALLETE Clean Energy acquired a wind facility in Storm Lake, Iowa (Storm Lake I) for $15.0 million, subject to a working capital adjustment. Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II which was acquired in January 2014. The wind facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

On December 31, 2014, ALLETE Clean Energy entered into a purchase agreement to acquire wind facilities in southern Minnesota for approximately $47.5 million. The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility acquired in January 2014. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015.

U.S. Water Services.In February 2015, ALLETE acquired U.S. Water Services. Headquartered in St. Michael, Minnesota, U.S. Water Services has a national footprint serving a growing and diverse mix of over 3,600 industrial customers, with recurring revenues and customer retention that exceeds 90 percent. U.S. Water Services provides integrated water management for industry, combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services helps customers achieve efficient and sustainable use of their energy systems, is a leading provider to the biofuels industry, and has a growing presence in the power generation and midstream oil and gas industries. The acquisition is not expected to have a material impact on 2015 earnings per share.

BNI Coal.In 2014, BNI Coal sold 4.0 million tons of coal (3.7 million tons in 2013) and anticipates 2015 sales will be similar to 2014. In 2013, a customer of BNI Coal incurred a scheduled major outage resulting in fewer tons sold. BNI Coal operates under cost-plus fixed fee agreements extending through December 31, 2037.

ALLETE Properties.ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. Market conditions can impact land sales and could result in our inability to cover our operating expenses and fixed carrying costs such as community development district assessments and property taxes. ALLETE does not intend to acquire additional Florida real estate.

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.

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48

Outlook (Continued)

ALLETE Properties (Continued)

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	958	2,412	2,236,700
Palm Coast Park	3,777	3,554	3,096,800
Total Current Development Projects	4,735	5,966	5,333,500
Planned Development Project
Ormond Crossings	2,914	2,950	3,215,000
Other
Lake Swamp Wetland Mitigation Project	3,044	(d)	(d)
Total of Development Projects	10,693	8,916	8,548,500

(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 1,672 acres of other land available-for-sale.

Income Taxes. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2014. On an ongoing basis, ALLETE has tax credits and other tax adjustments that reduce the statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, renewable tax credits, AFUDC-Equity, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income before non-controlling interest and income taxes, state and federal tax law changes that become effective during the year, business combinations and configuration changes, tax planning initiatives and resolution of prior years’ tax matters. Due primarily to increased federal production tax credits as a result of wind generation, we expect our effective tax rate to be approximately 15 percent for 2015. 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, 2014, we had cash and cash equivalents of $145.8 million, $357.2 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:

As of December 31	2014		%	2013		%	2012		%
Millions
ALLETE Equity		$1,609.4	54		$1,342.9	55		$1,201.0	54
Non-Controlling Interest	1.8		—	—		—	—		—
Long-Term Debt (Including Current Maturities)	1,373.5		46	1,110.2		45	1,018.1		46
Notes Payable	3.7		—	—		—	—		—
		$2,988.4	100		$2,453.1	100		$2,219.1	100

ALLETE, Inc. 2014 Form 10-K

49

Liquidity and Capital Resources (Continued)

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

Year Ended December 31	2014			2013			2012
Millions
Cash and Cash Equivalents at Beginning of Period		$97.3			$80.8			$101.1
Cash Flows from (for)
Operating Activities	269.8			239.4			239.6
Investing Activities	(625.7		)	(336.6		)	(420.1		)
Financing Activities	404.4			113.7			160.2
Change in Cash and Cash Equivalents	48.5			16.5			(20.3		)
Cash and Cash Equivalents at End of Period		$145.8			$97.3			$80.8

Operating Activities. Cash from operating activities in 2014 was higher than 2013 primarily due to higher net income, cash contributions of $10.8 million in 2013 to other postretirement benefit plans, and timing of accounts payable payments, which were partially offset by increased fuel inventory purchases in 2014.

Cash from operating activities in 2013 was similar to 2012 as higher net income and lower fuel inventory purchases were offset by decreased other current liabilities due to higher receipts of customer security deposits in 2012 and increased cost recovery rider revenue receivables in 2013.

Investing Activities. Cash used for investing activities in 2014 was higher than 2013 primarily due to higher capital expenditures and ALLETE Clean Energy acquisitions in 2014, partially offset by a transfer of cash included in Other Investments to Cash and Cash Equivalents in 2014.

The decrease in cash used for investing activities in 2013 from 2012 was primarily due to lower payments for capital expenditures and increased proceeds from sales of available-for-sale securities in 2013.

Financing Activities. Cash from financing activities in 2014 was higher than 2013 primarily due to proceeds from the issuance of long-term debt and the issuance of common stock in 2014, partially offset by increased payments on long-term debt and dividends on common stock in 2014.

The decrease in cash from financing activities in 2013 compared to 2012 was primarily due to lower proceeds from long-term debt issuances and the repayment of long-term debt which matured in 2013, partially offset by increased common stock issuances in 2013.

Working Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit, the sale of securities or commercial paper. As of December 31, 2014, we had consolidated bank lines of credit aggregating $408.4 million ($406.4 million as of December 31, 2013), the majority of which expire in November 2018. We had $47.5 million outstanding in standby letters of credit and $3.7 million outstanding in draws under our lines of credit as of December 31, 2014 ($5.4 million in standby letters of credit and no draws outstanding as of December 31, 2013). In addition, as of December 31, 2014, we had 2.1 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, 1.3 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets, Inc. and 1.4 million original issue shares of common stock available for issuance under a forward sale agreement. (See Securities.) The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.

Securities. We entered into a distribution agreement with Lampert Capital Markets, Inc., in February 2008, as amended most recently in May 2014, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 1.3 million shares remain available for issuance. For the year ended December 31, 2014, 1.9 million shares of common stock were issued under this agreement, resulting in net proceeds of $90.0 million (1.3 million shares for net proceeds of $63.4 million for the year ended December 31, 2013; 1.3 million shares for net proceeds of $53.1 million for the year ended December 31, 2012). The shares sold in 2012 and through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

ALLETE, Inc. 2014 Form 10-K

50

Liquidity and Capital Resources (Continued)

Securities (Continued)

For the year ended December 31, 2014, 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 $25.4 million (0.7 million shares were issued for net proceeds of $34.8 million during the year ended December 31, 2013; 0.5 million shares were issued for net proceeds of $23.9 million during the year ended December 31, 2012). These shares of common stock were registered under Registration Statement Nos. 333-188315, 333-183051 and 333-162890.

On January 10, 2014, ALLETE contributed 0.4 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, as amended, and had an aggregate value of $19.5 million when contributed.

On February 26, 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock. Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock from third parties and sold them to the underwriters. ALLETE had the right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elected physical settlement of the Agreement, it would deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price was initially $48.01 per share, subject to adjustment as provided in the Agreement. On September 5, 2014, ALLETE physically settled a portion of its obligations under the Agreement by having delivered approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million. On February 4, 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares for cash proceeds of $65.4 million.

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

During 2014, we issued $375.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market in seven series. The Company used the proceeds from the sale of the Bonds to refinance debt, fund utility capital expenditures and/or for general corporate purposes. (See Note 11. Short-Term and Long-Term Debt.)

On July 1, 2014, we redeemed $111.0 million of pollution control bonds, at par, which were due on July 1, 2022.

Financial Covenants. See Note 11. Short-Term and Long-Term Debt for information regarding our financial covenants.

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 12. Commitments, Guarantees and Contingencies.

ALLETE, Inc. 2014 Form 10-K

51

Liquidity and Capital Resources (Continued)

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 as of December 31, 2014.

	Payments Due by Period
Contractual Obligations			Less than		1 to 3		4 to 5		After
As of December 31, 2014	Total		1 Year		Years		Years		5 Years
Millions
Long-Term Debt		$2,210.9		$159.1		$189.7		$201.7		$1,660.4
Pension (a)	398.5		36.5		75.3		78.9		207.8
Other Postretirement Benefit Plans (a)	93.1		8.0		17.3		18.4		49.4
Operating Lease Obligations	80.5		13.4		22.0		17.8		27.3
Uncertain Tax Positions (b)	—		—		—		—		—
Capital Purchase Obligations (c)	126.3		105.8		18.0		2.5		—
PPA Obligations (d)	459.5		57.5		119.9		125.0		157.1
Other Purchase Obligations	38.4		38.4		—		—		—
		$3,407.2		$418.7		$442.2		$444.3		$2,102.0

(a) Represents the estimated future benefit payments for our defined benefit pension and other postretirement plans through 2024.

(b) Excludes $2.0 million of non-current unrecognized tax benefits due to uncertainty regarding the timing of future cash payments related to uncertain tax positions.

(c) Consists mostly of capital expenditures related to the Boswell Unit 4 environmental upgrade.

(d) Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only, and the agreements with Manitoba Hydro commencing in 2020, as our obligations under these contracts is subject to the construction of a hydro generation facility by Manitoba Hydro and additional transmission capacity. Also, excludes Oliver Wind I and Oliver Wind 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, 2014, remain constant through the remaining term. (See Note 11. 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 future benefit payments through 2024. 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 17. Pension and Other Postretirement Benefit Plans.)

Capital Purchase Obligations. Capital purchase obligations represent our purchase obligations for certain capital expenditure projects. It includes capital expenditures related to the Boswell Unit 4 environmental upgrade and certain transmission projects. (See Note 12. Commitments, Guarantees and Contingencies.)

PPA Obligations. PPA obligations represent our Square Butte, Manitoba Hydro, Minnkota Power and other purchase power contracts. (See Note 12. 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.

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52

Liquidity and Capital Resources (Continued)

Contractual Obligations and Commercial Commitments (Continued)

Minnesota Power has a PPA with Manitoba Hydro that expires in May 2020. Under this agreement, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

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

Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index as well as market prices. Both PPAs are subject to MPUC approval.

Other Purchase Obligations. Other purchase obligations represent our minimum purchase commitments under coal and rail contracts. (See Note 12. Commitments, Guarantees and Contingencies.)

Credit Ratings. Access to reasonably priced capital markets is dependent in part on credit and ratings. Our securities have been rated by Standard & Poor’s and by Moody’s. Rating agencies use both quantitative and qualitative measures in determining a company’s credit rating. These measures include business risk, liquidity risk, competitive position, capital mix, financial condition, predictability of cash flows, management strength and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative ones are more subjective. Our current credit ratings are listed in the table below:

Credit Ratings	Standard & Poor’s	Moody’s
Issuer Credit Rating	BBB+	A3
Commercial Paper	A-2	P-2
First Mortgage Bonds	A	A1

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.

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 2014, we paid out 68 percent (72 percent in 2013; 71 percent in 2012) of our per share earnings in dividends. On January 22, 2015, our Board of Directors declared a dividend of $0.505 per share, which is payable on March 1, 2015, to shareholders of record at the close of business on February 16, 2015.

ALLETE, Inc. 2014 Form 10-K

53

Liquidity and Capital Resources (Continued)

Capital Requirements

ALLETE’s projected capital expenditures for the years 2015 through 2019 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		2015		2016		2017		2018		2019		Total
Millions
Regulated Utility Operations
	Base and Other		$135		$170		$160		$205		$125		$795
	Cost Recovery (a)
	Environmental (b)	90		10		—		—		—		100
	Renewable	10		—		—		—		—		10
	Transmission (c)	15		25		70		105		120		335
	Total Cost Recovery	115		35		70		105		120		445
Regulated Utility Capital Expenditures		250		205		230		310		245		1,240
Other		30		30		30		30		25		145
Total Capital Expenditures			$280		$235		$260		$340		$270		$1,385

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

(b) Environmental capital expenditures primarily related to compliance with the MATS rule for Boswell Unit 4 which reflect Minnesota Power’s ownership percentage of 80 percent. (See Note 12. Commitments, Guarantees and Contingencies.)

(c) Transmission capital expenditures related to construction of the GNTL are estimated at approximately $315 million through 2019. (See Outlook – Regulated Operations.)

We are well positioned to meet our financing needs due to adequate operating cash flows, available additional working capital, and access to capital markets. We will finance capital expenditures from a combination of internally generated funds and debt and equity issuance proceeds. We intend to maintain a capital structure with capital ratios near current levels. (See Liquidity and Capital Resources – Capital Structure.) Based on our projected capital expenditures reflected above, we project our rate base to grow by approximately 15 percent from 2014 year-end through 2019.

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 12. Commitments, Guarantees and Contingencies. (See Item 1. Business – Environmental Matters.)

Market Risk

Securities Investments

Available-for-Sale Securities. At December 31, 2014, our available-for-sale securities portfolio consisted of securities held in other postretirement plans to fund employee benefits. (See Note 8. 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, 2014.

ALLETE, Inc. 2014 Form 10-K

54

Liquidity and Capital Resources (Continued)

Market Risk (Continued)

	Expected Maturity Date
Interest Rate Sensitive Financial Instruments	2015		2016		2017		2018		2019		Thereafter		Total		Fair Value
Dollars in Millions
Long-Term Debt
Fixed Rate		$4.7		$24.9		$54.6		$54.8		$46.9		$1,050.3		$1,236.2		$1,347.2
Average Interest Rate – %	5.3		7.3		6.0		2.2		7.9		4.5		4.7
Variable Rate		$96.0	—		—		—		—			$41.3		$137.3		$137.3
Average Interest Rate – % (a)	1.1		—		—		—		—		0.1		0.8

(a) The $75 million term loan matures in 2015. It has an effective fixed rate of 1.625 percent for the remaining term 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, 2014, and assuming no other changes to our financial structure, an increase of 100 basis points in interest rates would impact the amount of pretax interest expense by $0.6 million. This amount was determined by considering the impact of a hypothetical 100 basis point increase to the average variable interest rate on the variable rate debt outstanding as of December 31, 2014.

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

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

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

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, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, and supplementary data, which are indexed in Item 15(a).

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55

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

As of December 31, 2014, evaluations were performed, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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 updated Internal Control – Integrated Framework (2013 framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The 2013 framework supersedes the original framework issued in 1992 and is effective for all dates after December 15, 2014. Based on our evaluation under the 2013 framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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. The Company is undergoing a project with the objective of improving customer information systems. The focus of the project is the upgrade and addition of certain customer information applications; these changes are not the result of any identified deficiencies in our internal control over financial reporting. The Company expects the project to result in greater efficiencies and enhance the processes used by employees to track power consumption, invoice customers, process payments, and analyze data. Implementation is expected in the first half of 2015.

Item 9B. Other Information

Not applicable.

ALLETE, Inc. 2014 Form 10-K

56

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 2015 Annual Meeting of Shareholders (2015 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 “Corporate Governance” section and the “Audit Committee Report” section;

• Audit Committee Members. The identity of the Audit Committee members will be included in the “Corporate Governance” section and 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 2015 Proxy Statement will be filed with the SEC within 120 days after the end of our 2014 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 Executive Officers,” the “Compensation Committee Report” and the “Director Compensation” sections in our 2015 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 2015 Proxy Statement.

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57

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 2015 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 2015 Proxy Statement.

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	66
	Consolidated Balance Sheet at December 31, 2014 and 2013	67
	For the Three Years Ended December 31, 2014
	Consolidated Statement of Income	68
	Consolidated Statement of Comprehensive Income	69
	Consolidated Statement of Cash Flows	70
	Consolidated Statement of Shareholders’ Equity	71
	Notes to Consolidated Financial Statements	72
(2)	Financial Statement Schedules
	Schedule II – ALLETE Valuation and Qualifying Accounts and Reserves	123
	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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58

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 September 20, 2004 (filed as Exhibit 3 to the September 21, 2004, Form 8-K, File No. 1-3548).
*3(a)3	—	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)4	—	Amendment to Articles of Incorporation, dated as of May 11, 2010 (filed as Exhibit 3(a) to the May 14, 2010, Form 8-K, File No. 1-3548).
*3(a)5	—	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
		Thirty-fourth	April 1, 2013	1-3548 (April 2, 2013 Form 8-K)	4

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59

Exhibit Number
		Thirty-fifth	March 1, 2014	1-3548 (March 31, 2014 Form 10-Q)	4
		Thirty-sixth	June 1, 2014	1-3548 (June 30, 2014 Form 10-Q)	4
		Thirty-seventh	September 1, 2014	1-3548 (Sept. 30, 2014 Form 10-Q)	4
*4(b)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(b)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
		Twelfth	December 2, 2013	1-3548 (2013 Form 10-K)	4(c)3
*4(c)	—	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(d)	—	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).
*4(e)	—	First Amendment dated as of August 26, 2013, to 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 September 30, 2013, Form 10-Q, 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 November 4, 2013 among ALLETE, 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 November 4, 2013, Form 8-K, File No. 1-3548).
*10(c)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(c)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(c)3	—	First Amendment to Amended and Restated Letter of Credit Agreement, dated as of June 1, 2013, between ALLETE and Wells Fargo Bank, National Association, as Issuing Bank, Administrative Agent and sole Participating Bank (filed as Exhibit 10(b) to the June 30, 2013, Form 10-Q, File No. 1-3548).
*10(d)	—	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(e)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(e)2	—	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(e)3	—	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(e)4	—	ALLETE Executive Annual Incentive Plan Form of Awards Effective 2013 (filed as Exhibit 10(f)5 to the 2012 Form 10-K, File No. 1-3548).
+*10(e)5	—	ALLETE Executive Annual Incentive Plan Form of Awards Effective 2014 (filed as Exhibit 10(e)6 to the 2013 Form 10-K, File No. 1-3548).
+10(e)6	—	ALLETE Executive Annual Incentive Plan Form of Awards Effective 2015.
+*10(f)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(f)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).

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60

Exhibit Number
+10(f)3	—	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2015.
+*10(g)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(g)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(g)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(g)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(h)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(h)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(h)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(h)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(i)	—	ALLETE Deferred Compensation Trust Agreement, as amended and restated, effective December 15, 2012 (filed as Exhibit 10(j) to the 2012 Form 10-K, File No. 1-3548).
+*10(j)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(j)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(j)3	—	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(j)4	—	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(j)5	—	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(j)6	—	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(j)7	—	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(j)8	—	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(j)9	—	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(j)10	—	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(j)11	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2013 (filed as Exhibit 10(k)14 to the 2012 Form 10-K, File No. 1-3548).
+*10(j)12	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2013 (filed as Exhibit 10(k)15 to the 2012 Form 10-K, File No. 1-3548).
+*10(j)14	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2014 (filed as Exhibit 10(j)14 to the 2013 Form 10-K, File No. 1-3548).
+*10(j)15	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2014 (filed as Exhibit 10(j)15 to the 213 Form 10-K, File No. 1-3548).
+10(j)16	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2015.
+10(j)17	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2015.
+*10(k)1	—	Minnesota Power (now ALLETE) Non-Employee Director Stock Plan, effective May 9, 1995 (filed as Exhibit 10 to the March 31, 1995, Form 10-Q, File No. 1-3548).
+*10(k)2	—	Amendments through December 2003 to the Minnesota Power (now ALLETE) Non-Employee Director Stock Plan (filed as Exhibit 10(z)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(k)3	—	July 2004 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(e) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(k)4	—	January 2007 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(n)4 to the 2006 Form 10‑K, File No. 1-3548).
+*10(k)5	—	May 2009 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(b) to the June 30, 2009, Form 10-Q, File No. 1-3548).

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61

Exhibit Number
+*10(k)6	—	May 2010 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(a) to the June 30, 2010, Form 10-Q, File No. 1-3548).
+*10(k)7	—	October 2010 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10 to the September 30, 2010, Form 10-Q, File No. 1-3548).
+*10(k)8	—	Amended and Restated ALLETE Non-Employee Director Stock Plan, effective May 15, 2013 (filed as Exhibit 10(a) to the June 30, 2013, Form 10-Q, File No. 1-3548).
+*10(l)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(l)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(l)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(l)4	—	ALLETE Non-Management Director Compensation Summary effective January 1, 2014 (filed as Exhibit 10(l)4 to the 2013 Form 10-K, File No. 1-3548).
+10(l)5	—	ALLETE Non-Employee Director Compensation Summary effective January 1, 2015.
+*10(m)1	—	Minnesota Power (now ALLETE) Non-Employee 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(m)2	—	October 2003 Amendment to the Minnesota Power (now ALLETE) Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(aa)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(m)3	—	January 2005 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(c) to the March 31, 2005, Form 10-Q, File No. 1-3548).
+*10(m)4	—	October 2006 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(d) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(m)5	—	July 2012 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(n)5 to the 2012 Form 10-K, File No. 1-3548).
+*10(n)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(n)2	—	ALLETE Non-Employee Director Compensation Deferral Plan II, as amended and restated, effective July 24, 2012 (filed as Exhibit 10(o)2 to the 2012 Form 10-K, File No. 1-3548).
+*10(o)1	—	ALLETE Non-Employee 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(o)2	—	ALLETE Non-Employee Director Compensation Trust Agreement, as amended and restated, effective December 15, 2012 (filed as Exhibit 10(p)2 to the 2012 Form 10-K, File No. 1-3548).
+*10(p)	—	July 2013 ALLETE and Affiliated Companies Compensation Recovery Policy (filed as Exhibit 10(c) to the June 30, 2013, Form 10-Q, File No. 1-3548).
+*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 17, 2015, announcing earnings for the year ended December 31, 2014. (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, Inc. 2014 Form 10-K

62

Exhibits (Continued)

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 ($24,630,000 remaining principal balance); (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, Inc. 2014 Form 10-K

63

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 17, 2015	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 17, 2015
Alan R. Hodnik	(Principal Executive Officer)
/s/ Steven Q. DeVinck	Senior Vice President and Chief Financial Officer	February 17, 2015
Steven Q. DeVinck	(Principal Financial Officer)
/s/ Steven W. Morris	Controller	February 17, 2015
Steven W. Morris	(Principal Accounting Officer)

ALLETE, Inc. 2014 Form 10-K

64

Signatures (Continued)

Signature	Title	Date
/s/ Kathryn W. Dindo	Director	February 17, 2015
Kathryn W. Dindo
/s/ Sidney W. Emery, Jr.	Director	February 17, 2015
Sidney W. Emery, Jr.
/s/ George G. Goldfarb	Director	February 17, 2015
George G. Goldfarb
/s/ James S. Haines, Jr.	Director	February 17, 2015
James S. Haines, Jr.
/s/ James J. Hoolihan	Director	February 17, 2015
James J. Hoolihan
/s/ Heidi E. Jimmerson	Director	February 17, 2015
Heidi E. Jimmerson
/s/ Madeleine W. Ludlow	Director	February 17, 2015
Madeleine W. Ludlow
/s/ Douglas C. Neve	Director	February 17, 2015
Douglas C. Neve
/s/ Leonard C. Rodman	Director	February 17, 2015
Leonard C. Rodman

ALLETE, Inc. 2014 Form 10-K

65

Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholders of ALLETE, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flowspresent fairly, in all material respects, the financial position of ALLETE, Inc. and its subsidiaries (the Company) at December 31, 2014 and December 31, 2013 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014in 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, 2014 based on criteria established in Internal Control - Integrated Framework (2013) 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 17, 2015

ALLETE, Inc. 2014 Form 10-K

66

CONSOLIDATED FINANCIAL STATEMENTS

ALLETE Consolidated Balance Sheet

As of December 31	2014			2013
Millions
Assets
Current Assets
Cash and Cash Equivalents		$145.8			$97.3
Accounts Receivable (Less Allowance of $1.1 and $1.1)	103.0			96.3
Inventories	80.5			59.3
Prepayments and Other	82.0			35.1
Deferred Income Taxes	7.5			19.0
Total Current Assets	418.8			307.0
Property, Plant and Equipment – Net	3,286.4			2,576.5
Regulatory Assets	357.3			263.8
Investment in ATC	121.1			114.6
Other Investments	114.4			146.3
Other Non-Current Assets	62.8			68.6
Total Assets		$4,360.8			$3,476.8
Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable		$134.1			$99.9
Accrued Taxes	38.7			34.8
Accrued Interest	18.0			15.7
Long-Term Debt Due Within One Year	100.7			27.2
Notes Payable	3.7			—
Other	120.8			52.6
Total Current Liabilities	416.0			230.2
Long-Term Debt	1,272.8			1,083.0
Deferred Income Taxes	510.7			479.1
Regulatory Liabilities	94.2			81.0
Defined Benefit Pension and Other Postretirement Benefit Plans	190.9			133.4
Other Non-Current Liabilities	265.0			127.2
Total Liabilities	2,749.6			2,133.9
Commitments, Guarantees and Contingencies (Note 12)
Equity
ALLETE’s Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 45.9 and 41.4 Shares Outstanding	1,107.6			885.2
Unearned ESOP Shares	(7.2		)	(14.3		)
Accumulated Other Comprehensive Loss	(21.1		)	(17.1		)
Retained Earnings	530.1			489.1
Total ALLETE Equity	1,609.4			1,342.9
Non-Controlling Interest in Subsidiaries	1.8			—
Total Equity	1,611.2			1,342.9
Total Liabilities and Equity		$4,360.8			$3,476.8

The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K

67

ALLETE Consolidated Statement of Income

Year Ended December 31	2014			2013			2012
Millions Except Per Share Amounts
Operating Revenue		$1,136.8			$1,018.4			$961.2
Operating Expenses
Fuel and Purchased Power	356.1			334.8			308.7
Operating and Maintenance	456.2			412.9			397.1
Depreciation	135.7			116.6			100.2
Total Operating Expenses	948.0			864.3			806.0
Operating Income	188.8			154.1			155.2
Other Income (Expense)
Interest Expense	(54.8		)	(50.3		)	(45.5		)
Equity Earnings in ATC	19.6			20.3			19.4
Other	8.6			9.3			6.0
Total Other Expense	(26.6		)	(20.7		)	(20.1		)
Income Before Non-Controlling Interest and Income Taxes	162.2			133.4			135.1
Income Tax Expense	36.7			28.7			38.0
Net Income	125.5			104.7			97.1
Less: Non-Controlling Interest in Subsidiaries	0.7			—			—
Net Income Attributable to ALLETE		$124.8			$104.7			$97.1
Average Shares of Common Stock
Basic	42.9			39.7			37.6
Diluted	43.1			39.8			37.6
Basic Earnings Per Share of Common Stock		$2.91			$2.64			$2.59
Diluted Earnings Per Share of Common Stock		$2.90			$2.63			$2.58
Dividends Per Share of Common Stock		$1.96			$1.90			$1.84

The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K

68

ALLETE Consolidated Statement of Comprehensive Income

Comprehensive Income
Year Ended December 31	2014			2013		2012
Millions
Net Income		$125.5			$104.7		$97.1
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Securities
Net of Income Taxes of $(0.2), $– and $0.8	(0.2		)	—		1.2
Unrealized Gain (Loss) on Derivatives
Net of Income Taxes of $0.1, $– and $(0.1)	0.2			0.1		(0.2		)
Defined Benefit Pension and Other Postretirement Benefit Plans
Net of Income Taxes of $(2.8), $3.3 and $3.9	(4.0		)	4.8		5.9
Total Other Comprehensive Income (Loss)	(4.0		)	4.9		6.9
Total Comprehensive Income	121.5			109.6		104.0
Less: Non-Controlling Interest in Subsidiaries	0.7			—		—
Comprehensive Income Attributable to ALLETE		$120.8			$109.6		$104.0

The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K

69

ALLETE Consolidated Statement of Cash Flows

Year Ended December 31	2014			2013			2012
Millions
Operating Activities
Net Income		$125.5			$104.7			$97.1
Allowance for Funds Used During Construction – Equity	(7.8		)	(4.6		)	(5.1		)
Income from Equity Investments, Net of Dividends	(2.6		)	(4.2		)	(3.7		)
Loss (Gain) on Sale of Assets / Investments	(0.2		)	(2.6		)	0.2
Depreciation Expense	135.7			116.6			100.2
Other Amortization	0.7			1.0			1.0
Amortization of Power Purchase Agreements	(12.7		)	—			—
Deferred Income Tax Expense	32.7			28.6			37.5
Share-Based Compensation Expense	2.3			2.4			2.1
ESOP Compensation Expense	9.1			8.4			7.7
Defined Benefit Pension and Other Postretirement Benefit Expense	12.8			21.0			27.5
Bad Debt Expense	1.8			1.3			1.0
Changes in Operating Assets and Liabilities
Accounts Receivable	(3.5		)	(8.6		)	(10.1		)
Inventories	(17.5		)	10.5			(0.7		)
Prepayments and Other	4.8			(1.4		)	(6.5		)
Accounts Payable	10.9			1.1			(1.5		)
Other Current Liabilities	(3.5		)	1.4			21.8
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans	—			(10.8		)	(8.8		)
Changes in Regulatory and Other Non-Current Assets	(21.3		)	(18.3		)	(20.9		)
Changes in Regulatory and Other Non-Current Liabilities	2.6			(7.1		)	0.8
Cash from Operating Activities	269.8			239.4			239.6
Investing Activities
Proceeds from Sale of Available-for-sale Securities	3.6			16.1			1.5
Payments for Purchase of Available-for-sale Securities	(5.0		)	(4.7		)	(1.8		)
Acquisitions of Subsidiaries – Net of Cash Acquired	(60.3		)	—			—
Investment in ATC	(3.9		)	(3.1		)	(4.7		)
Changes to Other Investments	33.0			(12.3		)	(9.6		)
Additions to Property, Plant and Equipment	(572.8		)	(328.5		)	(405.8		)
Construction Costs for Development Project	(25.7		)	—			—
Cash in Escrow for Acquisition	5.4			(5.4		)	—
Proceeds from Sale of Assets	—			1.3			0.3
Cash for Investing Activities	(625.7		)	(336.6		)	(420.1		)
Financing Activities
Proceeds from Issuance of Common Stock	200.6			98.2			77.0
Proceeds from Issuance of Long-Term Debt	375.0			169.8			180.6
Changes in Restricted Cash	(1.8		)	—			—
Changes in Notes Payable	3.7			—			(1.1		)
Reductions of Long-Term Debt	(134.5		)	(77.7		)	(25.9		)
Acquisition of Non-Controlling Interest	(6.0		)	—			—
Construction Deposits Received for Development Project	54.3			—			—
Debt Issuance Costs	(3.1		)	(1.4		)	(1.3		)
Dividends on Common Stock	(83.8		)	(75.2		)	(69.1		)
Cash from Financing Activities	404.4			113.7			160.2
Change in Cash and Cash Equivalents	48.5			16.5			(20.3		)
Cash and Cash Equivalents at Beginning of Period	97.3			80.8			101.1
Cash and Cash Equivalents at End of Period		$145.8			$97.3			$80.8

The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K

70

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, 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
Comprehensive Income
Net Income	104.7			104.7
Other Comprehensive Income – Net of Tax
Unrealized Gain on Derivatives – Net	0.1						0.1
Defined Benefit Pension and Other Postretirement Plans – Net	4.8						4.8
Total Comprehensive Income Attributable to ALLETE	109.6
Common Stock Issued – Net	100.5										100.5
Dividends Declared	(75.2		)	(75.2		)
ESOP Shares Earned	7.0								7.0
Balance as of December 31, 2013	1,342.9			489.1			(17.1	)	(14.3	)	885.2
Comprehensive Income
Net Income	125.5			125.5
Other Comprehensive Income – Net of Tax
Unrealized Loss on Securities – Net	(0.2		)				(0.2	)
Unrealized Gain on Derivatives – Net	0.2						0.2
Defined Benefit Pension and Other Postretirement Plans – Net	(4.0		)				(4.0	)
Total Comprehensive Income	121.5
Non-Controlling Interest in Subsidiaries	(0.7		)	(0.7		)
Total Comprehensive Income Attributable to ALLETE	120.8
Common Stock Issued – Net	222.4										222.4
Dividends Declared	(83.8		)	(83.8		)
ESOP Shares Earned	7.1								7.1
Balance as of December 31, 2014		$1,609.4			$530.1		$(21.1)		$(7.2)			$1,107.6

The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K

71

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.

On February 10, 2015, ALLETE acquired U.S. Water Services for $168 million and a contingent amount to be paid in 2019 based on U.S. Water Services’ future earnings. U.S. Water Services, an integrated industrial water management company headquartered in St. Michael, Minnesota, has a national footprint serving a growing and diverse mix of over 3,600 industrial customers, with recurring revenues and customer retention that exceeds 90 percent. U.S. Water Services provides integrated water management for industry, combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services helps customers achieve efficient and sustainable use of their energy systems, is a leading provider to the biofuels industry, and has a growing presence in the power generation and midstream oil and gas industries. The acquisition of U.S. Water Services is consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. We expect to finalize the allocation of the purchase price during the first half of 2015. Transaction costs related to the acquisition were expensed as incurred and were not material to the 2014 Consolidated Statement of Income.

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 144,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Otheris comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy and BNI Coal. Investments and Other also includes ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

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, midstream gas and oil infrastructure, among other energy-related projects. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements, and will be subject to applicable state and federal regulatory jurisdictions.

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 2014, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 12. 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, Inc. 2014 Form 10-K

72

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 of real estate 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.

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 8. Investments.)

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	2014		2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$51.3		$47.5		$42.7
Cash Paid During the Period for Income Taxes		$5.1		$0.5	—
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$21.7		$8.3	$20.2
Capitalized Asset Retirement Costs		$22.4	$(0.7)			$17.1
AFUDC – Equity		$7.8		$4.6		$5.1
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan		$19.5	—		—

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	2014		2013
Millions
Trade Accounts Receivable
Billed		$85.5		$78.7
Unbilled	18.6		18.7
Less: Allowance for Doubtful Accounts	1.1		1.1
Total Accounts Receivable		$103.0		$96.3

ALLETE, Inc. 2014 Form 10-K

73

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 10 Large Power Customers. Receivables from these customers totaled $14.7 million at December 31, 2014 ($14.2 million at December 31, 2013). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power’s taconite-producing Large Power Customers are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 10.8 percent of consolidated revenue in 2014 (12.0 percent in 2013; 12.3 percent in 2012).

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 8. 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 8. 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	2014		2013
Millions
Fuel (a)		$29.0		$13.1
Materials and Supplies	51.5		46.2
Total Inventories		$80.5		$59.3

(a) Fuel inventory was lower at December 31, 2013 primarily due to the timing of coal shipments.

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 the effects of certain types of regulation. 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. Upon MPUC approval of cost recovery, 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 book value of retired plant assets. We expect to retire Taconite Harbor Unit 3 and convert Laskin to natural gas in the second quarter of 2015, which were included in our 2013 Integrated Resource Plan approved by the MPUC in a November 2013 order. Accordingly, we do not expect any impairment charge as a result of the retirement of Taconite Harbor Unit 3 or conversion of Laskin.

Impairment of Long-Lived Assets. Land inventory is accounted for as held for use and is recorded at cost. 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, Inc. 2014 Form 10-K

74

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, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net 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, may vary among each land parcel or bulk sale, and may change in the future.If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material.

In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. Our undiscounted future net 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 2014 asset management and disposition plan (Plan) which is reviewed annually for adjustment or modification. 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. Our analysis assumes retail land sales are followed by project bulk sales over a five-year period. 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 future net 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, as set forth in the Plan, is based on management’s current intent for the use and disposition of each property, and is subject to change in future periods if the intentions of the Company were to change.

In the event that projected undiscounted future net 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 of the asset is less than its carrying value, its carrying value is reduced and an impairment charge is recorded in the current period. In 2014, 2013 and 2012, impairment analyses of estimated undiscounted future net cash flows were conducted and indicated that the cash flows were adequate to recover the carrying value of our land inventory. As a result, there was no impairment recorded for the years ended December 31, 2014, 2013, and 2012.

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 those risks including interest rate risk related to certain variable-rate borrowings. (See Note 9. Derivatives.)

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 18. Employee Stock and Incentive Plans.)

Prepayments and Other Current Assets
As of December 31	2014		2013
Millions
Deferred Fuel Adjustment Clause		$16.3		$23.0
Construction Costs for Development Project (a)	48.2		—
Restricted Cash (b)	2.7		—
Other	14.8		12.1
Total Prepayments and Other Current Assets		$82.0		$35.1

(a) Construction Costs for Development Project acquired/incurred due to ALLETE Clean Energy’s acquisition on November 20, 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 7. Acquisitions.)

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

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Non-Current Assets. As of December 31, 2014, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $5.3 million related to ALLETE Clean Energy’s wind energy facilities debt service and other requirements. As of December 31, 2013, the Company had restricted cash of $5.4 million related to cash held in escrow pending the closing of the wind energy facilities acquisition on January 30, 2014. (See Note 7. Acquisitions.)

Other Current Liabilities
As of December 31	2014		2013
Millions
Customer Deposits		$19.7		$26.0
Power Purchase Agreements (a)	19.4		—
Construction Deposits Received for Development Project (b)	54.3		—
Other	27.4		26.6
Total Other Current Liabilities		$120.8		$52.6

(a) Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)

(b) Construction Deposits Received for Development Project are due to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayment and Other Current Assets table and Note 7. Acquisitions.)

Other Non-Current Liabilities
As of December 31	2014		2013
Millions
Asset Retirement Obligation (a)		$109.2		$81.8
Power Purchase Agreements (b)	110.7		—
Other	45.1		45.4
Total Other Non-Current Liabilities		$265.0		$127.2

(a) The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.

(b) Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)

Environmental Liabilities. 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. (See Note 12. 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 yet 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, renewable energy and environmental 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 Coal recognizes revenue when coal is delivered.

We account for revenue from our cost recovery riders (renewable resources, transmission and environmental improvement) in accordance with the accounting standards for alternative revenue programs. These standards allow for recognizing revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows automatic adjustment of future rates, the amount of the revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. Revenue recognized using the alternative revenue program guidance is included in Operating Revenue on our Consolidated Statement of Income and Regulatory Assets on our Consolidated Balance Sheet until it is subsequently collected from customers.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

Amortization of Power Purchase Agreements. As part of the ALLETE Clean Energy wind energy facilities acquisitions in 2014, the Company assumed various PPAs that were at below-market prices and will amortize the liabilities to revenue over the life of the agreements for the difference between contract prices and estimated market prices. In 2014, we recognized $12.7 million of amortization relating to the PPA liabilities in Operating Revenue on the Consolidated Statement of Income.

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 as well as 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 15. Income Tax Expense.)

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.

Purchase Accounting. In accordance with the authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the balance sheet if it exceeds the estimated fair value and as a bargain purchase gain on the income statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense.(See Note 7. Acquisitions.)

New Accounting Standards.

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

ALLETE, Inc. 2014 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

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

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 our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, our business which acquired four wind energy facilities in 2014 and is developing a wind facility to be sold in 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.

	Consolidated			Regulated Operations			Investments and Other
Millions
Year Ended December 31, 2014
Operating Revenue		$1,136.8			$1,003.5			$133.3
Fuel and Purchased Power Expense	356.1			356.1			—
Operating and Maintenance Expense	456.2			345.6			110.6
Depreciation Expense	135.7			118.0			17.7
Operating Income	188.8			183.8			5.0
Interest Expense	(54.8		)	(46.9		)	(7.9		)
Equity Earnings in ATC	19.6			19.6			—
Other Income	8.6			7.8			0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	162.2			164.3			(2.1		)
Income Tax Expense (Benefit)	36.7			39.9			(3.2		)
Net Income	125.5			124.4			1.1
Less: Non-Controlling Interest in Subsidiaries	0.7			—			0.7
Net Income Attributable to ALLETE		$124.8			$124.4			$0.4
As of December 31, 2014
Total Assets		$4,360.8			$3,709.6			$651.2
Capital Additions		$604.3			$583.5			$20.8

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NOTE 2. BUSINESS SEGMENTS (Continued)

	Consolidated			Regulated Operations			Investments and Other
Millions
Year Ended December 31, 2013
Operating Revenue		$1,018.4			$925.5			$92.9
Fuel and Purchased Power Expense	334.8			334.8			—
Operating and Maintenance Expense	412.9			322.4			90.5
Depreciation Expense	116.6			110.2			6.4
Operating Income (Loss)	154.1			158.1			(4.0		)
Interest Expense	(50.3		)	(42.1		)	(8.2		)
Equity Earnings in ATC	20.3			20.3			—
Other Income	9.3			4.7			4.6
Income (Loss) Before Non-Controlling Interest and Income Taxes	133.4			141.0			(7.6		)
Income Tax Expense (Benefit)	28.7			36.1			(7.4		)
Net Income (Loss)	104.7			104.9			(0.2		)
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income (Loss) Attributable to ALLETE		$104.7			$104.9		$(0.2)
As of December 31, 2013
Total Assets		$3,476.8			$3,160.8			$316.0
Capital Additions		$339.5			$326.3			$13.2

	Consolidated			Regulated Operations			Investments and Other
Millions
Year Ended December 31, 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
As of December 31, 2012
Total Assets		$3,253.4			$2,962.4			$291.0
Capital Additions		$432.2			$418.2			$14.0

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NOTE 3. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
As of December 31	2014			2013
Millions
Regulated Utility		$3,903.3			$3,380.0
Construction Work in Progress	355.4			303.9
Accumulated Depreciation	(1,260.2		)	(1,181.7		)
Regulated Utility Plant - Net	2,998.5			2,502.2
Investments and Other Operations (a)	357.8			131.3
Construction Work in Progress	5.9			3.4
Accumulated Depreciation	(75.8		)	(60.4		)
Investments and Other Operations Plant - Net	287.9			74.3
Property, Plant and Equipment - Net		$3,286.4			$2,576.5

(a) Includes primarily ALLETE Clean Energy, BNI Coal and a small amount of non-rate base generation.

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
Generation	5 to 50 years	Distribution	18 to 65 years
Transmission	44 to 67 years	Investments and Other Operations	5 to 44 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, development 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, 2012		$77.9
Accretion	4.6
Revisions in estimated cash flows	(0.7		)
Obligation as of December 31, 2013	81.8
Accretion	5.5
Liabilities recognized (a)	23.0
Liabilities settled	(0.5		)
Revisions in estimated cash flows	(0.6		)
Obligation as of December 31, 2014		$109.2

(a) The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.

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NOTE 4. JOINTLY-OWNED FACILITIES AND PROJECTS

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 one CapX2020 project and have completed two CapX2020 projects with varying ownership percentages.

Our investments in jointly-owned facilities and projects and the related ownership percentages are as follows:

Regulated Utility Plant As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
2014
Boswell Unit 4		$419.1		$209.1		$168.1	80
CapX2020 Projects	55.5		1.7		44.0		9.3 - 14.7
Total		$474.6		$210.8		$212.1
2013
Boswell Unit 4		$416.1		$197.5		$71.5	80
CapX2020 Projects	22.8		1.0		57.7		9.3 - 14.7
Total		$438.9		$198.5		$129.2

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 allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. The electric service agreements with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2023. Under the agreements with the remaining 15 municipal customers and SWL&P, no termination notices may be given prior to June 30, 2016.

2012 Wisconsin Rate Case.SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015. (See Note 1. Operations and Significant Accounting Policies.)

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NOTE 5. REGULATORY MATTERS (Continued)

Renewable Cost Recovery Rider. Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills. (See Note 1. Operations and Significant Accounting Policies.)

On January 29, 2015, the MPUC approved our petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider. The total project investment for Thomson is estimated to be approximately $90 million, net of insurance. (See Note 12. Commitments, Guarantees and Contingencies.)

Integrated Resource Plan.In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Significant elements of the “EnergyForward” plan include major wind investments in North Dakota which were completed in the fourth quarter of 2014, installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in the second quarter of 2015 and retiring Taconite Harbor Unit 3 in the second quarter of 2015. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014. On November 26, 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills. (See Note 1. Operations and Significant Accounting Policies.)

Great Northern Transmission Line (GNTL). Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500 kV transmission line, between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. (See Note 12. Commitments, Guarantees and Contingencies.)

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for the effect of certain types of regulation. 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. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.

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NOTE 5. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities
As of December 31	2014		2013
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$16.3		$23.0
Total Current Regulatory Assets	16.3		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	223.9		164.1
Cost Recovery Riders (c)	59.7		39.6
Income Taxes	46.6		35.3
Asset Retirement Obligations	17.8		16.0
PPACA Income Tax Deferral	5.0		5.0
Other	4.3		3.8
Total Non-Current Regulatory Assets	357.3		263.8
Total Regulatory Assets		$373.6		$286.8
Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$42.9		$19.7
Plant Removal Obligations	22.8		19.7
Income Taxes	13.4		17.0
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	3.5		16.3
Other	11.6		8.3
Total Non-Current Regulatory Liabilities		$94.2		$81.0

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

(b) Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. (See Note 17. Pension and Other Postretirement Benefit Plans.)

(c) The cost recovery rider regulatory assets are due to capital expenditures related to our Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs.

NOTE 6. 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 based on a FERC-approved 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, 2014, our equity investment in ATC was $121.1 million ($114.6 million at December 31, 2013). On January 29, 2015, we invested an additional $0.4 million in ATC. In total, we expect to invest approximately $1.9 million throughout 2015.

ALLETE’s Investment in ATC
Year Ended December 31	2014			2013
Millions
Equity Investment Beginning Balance		$114.6			$107.3
Cash Investments	3.9			3.1
Equity in ATC Earnings	19.6			20.3
Distributed ATC Earnings	(17.0		)	(16.1		)
Equity Investment Ending Balance		$121.1			$114.6

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NOTE 6. INVESTMENT IN ATC (Continued)

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2014		2013
Millions
Current Assets		$66.4		$80.7
Non-Current Assets	3,728.7		3,509.5
Total Assets		$3,795.1		$3,590.2
Current Liabilities		$313.1		$381.4
Long-Term Debt	1,701.0		1,550.0
Other Non-Current Liabilities	163.8		126.2
Members’ Equity	1,617.2		1,532.6
Total Liabilities and Members’ Equity		$3,795.1		$3,590.2

Income Statement Data
Year Ended December 31	2014		2013		2012
Millions
Revenue		$635.0		$626.3		$603.2
Operating Expense	307.4		295.1		281.0
Other Expense	88.9		83.6		84.8
Net Income		$238.7		$247.6		$237.4
ALLETE’s Equity in Net Income		$19.6		$20.3		$19.4

In November 2013, several customer groups located within the MISO service area filed a complaint with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15 percent. ATC's current authorized return on equity is 12.2 percent. In the fourth quarter of 2014, FERC ordered formal hearing proceedings to begin and established a date for potential refunds from November 12, 2013. An initial decision in the complaint is expected by November 30, 2015. In the fourth quarter of 2014, ATC recorded approximately an $18 million refund liability as ATC believes that it is probable that a refund will be required upon ultimate resolution of this matter. The refund liability is subject to adjustment in future periods if assumptions in the estimate change. ATC’s refund liability negatively impacted our Equity Earnings in ATC by approximately $1 million after-tax in 2014. We own approximately 8 percent of ATC and estimate that for every 50 basis point reduction in ATC’s allowed return on equity our equity earnings in ATC would be impacted annually by approximately $0.5 million on an after-tax basis.

NOTE 7. ACQUISITIONS

The acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.

ACE Wind Acquisition

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) from The AES Corporation (AES) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015.

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

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NOTE 7. ACQUISITIONS (Continued)

ALLETE Clean Energy acquired a controlling interest in the limited liability company (LLC) which owns Lake Benton and Storm Lake II, and a controlling interest in the LLC that owns Condon. The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. In connection with finalizing purchase price accounting, the Company recorded minor adjustments to certain assets and liabilities, which are reflected in the table below. These adjustments had no impact on the results of operations. Fair value measurements were valued primarily using the discounted cash flow method.

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

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

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

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

ALLETE Clean Energy incurred $1.4 million after-tax of acquisition-related costs in 2014, which were expensed when incurred and were recorded in Other Expense on the Consolidated Statement of Income. The pro forma impact of this acquisition was not material to the results of the Company for the years ended December 31, 2014 and 2013.

On February 11, 2014, ALLETE Clean Energy purchased the non-controlling interest related to Lake Benton and Storm Lake II for $6.0 million. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income.

Montana-Dakota Utilities

On November 20, 2014, ALLETE Clean Energy acquired a business for $27.0 million which is developing a wind facility near Hettinger, North Dakota. ALLETE Clean Energy will develop and construct a 107 MW wind farm using 43 turbines which will then be sold to Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approvals.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. Fair value measurements were valued primarily using the replacement cost method and determined that the assets acquired amounted to cash of approximately $3.6 million and construction in process of approximately $23.4 million. There were no liabilities assumed and no recognition of goodwill.

Acquisition-related costs were expensed as incurred and were not material for the year ended December 31, 2014. The pro forma impacts of this acquisition also were not material to the results of the Company for the years ended December 31, 2014 and 2013.

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NOTE 7. ACQUISITIONS (Continued)

As of December 31, 2014, $48.2 million of construction costs incurred (including the construction costs acquired) and $54.3 million of construction deposits received from Montana-Dakota Utilities Co. have been classified on the Consolidated Balance Sheet as Other Current Assets and Other Current Liabilities, respectively. Subject to regulatory approval, ALLETE expects revenue to be recognized under the percentage of completion method of accounting as progress toward completion of the project is achieved. Until regulatory approval is obtained, we expect no impact from the project on the Consolidated Statement of Income. Costs to construct the wind facility and deposits received from Montana-Dakota Utilities Co. are reported as Construction Costs for Development Project in investing activities and Construction Deposits Received for Development Project in financing activities on the Consolidated Statement of Cash Flows, respectively.

Storm Lake I Acquisition

On December 17, 2014, ALLETE Clean Energy acquired a wind generation facility in Storm Lake, Iowa (Storm Lake I) from NRG Energy, Inc. for $15.0 million, subject to a working capital adjustment.

Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II which ALLETE Clean Energy acquired in January 2014. The wind generation facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the preliminary estimated fair values of the assets acquired and liabilities assumed at the date of acquisition, as shown in the table below. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relating primarily to property, plant and equipment and the PPA; subsequent adjustments could impact the amount of goodwill recorded or result in a bargain purchase. Fair value measurements were valued primarily using the discounted cash flow method.

Millions
Assets Acquired
Cash and Cash Equivalents		$0.4
Other Current Assets	4.7
Property, Plant and Equipment – Net	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Other Current Liabilities (b)		$8.2
Power Purchase Agreements	23.5
Other Non-Current Liabilities	17.0
Total Liabilities Assumed	$48.7
Net Identifiable Assets Acquired		$15.1

(a) Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.

(b) Other Current Liabilities included $7.5 million related to the current liabilities portion of the Power Purchase Agreements.

Acquisition-related costs were expensed as incurred and were not material for the year ended December 31, 2014. The pro forma impacts of this acquisition also were not material to the results of the Company for the years ended December 31, 2014 and 2013.

ALLETE Clean Energy Purchase Agreement

On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire wind facilities in southern Minnesota for approximately $47.5 million, subject to a working capital adjustment.

The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility acquired in January 2014. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015.

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NOTE 8. INVESTMENTS

Investments. At December 31, 2014, our investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans, and other assets consisting primarily of land in Minnesota.

Other Investments
As of December 31	2014		2013
Millions
ALLETE Properties		$88.2		$89.9
Available-for-sale Securities (a)	18.9		17.7
Cash Equivalents (b)	2.9		34.2
Other	4.4		4.5
Total Other Investments		$114.4		$146.3

(a) As of December 31, 2014, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.6 million, in one year to less than three years was $1.7 million, in three years to less than five years was $2.6 million, and in five or more years was $5.9 million.

(b) During 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.

ALLETE Properties
As of December 31	2014			2013
Millions
Land Inventory Beginning Balance		$85.4			$86.5
Cost of Sales	(2.2		)	(1.5		)
Other	0.6			0.4
Land Inventory Ending Balance	83.8			85.4
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.2			1.4
Other	3.2			3.1
Total Real Estate Assets		$88.2			$89.9

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 indicators of impairment on a quarterly basis and no impairments were recorded for the year ended December 31, 2014 (none for the years ended December 31, 2013 and 2012).

Long-Term Finance Receivables. As of December 31, 2014, long-term finance receivables were $1.2 million net of an allowance ($1.4 million net of an allowance as of December 31, 2013). Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. As of December 31, 2014, the allowance for doubtful accounts amounted to $0.6 million ($0.6 million as of December 31, 2013).

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 held in other postretirement plans to fund employee benefits.

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NOTE 8. INVESTMENTS (Continued)

Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	Loss	Fair Value
2014	$19.6	$0.2	$0.9	$18.9
2013	$18.3	—	$0.6	$17.7
2012	$27.4	$0.5	$1.1	$26.8
		Net	Gross Realized
Year Ended December 31		Proceeds	Gain	Loss
2014		$3.6	$0.2	—
2013		$16.1	$2.2	—
2012		$1.5	—	—

NOTE 9. DERIVATIVES

We have one 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 which represents approximately 5 percent of the Company’s outstanding long-term debt, including long-term debt due within one year, as of December 31, 2014. (See Note 11. Short-Term and Long-Term Debt.) The Swap has an effective date of August 26, 2014, and matures on August 25, 2015. The Swap involves the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreement at 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swap are expected to be highly effective. If it is determined that the Swap ceases to be effective, we will prospectively discontinue hedge accounting. When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessment of hedge effectiveness resulted in no ineffectiveness recorded for the year ended December 31, 2014. As of December 31, 2014, the fair value of the Swap was a $0.3 million liability which was included in Other Current Liabilities on the Consolidated Balance Sheet. The fair value as of December 31, 2013, included an additional variable to fixed interest rate swap that expired on August 26, 2014, with an aggregate fair value at December 31, 2013 of $0.6 million of which $0.3 million was included in Other Non-Current Liabilities and $0.3 million was included in Other Current Liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swap were recorded in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet. Cash flows from the Swap are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in Other Comprehensive Income related to the Swap will be recorded in earnings when the hedged transactions occurs or when it is probable it will not occur. Gains or losses on the interest rate hedging transaction are reflected as a component of Interest Expense on the Consolidated Statement of Income.

NOTE 10. 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.

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NOTE 10. FAIR VALUE (Continued)

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.

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, 2014 and 2013. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the tables below.

	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.1	—		—		$8.1
Available-for-sale – Corporate Debt Securities	—			$10.8	—	10.8
Cash Equivalents	2.9		—		—	2.9
Total Fair Value of Assets		$11.0		$10.8	—		$21.8
Liabilities:
Deferred Compensation (b)	—			$16.2	—		$16.2
Derivatives – Interest Rate Swap (c)	—		0.3		—	0.3
Total Fair Value of Liabilities	—			$16.5	—		$16.5
Total Net Fair Value of Assets (Liabilities)		$11.0	$(5.7)		—		$5.3

(a) Included in Other Investments on the Consolidated Balance Sheet.

(b) Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

(c) Included in Current Liabilities - Other on the Consolidated Balance Sheet.

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NOTE 10. FAIR VALUE (Continued)

	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.9	—		—		$7.9
Available-for-sale – Corporate Debt Securities	—			$9.8	—	9.8
Cash Equivalents	34.2		—		—	34.2
Total Fair Value of Assets		$42.1		$9.8	—		$51.9
Liabilities:
Deferred Compensation (b)	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap (c)	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$17.4	—		$17.4
Total Net Fair Value of Assets (Liabilities)		$42.1	$(7.6)		—		$34.5

(a) Included in Other Investments on the Consolidated Balance Sheet.

(b) Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

(c) Included in Current Liabilities - Other and Other Non-Current Liabilities on the Consolidated Balance Sheet.

There was no activity in Level 3 during the years ended December 31, 2014 or 2013.

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, 2014 and 2013, there were no transfers in or out of Levels 1, 2 or 3.

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

Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2014	$1,373.5	$1,484.5
December 31, 2013	$1,110.2	$1,131.7

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NOTE 11. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2014, total short-term debt outstanding was $104.4 million ($27.2 million as of December 31, 2013) and consisted of long-term debt due within one year and notes payable.

As of December 31, 2014, we had bank lines of credit aggregating $408.4 million ($406.4 million as of December 31, 2013), the majority of which expire in November 2018. We had $47.5 million outstanding in standby letters of credit and $3.7 million outstanding in draws under our lines of credit as of December 31, 2014 ($5.4 million in standby letters of credit and no draws outstanding as of December 31, 2013).

Long-Term Debt. As of December 31, 2014, total long-term debt outstanding was $1,272.8 million ($1,083.0 million as of December 31, 2013). In conjunction with ALLETE Clean Energy’s January 30, 2014 wind energy facilities acquisition, ALLETE Clean Energy assumed $23.3 million of long-term debt, including $2.2 million due within one year. (See Note 7. Acquisitions.) The aggregate amount of long-term debt maturing in 2015 is $100.7 million ($24.9 million in 2016; $54.6 million in 2017; $54.8 million in 2018; $46.9 million in 2019; and $1,091.6 million thereafter). Substantially all of our regulated 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.

During 2014, we issued $375.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:

Issue Date	Maturity Date	Principal Amount	Interest Rate
March 4, 2014	March 15, 2024	$60 Million	3.69%
March 4, 2014	March 15, 2044	$40 Million	4.95%
June 26, 2014	July 15, 2022	$75 Million	3.40%
June 26, 2014	July 15, 2044	$40 Million	5.05%
September 16, 2014	September 15, 2021	$60 Million	3.02%
September 16, 2014	September 15, 2029	$50 Million	3.74%
September 16, 2014	September 15, 2044	$50 Million	4.39%

The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision; however, each series of bonds is redeemable at par, including, in each case, accrued and unpaid interest, six months prior to the maturity date. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company used the proceeds from the sale of the Bonds to refinance debt, fund utility capital expenditures and/or for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

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NOTE 11. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt
As of December 31	2014		2013
Millions
First Mortgage Bonds
6.94% Series Due 2014	—		$18.0
7.70% Series Due 2016	$20.0		20.0
1.83% Series Due 2018	50.0		50.0
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
3.02% Series Due 2021	60.0		—
3.40% Series Due 2022	75.0		—
4.95% Pollution Control Series F Due 2022	—		111.0
6.02% Series Due 2023	75.0		75.0
3.69% Series Due 2024	60.0		—
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		75.0
5.99% Series Due 2027	60.0		60.0
3.30% Series Due 2028	40.0		40.0
3.74% Series Due 2029	50.0		—
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		85.0
4.21% Series Due 2043	60.0		60.0
4.95% Series Due 2044	40.0		—
5.05% Series Due 2044	40.0		—
4.39% Series Due 2044	50.0		—
Unsecured Term Loan Variable Rate Due 2015	75.0		75.0
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2015 – 2020	24.6		24.6
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8		27.8
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0		15.0
Other Long-Term Debt, 0.08% – 7.50% Due 2015 – 2037	59.1		41.8
Total Long-Term Debt	1,373.5		1,110.2
Less: Due Within One Year	100.7		27.2
Net Long-Term Debt		$1,272.8		$1,083.0

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 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, 2014, our ratio was approximately 0.47 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from 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, 2014, ALLETE was in compliance with its financial covenants.

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

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

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the Agreement, 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, 2014, Square Butte had total debt outstanding of $402.9 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2015 through 2019, 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 2014 was $70.1 million ($71.1 million in 2013; $67.1 million in 2012). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $10.5 million in 2014 ($10.5 million in 2013; $11.1 million in 2012). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced June 1, 2014. Under the power sales agreement, Minnesota Power is selling 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.

Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity from June 2016 through May 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. 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 that expire in 2031 and 2032, respectively. Each agreement provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges, and we only pay for energy as it is delivered to us.

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2020. Under this agreement Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index as well as market prices. Both PPAs are subject to MPUC approval.

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.

Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills.

Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota, and surrounding areas. The flooding impacted Minnesota Power’s St. Louis River hydro system, particularly Thomson, which had damage to the forebay canal and flooding at the facility. The forebay rebuild is complete and Minnesota Power commenced filling the forebay canal on October 9, 2014. Thomson returned to partial generation in the fourth quarter of 2014 and work is ongoing towards returning to full generation early in 2015. Total project costs are estimated to be approximately $90 million, net of insurance. On January 29, 2015, the MPUC approved our petition seeking cost recovery of investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through December 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through December 2015. Minnesota Power is currently in discussions regarding the extension of our coal supply and transportation contracts beyond 2015. Our minimum annual payment obligation under these supply and transportation agreements is $38.3 million for 2015. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Coal, Rail and Shipping Contracts (Continued)

Rail congestion has negatively impacted customers throughout the Upper Midwest, affecting commerce by rail including, but not limited to, agriculture, commodity, intermodal and energy industries. We have experienced delays in coal deliveries resulting in lower coal inventory levels in 2013 and throughout much of 2014 at our generating stations in Northeastern Minnesota. Minnesota Power filed a notice of fuel supply emergency with the U.S. Department of Energy on September 22, 2014 in response to inadequate rail deliveries. Rail deliveries increased late in 2014, building inventories to normal levels by year end 2014. On December 30, 2014, the Surface Transportation Board ordered BNSF Railway to submit a detailed description of the contingency plans it would use to mitigate an acute coal inventory shortage at one or more generating stations in a region. Minnesota Power’s exposure to price risk for purchased power 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.

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 2022. The aggregate amount of minimum lease payments for all operating leases is $13.4 million in 2015, $11.4 million in 2016, $10.6 million in 2017, $9.5 million in 2018, $8.3 million in 2019 and $27.3 million thereafter. Total lease expense was $14.8 million in 2014 ($13.8 million in 2013; $11.5 million in 2012).

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

Transmission Investments. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015.

CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives and municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020.

Minnesota Power is currently participating in the construction of one CapX2020 transmission line project. Minnesota Power also participated in two CapX2020 projects which were previously completed and placed into service in 2011 and 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project, of which the final phase is currently under construction and expected to be in service in the second quarter of 2015.

Based on projected costs of the three transmission line projects and the allocation agreements among participating utilities, in total Minnesota Power plans to invest approximately $105 million in the CapX2020 initiative through 2015, of which $99 million was spent through December 31, 2014. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220-mile 500 kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line.

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

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserted that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that Boswell Unit 4’s Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated.

Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota (Court) on September 29, 2014. The Consent Decree covers Minnesota Power’s Boswell, Laskin, Taconite Harbor, and Rapids Energy Centers. The Consent Decree provides for more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at some units, and the addition of 200 MW of wind energy. Minnesota Power is required to spend $4.2 million on environmental mitigation projects over the next five years. Under the terms of the Consent Decree, Minnesota Power also paid a $1.4 million civil penalty which was recognized as an expense in 2013. In 2014, the Company recorded an expense associated with the environmental mitigation projects.

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Since 2005, the Company has, and will, invest more than $600 million to reduce sulfur dioxide, nitrogen oxide, mercury and particulate matters emissions at its thermal generation facilities, and between 2010 and 2014 placed in service nearly 500 MW of renewable wind energy, which fulfills certain obligations under the Consent Decree. In addition, Minnesota Power’s EnergyForward plan addresses many of the requirements included in the Consent Decree. Under the EnergyForward plan, Minnesota Power intends to: 1) retire Taconite Harbor Unit 3, 2) convert Laskin from coal to natural gas, and 3) install emission controls at Boswell Unit 4.

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

Cross-State Air Pollution Rule (CSAPR). On April 29, 2014, the U.S. Supreme Court issued an opinion reversing an August 2012 U.S. Court of Appeals for the D.C. Circuit decision that had vacated the CSAPR. The EPA filed a motion with the U.S. Court of Appeals for the D.C. Circuit on June 26, 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion, allowing the first compliance period, Phase I, to begin on January 1, 2015, with Phase II beginning in 2017.

CSAPR requires five states in the eastern half of the United States, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone or fine particulate pollution in other states. These states are required to make summertime NO_x reductions under the CSAPR ozone season control program. CSAPR does not require installation of controls; rather it requires that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances will be allocated to facilities from each state’s annual budget and can be bought and sold.

In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017-2020) have not been distributed. Based on our initial accounting of the NO_x and SO₂ Phase I allowances already issued, and our review of the CSAPR Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will be in compliance in both Phase I and Phase II.

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

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

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

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $250 million through 2016, of which $145 million was spent through December 31, 2014. Boswell Unit 3 is also subject to the MATS rule; however, the emission reduction investments completed in 2009 at our Boswell Unit 3 generating unit substantially meet the requirements of the MATS rule. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in a November 2013 order, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015 to position the Company for MATS compliance. On January 9, 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS to June 1, 2015, in order to align the Unit 3 retirement with MISO’s resource planning year.

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

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT) became effective in December 2012. Major existing sources have until January 31, 2016, to achieve compliance with the final rule. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. We expect compliance to consist largely of adjustments to our operating practices; therefore costs for complying with the final rule are not expected to be material at this time.

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

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. On November 25, 2014, the EPA proposed a 65 to 70 parts per billion (ppb) NAAQS for ground level ozone. The EPA is proposing to update both the primary ozone standard and the secondary standard. Both standards would be 8-hour standards set within a range of 65 to 70 ppb. The EPA is also seeking comment on levels for the primary standard as low as 60 ppb. The EPA has announced it will accept comments on all aspects of the proposal, including retaining the existing standard. A final rule is expected to be issued in the fourth quarter of 2015. The costs for complying with the final ozone NAAQS cannot be estimated at this time.

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in September 2006. Since then, the EPA has established more stringent 24-hour and annual average fine particulate matter (PM_2.5) standards; the 24-hour coarse particulate matter standard has remained unchanged. In December 2012, the EPA issued a final rule implementing a more stringent annual PM_2.5 standard, while retaining the current 24-hour PM_2.5 standard. To implement the new annual PM_2.5 standard, the EPA is also revising aspects of relevant monitoring, designation and permitting requirements. New projects and permits must comply with the new standard, which is generally demonstrated by modeling at the facility level.

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Environmental Matters (Continued)

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by December 2013, based on already available monitoring data. The EPA issued designations of 2012 fine particulate attainment status on December 18, 2014. Minnesota retained attainment status; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly, the costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

SO₂ and NO₂ NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO₂ and NO₂. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO₂ NAAQS also may require the EPA to evaluate modeling data to determine attainment. In April 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by June 2013. However, the State of Minnesota has delayed completing the documents pending EPA guidance to states for preparing the SIP submittal. The MPCA has indicated it will communicate with affected sources once it has more information on how the state will meet the EPA’s SIP requirements. Guidance was expected in 2013 but has been delayed. 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.

In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Band) announced that it had petitioned the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Band does not currently possess authority to directly regulate air quality. Federal Class I air shed status, if granted, would allow the Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have applied for and received Class I status. A public hearing was held by the Band on October 2, 2014, and the public comment period on the petition expired on November 10, 2014. The Band is now preparing responses to the comments after which the Band will make a formal submittal request to the EPA. There is no deadline for the approval, denial, or modification of the request by the EPA. The Company has requested additional clarification from the Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation. We are unable to determine the impact of potential Class I status on the Company’s operations at this time. 

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

• Expanding our renewable energy supply;

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

• Improving efficiency of our energy generating facilities;

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

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

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

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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

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

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

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

The EPA proposed that BSER is comprised of four building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, 3) building more or preserving existing zero- and low-emitting power sources, including renewable and nuclear energy, and 4) more efficient electricity use by consumers.

The EPA then established state goals, expressed as a carbon intensity target in CO₂ tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company. We submitted comments on the CPP to the EPA.

Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its “EnergyForward” strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 5. Regulatory Matters.)

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.

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NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Minnesota’s Next Generation Energy Act of 2007. On April 14, 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO₂-producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO₂ emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit on May 16, 2014.

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule was published in the Federal Register on August 15, 2014, with an effective date of October 14, 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDEC permits have been re-issued containing 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance; however, our preliminary assessment suggests costs of compliance could be up to approximately $15 million. We would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In April 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register in June 2013, and public comments were due in September 2013. The EPA is expected to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. We would seek recovery of any additional costs through cost recovery riders or in a general rate case

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 (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).

ALLETE, Inc. 2014 Form 10-K

101

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

The EPA issued the final CCR rule on December 19, 2014 under Subtitle D (non-hazardous) of RCRA. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. The final rule also includes provisions that could incentivize early closure of existing impoundments within a three-year window. Costs of compliance, primarily for Boswell and Laskin, could be up to approximately $130 million. The Company continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. We would seek recovery of any additional costs through a general rate case.

Other Matters

ALLETE Clean Energy. In January 2014, ALLETE Clean Energy acquired three wind energy facilities–Lake Benton, Storm Lake II and Condon–from AES. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. On December 17, 2014, ALLETE Clean Energy acquired a wind facility, Storm Lake I, which has a PPA in place for its entire output which expires in 2018. On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire a wind facility in southern Minnesota and has PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015. (See Note 7. Acquisitions.)

BNI Coal. As of December 31, 2014, BNI Coal had surety bonds outstanding of $49.5 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit for an additional $0.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $49.3 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of December 31, 2014, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in November 2006 for Town Center and November 2007 for Palm Coast Park. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At December 31, 2014, we owned 72 percent of the assessable land in the Town Center District (73 percent at December 31, 2013) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2013). At these ownership levels, our annual assessments are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act, which it supplemented in March 2014. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of December 31, 2014, because a potential loss is not currently probable or reasonably estimable.

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

ALLETE, Inc. 2014 Form 10-K

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NOTE 13. COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock	Shares	Equity
	Thousands	Millions
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
Employee Stock Purchase Program	16	0.7
Invest Direct	395	18.5
Options and Stock Awards	301	17.9
Equity Issuance Program	1,312	63.4
Balance as of December 31, 2013	41,401	885.2
Employee Stock Purchase Program	18	0.8
Invest Direct	378	18.9
Options and Stock Awards	78	8.0
Equity Issuance Program	1,851	90.0
Forward Sale Agreement and Issuance	1,807	85.2
Contributions to Pension	396	19.5
Balance as of December 31, 2014	45,929		$1,107.6

Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, Inc., in February 2008, as amended most recently in May 2014, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 1.3 million shares remain available for issuance. For the year ended December 31, 2014, 1.9 million shares of common stock were issued under this agreement resulting in net proceeds of $90.0 million (1.3 million shares for net proceeds of $63.4 million for the year ended December 31, 2013). The shares sold in 2012 through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

Earnings Per Share. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units, performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below). In 2014 and 2013, in accordance with accounting standards for earnings per share, no 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. In 2012, there were 0.2 million shares excluded because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive.

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

Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock (borrowed shares) from third parties and sold them to the underwriters. ALLETE had the right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elected physical settlement of the Agreement, it would deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price was initially $48.01 per share, subject to adjustment as provided in the Agreement. On September 5, 2014, ALLETE physically settled a portion of its obligations under the Agreement by having delivered approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million. On February 4, 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares for cash proceeds of $65.4 million.

ALLETE, Inc. 2014 Form 10-K

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NOTE 13. COMMON STOCK AND EARNINGS PER SHARE (Continued)

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

The equity forward transaction was reflected in ALLETE’s diluted earnings per share using the treasury stock method, which resulted in no material dilutive impact to ALLETE’s diluted earnings per share for the year ended December 31, 2014. Prior to any settlement date, any dilutive effect of the Agreement on our earnings per share would only occur during periods when the average market price per share of our common stock is above the per share adjusted forward sales price described above.

The equity forward transaction is accounted for as an equity instrument in accordance with the accounting guidance for distinguishing liabilities from equity and the guidance for derivatives. Under the accounting guidance, the transaction qualifies for an exception from derivative accounting because the forward sale transaction is indexed to ALLETE’s stock.

Contributions to Pension. In 2014, we contributed approximately 0.4 million shares of ALLETE common stock to our pension plan, which had an aggregate value of $19.5 million when contributed. There were no contributions of ALLETE common stock to our pension plan in 2013 or 2012. 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, as amended.

Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2014
Net Income Attributable to ALLETE		$124.8			$124.8
Average Common Shares	42.9		0.2	43.1
Earnings Per Share		$2.91			$2.90
2013
Net Income Attributable to ALLETE		$104.7			$104.7
Average Common Shares	39.7		0.1	39.8
Earnings Per Share		$2.64			$2.63
2012
Net Income Attributable to ALLETE		$97.1			$97.1
Average Common Shares	37.6		—	37.6
Earnings Per Share		$2.59			$2.58

NOTE 14. OTHER INCOME (EXPENSE)

Year Ended December 31	2014		2013		2012
Millions
AFUDC – Equity		$7.8		$4.6		$5.1
Gain on Sale of Available-for-sale Securities	0.2		2.2		—
Investments and Other Income	0.6		2.5		0.9
Total Other Income		$8.6		$9.3		$6.0

ALLETE, Inc. 2014 Form 10-K

104

NOTE 15. INCOME TAX EXPENSE

Income Tax Expense
Year Ended December 31	2014			2013			2012
Millions
Current Tax Expense
Federal (a)	$1.1			—			—
State (a)	2.9			$0.1			$0.5
Total Current Tax Expense	4.0			0.1			0.5
Deferred Tax Expense
Federal	25.3			22.9			37.0
State	8.2			6.5			1.4
Investment Tax Credit Amortization	(0.8		)	(0.8		)	(0.9		)
Total Deferred Tax Expense	32.7			28.6			37.5
Total Income Tax Expense		$36.7			$28.7			$38.0

(a) For the years ended December 31, 2014, 2013, and 2012, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012. The federal and state NOLs will be carried forward to offset future taxable income. The year ended 2014 includes the resolution of an IRS examination for the tax years 2005-2009 and the impacts of initiatives implemented on the 2013 federal and state tax returns to utilize tax carryforwards that may have expired.

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2014			2013			2012
Millions
Income Before Non-Controlling Interest and Income Taxes		$162.2			$133.4			$135.1
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$56.8			$46.7			$47.3
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	7.2			4.3			1.2
Regulatory Differences for Utility Plant	(3.5		)	(2.2		)	(2.2		)
Production Tax Credits	(23.7		)	(19.2		)	(7.6		)
Other	(0.1		)	(0.9		)	(0.7		)
Total Income Tax Expense		$36.7			$28.7			$38.0

The effective tax rate on income was 22.6 percent for 2014 (21.5 percent for 2013; 28.1 percent for 2012). The 2014, 2013, and 2012 effective rates were primarily impacted by production tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above).

ALLETE, Inc. 2014 Form 10-K

105

NOTE 15. INCOME TAX EXPENSE (Continued)

Deferred Tax Assets and Liabilities
As of December 31	2014			2013
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$102.2			$66.3
Property Related	102.7			82.2
NOL Carryforwards	156.5			112.8
Tax Credit Carryforwards	95.7			55.1
Power Purchase Agreements	51.8			—
Other	17.0			16.9
Gross Deferred Tax Assets	525.9			333.3
Deferred Tax Asset Valuation Allowance	(22.1		)	(8.0		)
Total Deferred Tax Assets		$503.8			$325.3
Deferred Tax Liabilities
Property Related		$848.8			$656.2
Regulatory Asset for Benefit Obligations	89.9			58.7
Unamortized Investment Tax Credits	10.3			11.1
Partnership Basis Differences	41.9			36.7
Other	16.1			22.7
Total Deferred Tax Liabilities		$1,007.0			$785.4
Net Deferred Income Taxes		$503.2			$460.1
Recorded as:
Net Current Deferred Tax Assets		$7.5		$19.0
Net Long-Term Deferred Tax Liabilities	510.7			479.1
Net Deferred Income Taxes		$503.2			$460.1

NOL and Tax Credit Carryforwards
As of December 31	2014	2013
Millions
Federal NOL Carryforwards (a)	$413.7		$279.8
Federal Tax Credit Carryforwards	$59.3	$35.5
State NOL Carryforwards (a)	$184.7	$156.3
State Tax Credit Carryforwards (b)	$14.7	$11.9

(a) Pretax amounts.

(b) Net of a $21.7 million valuation allowance as of December 31, 2014 ($7.7 million as of December 31, 2013).

The federal NOL and tax credit carryforward periods expire between 2030 and 2035. We expect to fully utilize the federal NOL and federal tax credit carryforwards; therefore no federal valuation allowance has been recognized as of December 31, 2014. The state NOL and tax credit carryforward periods expire between 2025 and 2035. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.

ALLETE, Inc. 2014 Form 10-K

106

NOTE 15. INCOME TAX EXPENSE (Continued)

Gross Unrecognized Income Tax Benefits	2014			2013			2012
Millions
Balance at January 1		$1.2			$2.7			$11.4
Additions for Tax Positions Related to the Current Year	—			0.1			—
Additions for Tax Positions Related to Prior Years	1.0			1.3			—
Reductions for Tax Positions Related to Prior Years	—			—			(8.7		)
Reductions for Settlements	—			(2.9		)	—
Lapse of Statute	(0.2		)	—			—
Balance as of December 31		$2.0			$1.2			$2.7

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 income 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, 2014, include $0.4 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $2.9 million in 2013 was due to the removal of our uncertain tax positions for positions effectively settled with the IRS for tax years 2005 through 2009. 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, 2014, we had no accrued interest ($0.5 million for 2013 and $0.5 million for 2012) related to unrecognized tax benefits included on our Consolidated Balance Sheet due to our NOL carryforwards. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on our Consolidated Statement of Income. In 2014, we recognized a decrease in interest expense of $0.5 million related to unrecognized tax benefits on our Consolidated Statement of Income (zero for 2013 and decrease of $0.6 million for 2012). There were no penalties recognized in 2014, 2013 or 2012. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on our Consolidated Balance Sheet.

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 has settled with the IRS for the audit of tax years 2005 through 2009. ALLETE is no longer subject to federal examination for years before 2011, or state examination for years before 2010.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $0.1 million due to the expiration of the statute of limitations. This amount is primarily due to temporary tax positions.

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

ALLETE, Inc. 2014 Form 10-K

107

NOTE 16. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive loss, net of tax, for the year ended December 31, 2014, were as follows:

	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items		Gains and Losses on Cash Flow Hedge	Total
Millions
For the Year Ended December 31, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)		$(0.3)	$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.3	)	(5.2	)	0.2	(5.3	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	0.1		1.2		—	1.3
Net Other Comprehensive Income (Loss)	(0.2	)	(4.0	)	0.2	(4.0	)
Ending Accumulated Other Comprehensive Loss	$(0.3)		$(20.7)		$(0.1)	$(21.1)

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2014, were as follows:

	Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	December 31,
	2014
Millions
Unrealized Gains on Available-for-sale Securities (a)	$(0.2)
Income Taxes (b)	0.1
Total, Net of Income Taxes	$(0.1)
Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.3
Actuarial Gains and Losses (c)	(2.3	)
Total	(2.0	)
Income Taxes (b)	0.8
Total, Net of Income Taxes	$(1.2)
Total Reclassifications	$(1.3)

(a) Included in Other Income (Expense) – Other on our Consolidated Statement of Income.

(b) Included in Income Tax Expense on our Consolidated Statement of Income.

(c) Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 17. Pension and Other Postretirement Benefit Plans.)

ALLETE, Inc. 2014 Form 10-K

108

NOTE 16. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)

Changes in accumulated other comprehensive loss, net of tax, for the year ended December 31, 2013, were as follows:

	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
For the Year Ended December 31, 2013
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(21.5)	$(0.4)	$(22.0)
Other Comprehensive Income Before Reclassifications	1.3		3.2	0.1	4.6
Amounts Reclassified From Accumulated Other Comprehensive Loss	(1.3	)	1.6	—	0.3
Net Other Comprehensive Income	—		4.8	0.1	4.9
Ending Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)	$(0.3)	$(17.1)

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2013, were as follows:

	Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	December 31,
	2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	$2.2
Income Taxes (b)	(0.9	)
Total, Net of Income Taxes	$1.3
Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.8
Actuarial Gains and Losses (c)	(3.5	)
Total	(2.7	)
Income Taxes (b)	1.1
Total, Net of Income Taxes	$(1.6)
Total Reclassifications	$(0.3)

(a) Included in Other Income (Expense) – Other on our Consolidated Statement of Income.

(b) Included in Income Tax Expense on our Consolidated Statement of Income.

(c) Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 17. Pension and Other Postretirement Benefit Plans.)

NOTE 17. 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 2014, we contributed $19.5 million to the plans, all of which was contributed in shares of ALLETE common stock (no contributions in 2013; $7.3 million in 2012). We also have a defined contribution RSOP covering substantially all employees. The 2014 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $9.1 million ($8.4 million for the 2013 plan year; $7.7 million for the 2012 plan year). (See Note 13. Common Stock and Earnings Per Share and Note 18. Employee Stock and Incentive Plans.)

ALLETE, Inc. 2014 Form 10-K

109

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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 require employees to be at least age 55 with 10 years of participation in the plan. In 2014, our postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015. The postretirement health and life 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 irrevocable grantor trusts. In 2014, no contributions were made to the VEBAs ($10.8 million in 2013; $1.5 million in 2012) and no contributions were made to the grantor trusts ($2.0 million in 2013; none in 2012).

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 or the defined benefit postretirement health and life plan in 2015.

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 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 expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) 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 (regulatory liability) on our Consolidated Balance Sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other non-rate base operations are recognized in accumulated other comprehensive income.

ALLETE, Inc. 2014 Form 10-K

110

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Obligation and Funded Status
At December 31	2014			2013
Millions
Accumulated Benefit Obligation		$661.4			$577.6
Change in Benefit Obligation
Obligation, Beginning of Year		$622.8			$652.1
Service Cost	8.3			9.9
Interest Cost	29.8			26.0
Actuarial (Gain) Loss	72.6			(49.2		)
Benefits Paid	(36.9		)	(33.5		)
Participant Contributions	17.9			17.5
Obligation, End of Year		$714.5			$622.8
Change in Plan Assets
Fair Value, Beginning of Year		$501.6			$460.1
Actual Return on Plan Assets	41.0			56.5
Employer Contribution (a)	38.5			18.5
Benefits Paid	(36.9		)	(33.5		)
Fair Value, End of Year		$544.2			$501.6
Funded Status, End of Year	$(170.3)			$(121.2)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.2)			$(1.1)
Non-Current Liabilities	$(169.1)			$(120.1)

(a) Includes participant contributions noted above.

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

Unrecognized Pension Costs
As of December 31	2014		2013
Millions
Net Loss		$250.4		$194.9
Prior Service Cost	0.2		0.4
Total Unrecognized Pension Costs		$250.6		$195.3

Components of Net Periodic Pension Expense
Year Ended December 31	2014			2013			2012
Millions
Service Cost		$8.3			$9.9			$9.1
Interest Cost	29.8			26.0			26.4
Expected Return on Plan Assets	(38.2		)	(35.2		)	(35.4		)
Amortization of Loss	14.2			21.5			17.5
Amortization of Prior Service Cost	0.3			0.3			0.3
Net Pension Expense		$14.4			$22.5			$17.9

ALLETE, Inc. 2014 Form 10-K

111

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2014		2013
Millions
Net (Gain) Loss	$69.8		$(70.4)
Amortization of Prior Service Cost	(0.3	)	(0.3	)
Amortization of Loss	(14.2	)	(21.5	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$55.3		$(92.2)

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2014		2013
Millions
Projected Benefit Obligation		$714.5		$622.8
Accumulated Benefit Obligation		$661.4		$577.6
Fair Value of Plan Assets		$544.2		$501.6

Postretirement Health and Life Obligation and Funded Status
At December 31	2014			2013
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$151.9			$168.8
Service Cost	3.4			3.9
Interest Cost	7.3			6.8
Actuarial (Gain) Loss	18.1			(18.8		)
Benefits Paid	(8.9		)	(9.9		)
Participant Contributions	2.6			2.7
Plan Amendments	(2.9		)	—
Plan Curtailments	(0.6		)	—
Settlements (a)	—			(1.6		)
Obligation, End of Year		$170.9			$151.9
Change in Plan Assets
Fair Value, Beginning of Year		$157.0			$131.0
Actual Return on Plan Assets	11.6			21.4
Employer Contribution	1.1			11.7
Participant Contributions	2.6			2.7
Benefits Paid	(9.1		)	(9.8		)
Fair Value, End of Year		$163.2			$157.0
Funded Status, End of Year	$(7.7)			$5.1
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$6.6			$19.4
Current Liabilities	$(0.9)			$(0.9)
Non-Current Liabilities	$(13.4)			$(13.4)

(a) Result of the termination of a legacy benefit plan.

ALLETE, Inc. 2014 Form 10-K

112

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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 $17.9 million in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at December 31, 2014 ($17.8 million at December 31, 2013).

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

Unrecognized Postretirement Health and Life Costs
As of December 31	2014		2013
Millions
Net (Gain) Loss	$6.9		$(9.0)
Prior Service Credit	(10.6	)	(10.1	)
Total Unrecognized Postretirement Health and Life Credit	$(3.7)		$(19.1)

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2014			2013			2012
Millions
Service Cost		$3.4			$3.9			$4.2
Interest Cost	7.3			6.8			9.4
Expected Return on Plan Assets	(10.3		)	(9.7		)	(9.9		)
Amortization of Loss	0.5			1.6			7.5
Amortization of Prior Service Credit	(2.5		)	(2.5		)	(1.7		)
Amortization of Transition Obligation	—			—			0.1
Effect of Plan Settlement (a)	—			(1.6		)	—
Net Postretirement Health and Life Expense (Credit)	$(1.6)			$(1.5)				$9.6

(a) Result of the termination of a legacy benefit plan.

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2014		2013
Millions
Net (Gain) Loss	$16.4		$(30.2)
Prior Service Credit Arising During the Period	(3.0	)	—
Amortization of Prior Service Credit	2.5		2.5
Amortization of Loss	(0.5	)	(1.6	)
Amount Recognized due to Plan Settlement (a)	—		(0.2	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$15.4		$(29.5)

(a) Result of the termination of a legacy benefit plan.

ALLETE, Inc. 2014 Form 10-K

113

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2015		$36.5		$8.0
2016		$37.1		$8.5
2017		$38.2		$8.8
2018		$39.0		$9.0
2019		$39.9		$9.4
Years 2020 – 2024		$207.8		$49.4

The pension and postretirement health and life costs recorded in regulatory long-term assets or liabilities 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, 2015, are as follows:

	Pension		Postretirement Health and Life
Millions
Net Loss		$17.9		$0.4
Prior Service Cost (Credit)	0.2		(3.0		)
Total Pension and Postretirement Health and Life Cost (Credit)		$18.1	$(2.6)

Assumptions Used to Determine Benefit Obligation
As of December 31	2014	2013
Discount Rate
Pension	4.30%	4.93%
Postretirement Health and Life	4.33%	4.96%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	6.75%	7.25%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2022	2020

Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2014	2013	2012
Discount Rate	4.93 - 4.96%	4.10 - 4.13%	4.54 - 4.56%
Expected Long-Term Return on Plan Assets
Pension	8.00%	8.25%	8.25%
Postretirement Health and Life	6.40 - 8.00%	6.60 - 8.25%	6.60 - 8.25%
Rate of Compensation Increase	3.70 - 4.30%	4.30 - 4.60%	4.30 - 4.60%

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.

ALLETE, Inc. 2014 Form 10-K

114

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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. The decrease in the discount rates used as of December 31, 2014 increased the pension and postretirement health and life benefit obligations by approximately $53 million and $14 million, respectively.

The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations. In 2014, revised mortality tables were released, and the Company adopted updated mortality tables as of December 31, 2014. The adoption of updated mortality tables increased the pension and postretirement health and life benefit obligations as of December 31, 2014 by approximately $25 million and $8 million, respectively.

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.5	$(1.2)
Effect on Postretirement Health and Life Obligation		$21.6	$(17.7)

Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2014		2013		2014		2013
Equity Securities	48	%	52	%	58	%	63	%
Debt Securities	39	%	34	%	34	%	29	%
Private Equity	8	%	9	%	8	%	8	%
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 as of December 31, 2014 (no shares as of December 31, 2013).

As of December 31, 2013, the defined benefit pension plan adopted a dynamic asset allocation strategy (glide path) that increases the invested allocation to fixed income assets as the funding level of the plan increases to better match the sensitivity of the plan’s assets and liabilities to changes in interest rates. This is expected to reduce the volatility of reported pension plan expenses. The postretirement health and life plans’ assets continue to be diversified to achieve strong returns within managed risk. 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. Below are the current targeted allocations as of December 31, 2014.

Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	56	%	60	%
Debt Securities	35	%	37	%
Real Estate	9	%	3	%
	100	%	100	%

(a) Includes VEBAs and irrevocable grantor trusts.

ALLETE, Inc. 2014 Form 10-K

115

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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.

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, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$56.4	—			$88.5
U.S. Mid-cap Growth (a)	13.6		23.9		—		37.5
U.S. Small-cap (a)	13.9		24.4		—		38.3
International	46.1		45.9		—		92.0
Debt Securities:
Mutual Funds	0.1		—		—		0.1
Fixed Income	2.7		201.0		—		203.7
Cash Equivalents	11.9		—		—		11.9
Other Types of Investments:
Private Equity Funds	—		—			$43.3	43.3
Real Estate	—		—		28.9		28.9
Total Fair Value of Assets		$120.4		$351.6		$72.2		$544.2

(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, 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.

ALLETE, Inc. 2014 Form 10-K

116

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2013		$46.8			$26.5
Actual Return on Plan Assets	1.2			2.8
Purchases, sales, and settlements, net	(4.7		)	(0.4		)
Balance as of December 31, 2014		$43.3			$28.9

	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$20.9		$59.3	—			$80.2
U.S. Mid-cap Growth (a)	9.4		26.7		—		36.1
U.S. Small-cap (a)	9.9		28.2		—		38.1
International	61.2		43.5		—		104.7
Debt Securities:
Mutual Funds	130.1		—		—		130.1
Fixed Income	—		36.4		—		36.4
Cash Equivalents	2.7		—		—		2.7
Other Types of Investments:
Private Equity Funds	—		—			$46.8	46.8
Real Estate	—		—		26.5		26.5
Total Fair Value of Assets		$234.2		$194.1		$73.3		$501.6

(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, 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, 2012		$58.9			$24.9
Actual Return on Plan Assets	2.3			2.1
Purchases, sales, and settlements, net	(14.4		)	(0.5		)
Balance as of December 31, 2013		$46.8			$26.5

ALLETE, Inc. 2014 Form 10-K

117

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Postretirement Health and Life Fair Value

	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$29.3	—		—			$29.3
U.S. Mid-cap Growth (a)	20.0		—		—		20.0
U.S. Small-cap (a)	12.6		—		—		12.6
International	30.6		—		—		30.6
Debt Securities:
Mutual Funds	44.5		—		—		44.5
Fixed Income	—			$9.9	—		9.9
Cash Equivalents	3.4		—		—		3.4
Other Types of Investments:
Private Equity Funds	—		—			$12.9	12.9
Total Fair Value of Assets		$140.4		$9.9		$12.9		$163.2

(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, 2013		$13.1
Actual Return on Plan Assets	1.4
Purchases, sales, and settlements, net	(1.6		)
Balance as of December 31, 2014		$12.9

	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$28.3	—		—			$28.3
U.S. Mid-cap Growth (a)	17.6		—		—		17.6
U.S. Small-cap (a)	18.2		—		—		18.2
International	33.4		—		—		33.4
Debt Securities:
Mutual Funds	30.8		—		—		30.8
Fixed Income	—			$15.5	—		15.5
Cash Equivalents	0.1		—		—		0.1
Other Types of Investments:
Private Equity Funds	—		—			$13.1	13.1
Total Fair Value of Assets		$128.4		$15.5		$13.1		$157.0

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

ALLETE, Inc. 2014 Form 10-K

118

NOTE 17. 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, 2012		$13.5
Actual Return on Plan Assets	2.4
Purchases, sales, and settlements, net	(2.8		)
Balance as of December 31, 2013		$13.1

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 18. 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 $9.1 million in 2014 ($8.4 million in 2013; $7.7 million in 2012).

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.

As of December 31	2014		2013		2012
Millions
ESOP Shares
Allocated	1.9		2.0		2.2
Unallocated	0.3		0.5		0.7
Total	2.2		2.5		2.9
Fair Value of Unallocated Shares		$13.2		$24.1		$28.7

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 0.8 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, 2014.

ALLETE, Inc. 2014 Form 10-K

119

NOTE 18. 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	2014		2013		2012
Millions
Performance Shares		$1.6		$1.7		$1.4
Restricted Stock Units	0.7		0.7		0.7
Total Share-Based Compensation Expense		$2.3		$2.4		$2.1
Income Tax Benefit		$1.0		$1.0		$0.9

ALLETE, Inc. 2014 Form 10-K

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NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized share-based compensation costs during the years ended December 31, 2014, 2013 or 2012.

As of December 31, 2014, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $1.8 million and $0.7 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.6 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, 2014, 2013 and 2012.

	2014				2013				2012
	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,	108,299			$44.10	395,678			$42.28	460,234			$41.68
Granted (a)	—		—		—		—		—		—
Exercised	(42,020	)		$43.65	(287,379	)		$41.60	(49,075	)		$35.84
Forfeited	—		—		—		—		(15,481	)		$44.86
Outstanding as of December 31,	66,279			$44.39	108,299			$44.10	395,678			$42.28
Exercisable as of December 31,	66,279			$44.39	108,299			$43.17	395,678			$41.71

(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 approximately $1.8 million in 2014. 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 $0.4 million during 2014 ($2.2 million in 2013; $0.3 million in 2012).

	Range of Exercise Price
As of December 31, 2014	$39.10 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	21,849		44,430
Weighted Average Remaining Contractual Life (Years)	2.9		1.7
Weighted Average Exercise Price		$39.27		$46.90
Aggregate Intrinsic Value (Millions)		$0.3		$0.4

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2014, 2013 and 2012.

	2014				2013				2012
	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,	114,765			$47.02	107,899			$40.73	128,333			$36.54
Granted (a)	47,992			$46.47	45,830			$52.15	38,764			$44.70
Awarded	(36,515	)		$42.01	(18,605	)		$35.10	(41,009	)		$34.25
Unearned Grant Award	—		—		(18,606	)		$35.10	(17,575	)		$34.25
Forfeited	(6,607	)		$48.29	(1,753	)		$47.26	(614	)		$34.49
Non-vested as of December 31,	119,635			$48.26	114,765			$47.02	107,899			$40.73

(a)    Shares granted include accrued dividends.

ALLETE, Inc. 2014 Form 10-K

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NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were 43,081 and 38,344 performance shares granted in January 2014 and 2015, for the three-year performance periods ending in 2016 and 2017, 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 $2.0 million and $2.3 million, respectively.

There were 36,515 performance shares awarded in February 2014 for the three-year performance period ending in 2013. There were no performance shares awarded in February 2015 for the three-year performance period ending in 2014. The grant date fair value of the shares awarded was $1.5 million and zero, respectively.

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2014, 2013 and 2012.

	2014				2013				2012
	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,	55,982			$40.85	56,415			$36.61	63,464			$32.57
Granted (a)	19,645			$48.44	21,440			$43.41	18,162			$40.83
Awarded	(18,860	)		$37.64	(20,939	)		$32.03	(24,707	)		$29.43
Forfeited	(2,879	)		$45.92	(934	)		$41.02	(504	)		$31.80
Available as of December 31,	53,888			$44.47	55,982			$40.85	56,415			$36.61

(a)    Shares granted include accrued dividends.

There were 17,491 and 15,633 restricted stock units granted in January 2014 and 2015, for the vesting periods ending in 2016 and 2017, respectively. The grant date fair value of the restricted stock units granted was $0.9 million and $0.9 million, respectively.

There were 18,860 restricted stock units awarded in 2014. The grant date fair value of the shares awarded was $0.7 million.

There were 17,815 restricted stock units awarded in February 2015. The grant date fair value of the shares awarded was $0.7 million.

NOTE 19. 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
2014
Operating Revenue		$296.5		$260.7		$288.9		$290.7
Operating Income		$48.3		$28.2		$60.8		$51.5
Net Income Attributable to ALLETE		$33.5		$16.8		$41.6		$32.9
Earnings Per Share of Common Stock
Basic		$0.81		$0.40		$0.97		$0.73
Diluted		$0.80		$0.40		$0.97		$0.73
2013
Operating Revenue		$263.8		$235.6		$251.0		$268.0
Operating Income		$44.4		$24.4		$38.4		$46.9
Net Income Attributable to ALLETE		$32.5		$14.0		$25.2		$33.0
Earnings Per Share of Common Stock
Basic		$0.83		$0.36		$0.63		$0.82
Diluted		$0.83		$0.35		$0.63		$0.82

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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
2012 Trade Accounts Receivable		$0.9		$1.0	—		$0.9		$1.0
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
2013 Trade Accounts Receivable		$1.0		$1.3	—		$1.2		$1.1
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
2014 Trade Accounts Receivable		$1.1		$1.8	—		$1.8		$1.1
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
Deferred Asset Valuation Allowance
2012 Deferred Tax Assets		$0.4	$2.0		—	—			$2.4
2013 Deferred Tax Assets		$2.4	$5.6		—	—			$8.0
2014 Deferred Tax Assets		$8.0		$14.1	—	—			$22.1

(a) Includes uncollectible accounts written off.

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