United States
Securities and Exchange Commission
Washington, D.C. 20549

Form 10-K

(Mark One)
R
(Mark One)
TAnnual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2009

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

Commission File No. 1-3548
ALLETE, Inc.
(Exact name of registrant as specified in its charter)

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


30 West Superior Street, Duluth, Minnesota 55802-2093
 (Address(Address of principal executive offices, including zip code)
(218) 279-5000
(Registrant’s telephone number, including area code)
Securities Registered Pursuantregistered pursuant to Section 12(b) of the Act:

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

Securities Registered Pursuantregistered 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 RT     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 RT

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act).
Large Accelerated Filer RLarge Accelerated Filer T    Accelerated Filer ¨Non-Accelerated Filer ¨Smaller Reporting Company ¨
Accelerated Filer £
Non-Accelerated Filer £
Smaller Reporting Company £

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

The aggregate market value of voting stock held by nonaffiliates on June 30, 2009,2012, was $974,440,368.$1,591,836,880.

As of February 1, 2010,2013, there were 35,243,90539,468,463 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference

Portions of the Proxy Statement for the 20102013 Annual Meeting of Shareholders are incorporated by reference in Part III.


1


Index

Definitions
3
  
Safe Harbor Statement Under the Private Securities Litigation Reform Act of 19955
  
Part I 
Item 1.6
 6
  6
  9
  11
  11
  11
  12
  15
  15
  15
  16
 16
  16
  16
  Non-Rate Base Generation17
  Other.17
 17
 21
 21
 22
Item 1A.23
Item 1B.26
Item 2.26
Item 3.26
Item 4.Submission of Matters to a Vote of Security Holders26
Part II 
Item 5.
2732
Item 6.28
Item 7.29
 29
 200930
 200832
 34
 35
 42
 46
 46
 46
 New48
Item 7A.48
Item 8.48
Item 9.48
Item 9A.48
Item 9B.49


ALLETE 2012 Form 10-K
2


Index
Part III 
Item 10.50
Item 11.50
Item 12.50
Item 13.50
Item 14.50
Part IV  
Item 15.51
  
55
  
58


ALLETE 20092012 Form 10-K
3

2


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 AcronymTerm
AICPAACAmerican Institute of Certified Public Accountants
ALLETEALLETE, Inc.
ALLETE PropertiesALLETE Properties, LLC and its subsidiariesAlternating Current
AFUDCAllowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods
AREAALLETEArrowhead Regional Emission AbatementALLETE, Inc.
ALLETE Clean EnergyALLETE Clean Energy, Inc.
ALLETE PropertiesALLETE Properties, LLC and its subsidiaries
ArcelorMittalArcelorMittal USA, Inc.
ARSAuction Rate Securities
ATCAmerican Transmission Company LLC
BasinBasin Electric Power Cooperative
Bison I1Bison I1 Wind Project
Bison 2Bison 2 Wind Project
Bison 3Bison 3 Wind Project
BisonBison Wind Energy Center
BNI CoalBNI Coal, Ltd.
BNSFBurlington Northern Santa Fe Railway Company
BoswellBoswell Energy Center
Boswell NOX Reduction Plan
CAIR
NOX emission reductions from Boswell Units 1, 2, and 4
Clean Air Interstate Rule
CO2
Carbon Dioxide
CompanyALLETE, Inc. and its subsidiaries
CSAPRCross-State Air Pollution Rule
DCDirect Current
DRIDevelopment of Regional Impact
EITFEmerging Issues Task Force
EPAEnvironmental Protection Agency
ESOPEmployee Stock Ownership Plan
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
Form 8-KALLETE Current Report on Form 8-K
Form 10-KALLETE Annual Report on Form 10-K
Form 10-QALLETE Quarterly Report on Form 10-Q
FTRFinancial Transmission Rights
GAAPAccounting Principles Generally Accepted in the United States
GHGGreenhouse Gases
Heating Degree DaysHibbardMeasure of the extent to which the average daily temperature is below 65 degrees Fahrenheit, increasing demand for heatingHibbard Renewable Energy Center
IBEW Local 31International Brotherhood of Electrical Workers Local 31
Invest DirectALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
Item___Item___of this Form 10-K
kVKilovolt(s)
LaskinLaskin Energy Center
LIBORLondon Inter Bank Offered Rate
MACTMaximum Achievable Control Technology
MagnetationMagnetation, Inc.
Manitoba HydroManitoba Hydro-Electric Board
MATSMercury and Air Toxics Standards
MBtuMillion British thermal units
Medicare Part DMedicare Part D provision of the Patient Protection and Affordable Care Act of 2010

ALLETE 2012 Form 10-K
4


Definitions (continued)

Mesabi NuggetMesabi Nugget Delaware, LLC
Minnesota PowerAn operating division of ALLETE, Inc.
Minnkota PowerMinnkota Power Cooperative, Inc.
MISOMidwest Independent Transmission System Operator, Inc.
Moody’sMoody’s Investors Service, Inc.
MPCAMinnesota Pollution Control Agency
ALLETE 2009 Form 10-K
3

Definitions (Continued)

MPUCMinnesota Public Utilities Commission
MW / MWhMegawatt(s) / Megawatt-hour(s)
NextEra EnergyNAAQSNextEra Energy Resources, LLCNational Ambient Air Quality Standards
NDPSCNorth Dakota Public Service Commission
NERCNorth American Electric Reliability Corporation
NOLNet Operating Loss
Non-residentialRetail 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
NPDESNational Pollutant Discharge Elimination System
NYSENew York Stock Exchange
OESMinnesota Office of Energy Security
Oliver Wind IOliver Wind I Energy Center
Oliver Wind IIOliver Wind II Energy Center
Palm Coast ParkPalm Coast Park development project in Florida
Palm Coast Park DistrictPalm Coast Park Community Development District
PolyMet MiningPolyMet Mining Corp.Corporation
PPAPower Purchase Agreement
PPACAPatient Protection and Affordable Care Act of 2010
PSCWPublic Service Commission of Wisconsin
PUHCA 2005Public Utility Holding Company Act of 2005
Rainy River EnergyRainy River Energy Corporation - Wisconsin
RSOPRetirement Savings and Stock Ownership Plan
SECSecurities and Exchange Commission
SO2
Sulfur Dioxide
Square ButteSquare Butte Electric Cooperative
Standard & Poor’sStandard & Poor’s Ratings Services a division of The McGraw-Hill Companies, Inc.
SWL&PSuperior Water, Light and Power Company
Taconite HarborTaconite Harbor Energy Center
Taconite RidgeTaconite Ridge Energy Center
Town CenterTown Center at Palm Coast development project in Florida
Town Center DistrictTown Center at Palm Coast Community Development District
WDNRU.S.Wisconsin DepartmentUnited States of Natural ResourcesAmerica
USS CorporationUnited States Steel Corporation



ALLETE 20092012 Form 10-K
5

4


Safe Harbor Statement
Under the Private Securities Litigation Reform Act of 1995Forward-Looking Statements

Statements in this report that are not statements of historical facts may beare 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 iscan 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,” “will likely result,“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 hereby filingproviding this cautionary statements identifyingstatement to identify important factors that could cause our actual results to differ materially from those projected, or expectations suggested,indicated in forward-looking statements made by or on behalf of ALLETE in this Annual Report on 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;
·prevailing governmental policies, regulatory actions, and legislation including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, and various local and county regulators, and city administrators, about allowed rates of return, financings, industry and rate structure, acquisition and disposal of assets and facilities, real estate development, operation and construction of plant facilities, recovery of purchased power, capital investments and other expenses, present or prospective wholesale and retail competition (including but not limited to transmission costs), zoning and permitting of land held for resale and environmental matters;
·our ability to manage expansion and integrate acquisitions;
·
the potential impacts of climate change and future regulation to restrict the emissions of GHG on our Regulated Operations;
·effects of restructuring initiatives in the electric industry;
·economic and geographic factors, including political and economic risks;
·changes in and compliance with laws and regulations;
·weather conditions;
·natural disasters and pandemic diseases;
·war and acts of terrorism;
·wholesale power market conditions;
·population growth rates and demographic patterns;
·effects of competition, including competition for retail and wholesale customers;
·changes in the real estate market;
·pricing and transportation of commodities;
·changes in tax rates or policies or in rates of inflation;
·project delays or changes in project costs;
·
availability and management of construction materials and skilled construction labor for capital projects;
·
changes in operating expenses, capital and land development expenditures;
·global and domestic economic conditions affecting us or our customers;
·our ability to access capital markets and bank financing;
·changes in interest rates and the performance of the financial markets;
·our ability to replace a mature workforce and retain qualified, skilled and experienced personnel; and
·the outcome of legal and administrative proceedings (whether civil or criminal) and settlements that affect the business and profitability of ALLETE.
our ability to successfully implement our strategic objectives;
regulatory or legislative actions, including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, the EPA and various state, local and county regulators, and city administrators, that impact our allowed rates of return, capital structure, ability to secure financing, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power, capital investments and other expenses, including present or prospective wholesale and retail competition and environmental matters;
our ability to manage expansion and integrate acquisitions;
our current and potential industrial and municipal customers’ ability to execute announced expansion plans;
the impacts on our Regulated Operations of climate change and future regulation to restrict the emissions of GHG;
effects of restructuring initiatives in the electric industry;
economic and geographic factors, including political and economic risks;
changes in and compliance with laws and regulations;
weather conditions, natural disasters and pandemic diseases;
war, acts of terrorism and cyber attacks;
wholesale power market conditions;
population growth rates and demographic patterns;
effects of competition, including competition for retail and wholesale customers;
zoning and permitting of land held for resale, real estate development or changes in the real estate market;
pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such commodities;
changes in tax rates or policies or in rates of inflation;
project delays or changes in project costs;
availability and managementof construction materials and skilled construction labor for capital projects;
changes in operating expenses and capital expenditures;
global and domestic economic conditions affecting us or our customers;
our ability to access capital markets and bank financing;
changes in interest rates and the performance of the financial markets;
our ability to replace a mature workforce and retain qualified, skilled and experienced personnel; and
the outcome of legal and administrative proceedings (whether civil or criminal) and settlements.

Additional disclosures regarding factors that could cause our results andor performance to differ from results or performancethose anticipated by this report are discussed in Item 1A under the heading “Risk Factors” beginning on page 2327 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 itwe assess the impact of each of these factors on theour businesses of ALLETE or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by us in this Form 10-K and in our other reports filed with the SEC that attempt to advise interested parties ofidentify the factorsrisks and uncertainties that may affect our business.


ALLETE 20092012 Form 10-K
6

5


Part I

Item 1.
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 144,000approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and wholesale electric service to 16 municipalities. Minnesota Power also provides regulated utility electric service to 1 private utility in Wisconsin. SWL&P, a wholesalewholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power,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.)authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 7,0006,100 acres of land available-for-sale in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2009,2012, unless otherwise indicated. All subsidiaries are wholly ownedwholly-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
       2009
       2008
       2007
    
Consolidated Operating Revenue – Millions$759.1$801.0$841.7
    
Percentage of Consolidated Operating Revenue   
Regulated Operations90%89%86%
Investments and Other10%11%14%
 100%100%100%
Year Ended December 312012
2011
2010
    
Consolidated Operating Revenue – Millions
$961.2

$928.2

$907.0
    
Percentage of Consolidated Operating Revenue   
Regulated Operations91%92%92%
Investments and Other9%8%8%
 100%100%100%

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


REGULATED OPERATIONSRegulated Operations

Electric Sales / Customers

Regulated Utility Electric Sales
Year Ended December 312009%2008%2007%
Millions of Kilowatt-hours      
Retail and Municipals      
Residential1,164101,17291,1419
Commercial1,420121,454121,45611
Industrial4,475377,192577,05455
Municipals (FERC rate regulated)99281,00281,0098
Total Retail and Municipals8,0516710,8208610,66083
Other Power Suppliers4,056331,800142,15717
 Total Regulated Utility Electric Sales12,10710012,62010012,817100
Regulated Utility Electric Sales      
Year Ended December 312012
%2011
%2010
%
Millions of Kilowatt-hours      
Retail and Municipals      
Residential1,132
91,159
91,150
9
Commercial1,436
111,433
111,433
11
Industrial7,502
577,365
566,804
52
Municipals1,020
81,013
71,006
7
Total Retail and Municipals11,090
8510,970
8310,393
79
Other Power Suppliers1,999
152,205
172,745
21
Total Regulated Utility Electric Sales13,089
10013,175
10013,138
100


ALLETE 2012 Form 10-K
7


Regulated Operations (Continued)

Seasonality

Due to the high concentration of industrial sales, Minnesota Power is not subject to significant seasonal fluctuations. The operations of our industrial customers, which make up a large portion of our sales portfolio as shown in the table above, are not typically subject to significant seasonal variations.

ALLETE 2009 Form 10-K
6


REGULATED OPERATIONS (Continued) As a result, Minnesota Power is generally not subject to significant seasonal fluctuations in electric sales; however, residential sales as compared to 2011 were down primarily due to unseasonably warm weather during the first four months of 2012. Heating degree days in Duluth, Minnesota were approximately 22 percent lower than the first four months of 2011.

Industrial Customers. In 2009,2012, our industrial customers represented 3757 percent of total regulated utility kilowatt-hour sales. Our industrial customers are primarily in the taconite mining, iron concentrate, paper, pulp and wood products, and pipeline industries.


Industrial Customer Electric SalesIndustrial Customer Electric Sales      
Year Ended December 312009%2008%2007%2012
%2011
%2010
%
Millions of Kilowatt-hours
            
Taconite Producers2,124474,579644,40862
Taconite/Iron Concentrate4,968
664,874
664,324
64
Paper, Pulp and Wood Products1,454331,567221,613231,571
211,560
211,573
23
Pipelines5041158285628
Other Industrial393946464717
4,4751007,1921007,054100
Pipelines and Other Industrial963
13931
13907
13
Total Industrial Customer Electric Sales7,502
1007,365
1006,804
100

Approximately 60Five Minnesota Power taconite customers produce approximately 75 percent of the iron ore consumed by integrated steel facilitiesproduced in the United States originates from sixU.S. according to the U.S. Geological Survey’s 2011 Minerals Yearbook published in January 2013. Sales to taconite customers of Minnesota Power, whichand iron concentrate customers represented 2,1244,968 million kilowatt-hours, or 4766 percent, of our total industrial sales in 2009.2012. Taconite, an iron-bearing rock of relatively low iron content, is abundantly available in northern Minnesota and an important domestic source of raw material for the steel industry. Taconite processing plants use large quantities of electric power to grind the iron-bearing rock, and agglomerate and pelletize the iron particles into taconite pellets.

BeginningMinnesota Power’s five taconite customers have the capability to produce up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the fallmanufacture of 2008, worldwideautomobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five percent of Minnesota taconite production is exported outside of North America.

During 2012, the domestic steel makers beganindustry’s production levels enabled Minnesota taconite producers to dramatically cutoperate at, or near, full capacity for the entire year. According to the American Iron and Steel Institute (AISI), an association of North American steel production in response to reduced demand driven largely by the global credit concerns. United Statesproducers, U.S. raw steel production ranoperated at approximately 5075 percent of capacity in 2009, reflecting poor demand2012, similar to 2011 levels of 75 percent, and up from 70 percent in automobiles, durable goods, and structural and other steel products.2010.


ALLETE 2012 Form 10-K
8


Regulated Operations (Continued)
Industrial Customers (Continued)

In late 2008, Minnesota taconite producers began to feel the impacts of decreased steel demand, and reduced taconite production levels occurred in 2009. Annual taconite production in Minnesota was approximately 18remained strong at, or near, full production with 39 million tons produced in both 2012 and 2011, up from 35 million tons in 2009 (40 million tons in 2008 and 39 million tons in 2007). Consequently, 2009 kilowatt-hour sales to our2010. The following table reflects Minnesota Power’s taconite customers were lower by approximately 54 percent from 2008customers’ production levels and we sold available power to Other Power Suppliers to partially mitigatefor the earnings impact of these lower taconite sales.past ten years.
Minnesota Power Taconite Customer Production
Year Tons (Millions)
2012* 39
2011 39
2010 35
2009 17
2008 39
2007 38
2006 39
2005 40
2004 39
2003 34
Source: Minnesota Department of Revenue December 2012 Mining Tax Guide for years 2003 - 2011.
* Preliminary data from the Minnesota Department of Revenue.

Raw steel production in the United States is projected to improve in 2010, and is estimated to run at approximately 60 percent of capacity. As a result, Minnesota Power expects an increase in taconite production in 2010 compared to 2009, although production will still be less than previous years’ levels. We will continue to market available power to Other Power Suppliers in an effort to mitigate the earnings impact of these lower industrial sales. These sales are dependent upon the availability of generation and are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. We can make no assurances that our power marketing efforts will fully offset the reduced earnings resulting from lower demand nominations from our industrial customers.

In addition to serving the taconite industry, Minnesota Power also serves a number of customers in the paper, pulp and wood products industry, which represented 1,4541,571 million kilowatt-hours, or 3321 percent, of our total industrial sales in 2009. In total, we serve four2012. Four major paper and pulp mills, directly and one paper mill indirectly by providing wholesale service towhich represent the retail providermajority of the mill. Minnesota Power also serves several wood product manufacturers.

Minnesota Power’s paper and pulp customers ranthis load, reported operating at, or very near, full capacity for the majority of 2009, despite the fact that the industry as a whole experienced the impacts of the global recession in reduced sales of nearly every paper grade. Federal tax credits provided a subsidy for paper producers which allowed them to remain competitive. Minnesota Power’s paper and pulp customers benefited from the temporary or permanent idling of competitor plants both in North America and in Europe, as well as continued strength of the Canadian dollar and the Euro which has reduced imports both from Canada and Europe.2012.

The pipeline industry is the third key industrial segment served by Minnesota Power with services provided to two crude oil pipelines and one refinery indirectly through SWL&P, which represented 504 million kilowatt-hours, or 11 percent, of our total industrial sales in 2009. These customers have a common reliance on the importation of Canadian crude oil. After near capacity operations in 2007, 2008, and 2009, both pipeline operators are executing expansion plans to transport Western Canadian crude oil reserves (Alberta Oil Sands) to United States markets. Access to traditional Midwest markets is being expanded to Southern markets as the Canadian supply is displacing domestic production and deliveries imported from the Gulf Coast.

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


ALLETE 2009 Form 10-K
7


REGULATED OPERATIONS (Continued)
Large Power Customer Contracts (Continued)

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. FourThree of the Large Power Customers have interruptible service which provides a discounted demand rate in exchange for the ability to interrupt the customers during system emergencies. Minnesota Power also provides incremental production service for customer demand levels above the contractual take-or-pay levels. There is no demand charge for this service and energy is priced at an increment above Minnesota Power’s cost. Incremental production service is interruptible.

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


ALLETE 2012 Form 10-K
9


Regulated Operations (Continued)
Large Power Customer Contracts (Continued)

Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates. TheThese customers receive estimated bills based on Minnesota Power’s predictionestimate of the customer’s energy usage, forecasted energy prices, and fuel clause adjustment estimates. Minnesota Power’s fivefour taconite-producing Large Power Customers have generally predictable energy usage on a week-to-week basis, which makesand any differences that occur are trued-up the variance between the estimated usage and actual usage small.

following month.

Contract Status for Minnesota Power Large Power Customers
As of February 1, 20102013

Customer(a)IndustryLocationOwnership
Earliest
Termination Date
Hibbing Taconite Co.
Taconite
Hibbing, MN
62.3% ArcelorMittal USA Inc.
23% Cliffs Natural Resources Inc.
14.7% United States Steel Corporation
December 31, 2015
ArcelorMittal USA – Minorca Mine (b)(a)
TaconiteVirginia, MNArcelorMittal USA Inc.February 28, 2014January 31, 2017
Hibbing Taconite Co. (a)
TaconiteHibbing, MN
62.3% ArcelorMittal
23.0% Cliffs Natural Resources Inc.
14.7% USS Corporation
January 31, 2017
United States SteelTaconite LLC (a)
TaconiteEveleth, MNCliffs Natural Resources Inc.January 31, 2017
USS Corporation
(USS – Minnesota Ore) (b,c)(a,b)
TaconiteMt. Iron, MN and Keewatin, MNUnited States SteelUSS CorporationFebruary 28, 2014
United Taconite LLCTaconiteEveleth, MNCliffs Natural Resources Inc.DecemberJanuary 31, 20152017
Mesabi Nugget Delaware, LLCIron NuggetHoyt Lakes, MN
80% Steel Dynamics, Inc (80%)Inc.
20% Kobe Steel USA (20%)
December 31, 2017
UPM, Blandin Paper Mill (b)
PaperGrand Rapids, MNUPM-Kymmene CorporationFebruary 28, 2014
Boise White Paper, LLCPaperInternational Falls, MNBoise Paper Holdings, LLCDecemberJanuary 31, 20132015
Sappi Cloquet LLC
UPM, Blandin Paper Mill (a)
Paper and PulpCloquet,Grand Rapids, MNSappi LimitedUPM-Kymmene CorporationFebruary 28, 2014January 31, 2017
NewPage Corporation – Duluth Mills Mill (b)(c)
Paper and PulpDuluth, MNNewPage CorporationFebruary 28, 2014December 31, 2022
Sappi Cloquet LLC (a)
Paper and PulpCloquet, MNSappi LimitedJanuary 31, 2017

(a)During 2009, three Large Power Customers moved to the Large Light and Power rate class.
(b)(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 February 28, 2014.January 31, 2017.
(c)
(b)United States SteelUSS Corporation includesowns both the Minntac Plant in Mountain Iron, MN and the Keewatin Taconite Plant in Keewatin, MN.
(c)
NewPage emerged from Chapter 11 bankruptcy in December 2012. The Duluth mill operations continued without interruption throughout the bankruptcy proceedings and a new 10-year contract was approved by the MPUC in a December 10, 2012 order. (See Note 1. Operations and Significant Accounting Policies Concentration of Credit Risk.)

Residential and Commercial Customers.In 2009,2012, our residential and commercial customers represented 2220 percent of total regulated utility kilowatt-hour sales. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 144,000143,000 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.

ALLETE 2009 Form 10-K
8


REGULATED OPERATIONS (Continued)

Municipal Customers.In 2009,2012, our municipal customers represented 8 percent of total regulated utility kilowatt-hour sales, which included 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. In 2008, Minnesota Power entered into new contractsThe private non-affiliated utility in Wisconsin, which requires 17 MW of average monthly demand, has submitted a cancellation notice with its municipal customers with the exception of one small customer (less than 2 MW) whose contract is now in the cancellation period. The new contracts transitioned each customer to formula based rates, allowing rates to be adjusted annually based on changes in costs, and expire intermination effective December 31, 2013. In February 2009, the FERC approved our municipal contracts, including the formula-based rate provision.(See Item 1. Business – Regulated Operations – Regulatory Matters.)

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

Approximately 200 MWs of capacity and energy from our Taconite Harbor facility in northern Minnesota has been sold through two sales contracts totaling 175 MWs (201 MWs including a 15 percent reserve), which were effective May 1, 2005, and expire on April 30, 2010. Both contracts contain fixed monthly capacity charges and fixed minimum energy charges. One contract provides for an annual escalator to the energy charge based on increases in our cost of fuel, subject to a small minimum annual escalation. The other contract provides that the energy charge will be the greater of the fixed minimum charge or an annual amount based on the variable production cost of a combined-cycle, natural gas unit. Our exposure in the event of a full or partial outage at our Taconite Harbor facility is significantly limited under both contracts. When the buyer is notified at least two months prior to an outage, there is no liability. Outages with less than two months notice are subject to an annual duration limitation typical of this type of contract.

On October 29, 2009,Basin Power Sales Agreement. Minnesota Power entered into an agreement to sell 100 MWsMW of capacity and energy to Basin for the next ten years to Basin. The transaction is scheduled to begina ten-year period which began in May 2010, following the expiration of the two wholesale power sales contracts on April 30, 2010. The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro rata share of increased costs related to emissions that may occur during the last five years of the contract.

ALLETE 2012 Form 10-K
10


Regulated Operations (Continued)
Other Power Suppliers (Continued)

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power. Under the power sales agreement, Minnesota Power will sell a portion of its output from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. (See Note 11. Commitments, Guarantees and Contingencies.)


Power Supply

In order to meet our customers’ electric requirements, we utilize a mix of Company generation and purchased power. The Company’s generation is primarily coal-fired, but also includes approximately 112 MWs91 MW of hydrohydroelectric generation from ten hydro stations in Minnesota, 317 MW of nameplate capacity wind generation, and 25 MWs81 MW of windbiomass co-fired generation. Purchased power is made upconsists of long-term power purchase agreementscoal, wind and hydro PPAs as well as market purchases. The following table reflects the Company’s generating capabilities as of December 31, 2012, and total electrical requirements as of December 31, 2009.output for 2012. Minnesota Power had an annual net peak load of 1,414 MWs1,633 MW on January 15, 2009.

July 2, 2012.

ALLETE 20092012 Form 10-K
11

9


REGULATED OPERATIONSRegulated Operations (Continued)
Power Supply (Continued)
    Year Ended
 UnitYearNetDecember 31, 2012
Regulated Utility Power SupplyNo.InstalledCapabilityGeneration and Purchases
   MWMWh%
Coal-Fired     
Boswell Energy Center1195868
  
in Cohasset, MN2196068
  
 31973362
  
 41980468
(a) 
   966
6,484,096
48.6
Laskin Energy Center1195347
  
in Hoyt Lakes, MN2195350
  
   97
368,364
2.8
Taconite Harbor Energy Center1195779
  
in Schroeder, MN2195776
  
 3196784
  
   239
872,319
6.4
Total Coal  1,302
7,724,779
57.8
Biomass/Coal/Natural Gas     
Hibbard Renewable Energy Center in Duluth, MN3 & 41949, 195158
20,332
0.2
Cloquet Energy Center in Cloquet, MN5200123
66,803
0.5
Total Biomass/Coal/Natural Gas  81
87,135
0.7
Hydro (b)
     
Group consisting of ten stations in MNMultipleMultiple91
285,118
2.1
Wind (c)
     
Taconite Ridge Energy Center in Mt. Iron, MNMultiple20084
62,393
0.5
Bison Wind Energy Center in Oliver and Morton Counties, NDMultiple2010-201242
280,869
2.1
Total Wind  46
343,262
2.6
Total Company Generation  1,520
8,440,294
63.2
Long-Term Purchased Power     
Lignite Coal - Square Butte near Center, ND   1,630,776
12.2
Wind - Oliver County, ND   341,105
2.6
Hydro - Manitoba Hydro in Winnipeg, MB, Canada   359,395
2.7
Total Long-Term Purchased Power  

2,331,276
17.5
Other Purchased Power (d)
   2,577,648
19.3
Total Purchased Power  

4,908,924
36.8
Total  1,520
13,349,218
100.0
Regulated Utility
Power Supply
Unit
No.
Year
Installed
Net Winter
Capability
Year Ended
December 31, 2009
Electric Requirements
   MWMWh%
Coal-Fired     
Boswell Energy Center1195868  
in Cohasset, MN2196067  
 31973352  
 41980429  
   9165,390,13142.8%
Laskin Energy Center1195355  
in Hoyt Lakes, MN2195351  
   106510,5054.1
Taconite Harbor Energy Center1195775  
in Schroeder, MN2195774  
 3196776  
   2251,058,2638.4
Total Coal  1,2476,958,89955.3
Biomass/Coal/Natural Gas     
Hibbard Renewable Energy Center     
in Duluth, MN3 & 41949, 19515440,7030.3
      
Cloquet Energy Center
in Cloquet, MN
520012219,3400.2
Total Biomass/Coal/Natural Gas  7660,0430.5
Hydro     
Group consisting of ten stations in MNVarious 109434,5413.5
Wind     
Taconite Ridge
in Mt. Iron, MN (a)
1-102008456,2550.4
Total Company Generation  1,4367,509,73859.7
Long-Term Purchased Power     
Square Butte burns lignite coal near Center, ND   1,695,25413.5
Wind – Oliver County, ND   361,6242.9
Hydro – Manitoba Hydro in Winnipeg, MB, Canada   433,5433.4
Total Long-Term Purchased Power   2,490,42119.8
      
Other Purchased Power(b)
   2,579,40820.5
Total Purchased Power   5,069,82940.3
Total  1,43612,579,567100.0%

(a)TheBoswell Unit 4 net capability shown above reflects Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4. (See Note 4. Jointly-Owned Facilities.)
(b)In June 2012, record rainfall and flooding occurred near Duluth, Minnesota and surrounding areas impacting Minnesota Power’s hydro system, particularly the Thomson Energy Center, which is currently off-line due to damage to the forebay canal and flooding at the facility. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Outlook - Hydro Operations.)
(c)Taconite Ridge consists of 10 wind turbine generator units with a total nameplate capacity of Taconite Ridge is 25 MWs.MW. Bison Wind Energy Center consists of 101 wind turbine generator units, with a total nameplate capacity of 292 MW. The capacitynet capability reflected in the table is the actual accredited capacity of the facility. Accredited capacityfacility, which is the amount of net generating capability associated with the facility for which capacity credit may bewas obtained using limited historical data. As more data is collected, actual accredited capacity may increase. Bison 1 was commissioned in December 2010 and January 2012 while Bison 2 and Bison 3 were commissioned in December 2012.
(b)
(d)Includes short termshort-term market purchases in the MISO market and from Other Power Suppliers.

ALLETE 2012 Form 10-K
12


Regulated Operations (Continued)

Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin coal region located in Montana and Wyoming. Coal consumption in 20092012 for electric generation at Minnesota Power’s coal-fired generating stations was approximately 4.24.6 million tons. As of December 31, 2009,2012, Minnesota Power had a coal inventory of about 810,0000.8 million tons. Minnesota Power’s primary coal supply agreements have expiration dates through 2011. Under these agreements, Minnesota Power has the flexibility to procure 70 percent to 100 percent of its total coal requirements.2014. In 2010,2013, Minnesota Power expects to obtain coal under these coal supply agreements and in the spot market. This diversity in coal supply options allows Minnesota Power to manage its coal market price and supply risk and to take advantage of favorable spot market prices. Minnesota Poweralso continues to explore other future coal supply options. We believe that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.

In 2001, Minnesota Power and BNSF entered into a long-term agreement under which BNSF transports all of Minnesota Power’s coal by unit train from the Powder River Basin directly to Minnesota Power’s generating facilities or to designated interconnection points. Minnesota Power also has transportation agreements with an affiliatein place for the delivery of a significant portion of its coal requirements. These transportation agreements have expiration dates through 2015. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the Canadian National Railway and with Midwest Energy Resources Company to transport coal from BNSF interconnection points to certain Minnesota Power facilities.

ALLETE 2009 Form 10-K
10


REGULATED OPERATIONS (Continued)
Fuel (Continued)fuel adjustment clause.

Coal Delivered to Minnesota Power
Year Ended December 31
       2009
       2008
       2007
Average Price per Ton$24.99$22.73$21.78
Average Price per MBtu$1.37$1.25$1.20
Coal Delivered to Minnesota Power
Year Ended December 312012
2011
2010
Average Price per Ton
$29.58

$28.85

$25.49
Average Price per MBtu
$1.64

$1.60

$1.42


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

Square Butte.Butte PPA. Under the long-term agreement with Square Butte, which expires at the end of 2026, Minnesota Power is currently entitled to approximately 50 percent of the output of a 455-MW coal-fired generating unit located near Center, North Dakota. (See Note 11. Commitments, Guarantees and Contingencies.) TheBNI Coal supplies lignite that has been dedicatedcoal to Square Butte by BNI Coal is located on lands essentially all of which are under private control and presently leased by BNI Coal.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 20092012 was approximately $1.02$1.35 per MBtu.

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

Oliver Wind I and II PPAs. In 2006 and 2007, Minnesota Power entered into two long-term wind power purchase agreementsPPAs with an affiliate of NextEra Energy, Inc. to purchase the output from two wind facilities, Oliver Wind I and II located near Center, North Dakota. We began purchasing the output from Oliver Wind I a 50-MW facility, in December 2006(50 MW) and the output from Oliver Wind II a 48-MW facility, in November 2007.(48 MW) — wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities. Wefacilities at fixed energy prices. There are no fixed capacity charges, and we only pay a contractedfor energy price and will receive any potential renewable energy or environmental air quality credits.as it is delivered to us.

We also haveManitoba Hydro PPAs. Minnesota Power has a power purchase agreementlong-term PPA with Manitoba Hydro that began in May 2009 and expires in April 2015. Under thethis agreement, with Manitoba Hydro, Minnesota Power will purchaseis purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

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

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



ALLETE 2012 Form 10-K
13


Regulated Operations (Continued)

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 250kV345 kV (29 miles), 250 kV (465 miles), 230 kV (605(698 miles), 161 kV (43 miles), 138 kV (128 miles), 115 kV (1,220(1,244 miles) and less than 115 kV (6,206(6,233 miles). We own and operate 166170 substations with a total capacity of 10,28711,322 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

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

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

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

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

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


Investment in ATC

Rainy River Energy, our wholly ownedwholly-owned subsidiary, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATC provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of establishing the independent operationFERC-approved and ownership of, and investment in, transmission facilities. ATC rates are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, 2009,2012, our equity investment balance in ATC was $88.4$107.3 million ($76.998.9 million at December 31, 2008)2011). (See Note 6. Investment in ATC.)


ALLETE 2012 Form 10-K
14


Regulated Operations (Continued)
Investment in ATC (Continued)

In September 2012, ATC updated its 10-year transmission assessment covering the years 2012 through 2021 which identifies between $3.9 and $4.8 billion in transmission system improvements. These investments by ATC are expected to be funded through a combination of internally generated cash, debt and investor contributions. As opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro rata ownership interest in ATC.

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


Properties

We own office and service buildings, an energy control center, repair shops, lease offices, 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. Generally, we hold fee interest inAll of our generating plants and most of our substations are located on real propertiesproperty owned by us, subject only to the lien of the mortgages. Mosta mortgage, whereas most of our electric lines are located on land notreal property owned in fee, but are covered by others with appropriate easement rights or by 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 Electric Facility.Facilities.)


ALLETE 2009 Form 10-K
11


REGULATED OPERATIONS (Continued)

Regulatory Matters

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

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

Information published by the Edison Electric Institute (Typical Bills and Average Rates Report – Summer 20092012 and Rankings – July 1, 20092012) ranked Minnesota Power as having the eighthfourth lowest average retail rates out of 175169 utilities in the United States. According to this report,U.S. Minnesota Power had the lowest rates in Minnesota and thirdsecond lowest in the region consisting of Iowa, Kansas, Minnesota, Missouri, North Dakota, South Dakota and Wisconsin.

Minnesota Power requires that all large industrial and commercial customers under contract specify the date when power is first required. Thereafter, the customer is generally billed monthly for at least the minimum power for which they contracted. These conditions are part of all contracts covering power to be supplied to new large industrial and commercial customers and to current customers as their contracts expire or are amended. All rates and other contract terms are subject to approval by appropriate regulatory authorities.

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

20082010 Rate Case. In May 2008, Minnesota Power filedPower’s current retail rates are based on a 2011 MPUC retail rate increase request with the MPUC seeking additional revenues of approximately $40 million annually; the request also sought an 11.15order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a capital structure consisting of 54.854.29 percent equity and 45.2 percent debt. As a result of a May 2009 Order and an August 2009 Reconsideration Order, the MPUC granted Minnesota Power a revenue increase of approximately $20 million, including a return on equity of 10.74 percent and a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.ratio.

Interim rates, subject to refund, were in effect from August 1, 2008 through October 31, 2009. During 2009, Minnesota Power recorded a $21.7 million liability for refunds of interim rates, including interest, required to be made as a result of the May 2009 Order and the August 2009 Reconsideration Order. In 2009, $21.4 million was refunded, with a remaining $0.3 million balance to be refunded in early 2010; $7.6 million of the refunds required to be made were related to interim rates charged in 2008.

With the May 2009 Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel began with the implementation of final rates on November 1, 2009. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

2010 Rate Case. Minnesota Power previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of 11.50 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue.

Minnesota law allows the collection of interim rates while the MPUC processes the rate filing. On December 30, 2009, the MPUC issued an Order (the Order) authorizing $48.5 million of Minnesota Power’s November 2, 2009, interim rate increase request of $73.0 million. The MPUC cited exigent circumstances in reducing Minnesota Power’s interim rate request. Because the scope and depth of this reduction in interim rates was unprecedented, and because Minnesota law does not allow Minnesota Power to formally challenge the MPUC’s action until a final decision in the case is rendered, on January 6, 2010, Minnesota Power sent a letter to the MPUC expressing its concerns about the Order and requested that the MPUC reconsider its decision on its own motion. Minnesota Power described its belief the MPUC’s decision violates the law by prejudging the merits of the rate request prior to an evidentiary hearing and results in the confiscation of utility property. Further, the Company is concerned that the decision will have negative consequences on the environmental policy directions of the State of Minnesota by denying recovery for statutory mandates during the pendency of the rate proceeding. The MPUC has not acted in response to Minnesota Power’s letter.

ALLETE 20092012 Form 10-K
15

12


REGULATED OPERATIONSRegulated Operations (Continued)
Regulatory Matters (Continued)

The rate case process requires public hearings and an evidentiary hearing before an administrative law judge, both of which are scheduled for the second quarter of 2010. A final decision on the rate request is expected in the fourth quarter. We cannot predict the final level of rates that may be approved by the MPUC, and we cannot predict whether a legal challenge toIn February 2011, Minnesota Power appealed the MPUC’s interim rate decision will be forthcoming or successful.in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). On February 14, 2012, the Court granted the petition for review and oral arguments were held before the Court on October 9, 2012. A decision is expected in early 2013; however, we cannot predict the outcome at this time.

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

ALLETE Clean Energy.In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota Wind Project.to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. On July 7, 2009,23, 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

Bison Wind Energy Center. Our Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity. The 82 MW Bison 1 wind facility was completed in two phases; the first phase in 2010 and the second phase in January 2012. The 105 MW Bison 2 and 105 MW Bison 3 wind facilities were completed in December 2012. Total project costs for our Bison Wind Energy Center were $473.3 million through December 31, 2012. In September 2011 and November 2011, the MPUC approved ourMinnesota Power’s petition seeking current cost recovery offor investments and expenditures related to Bison I2 and Bison 3, respectively.

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated transmission upgrades.with Bison 1. We anticipate filing a cost recovery petition with the MPUC in the first quarterhalf of 20102013 to establishupdate customer billing rates for the approved cost recovery. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will fulfill the 2025 renewable energy supply requirement for our retail load.1 and to include investments and expenditures associated with Bison I will be comprised of 33 wind turbines with a total nameplate capacity of 76 MWs, located near Center, North Dakota,2 and be in service in late 2010 and 2011.Bison 3.

On September 29, 2009, the NDPSC authorized site construction for Bison I. On October 2, 2009, Minnesota Power filed a route permit application with the NDPSC for a 22 mile, 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. An order is expected in the first quarter 2010.

On December 31, 2009, we purchased an existing 250 kV DC transmission line from Square Butte for $69.7 million. The 465-mile transmission line runs from Center, North Dakota to Duluth, Minnesota. We expect to use this line to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit. We expect that the Square Butte generating unit will continue to be fully utilized and supplied with lignite coal by BNI Coal, as Minnkota Power is expected to take Square Butte generation not utilized by Minnesota Power. Acquisition of this transmission line was approved by an MPUC order dated December 21, 2009. In addition, the FERC issued an order on November 24, 2009, authorizing acquisition of the transmission facilities and conditionally accepting, upon compliance and other filings, the proposed tariff revisions, interconnection agreement and other related agreements.

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

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction and the Federal MATS rule. On October 5, 2009,August 31, 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC its 2010 Integrated Resource Plan, a comprehensive estimate of future capacity needs within Minnesota Power’s service territory.and the MPCA. The plan proposes that Minnesota Power does not anticipate the need for new base load generation withininstall pollution controls by early 2016 to address both the Minnesota Power service territory overmercury emissions reduction requirements and the next 15 years,Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures and plans to meetare estimated future customer demand while achieving:

·Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios;
·Reductions in the emission of GHGs (primarily carbon dioxide); and
·Compliance with mandated renewable energy standards.

To achieve these objectives over the coming years, we plan to reshape our generation portfolio by adding 300 to 500 megawatts of renewable energy to our generation mix, and exploring options to incorporate peaking or intermediate resources. Our 76 MW Bison I Wind Project in North Dakota is expected to be in service in late 2010between $350 million and 2011.

We project average annual long-term growth of approximately one percent in electric usage over$400 million. The MPCA has 180 days to comment on the next 15 years. We will also focus on conservation and demand side management to meet the energy savings goals established in Minnesota legislation.

Emission Reduction Plans. We have made investments in pollution control equipment at our Boswell Unit 3 generating unit that reduces particulates, SO2, NOx and mercury emissions to meet future federal and state requirements. This equipment was placed in service in November 2009. During the construction phase,reduction plan, which then is reviewed by the MPUC authorizedfor a cash returndecision. We expect a decision by the MPUC on construction workthe plan in progressthe third quarter of 2013. After approval by the MPUC we anticipate filing a petition to include investments and expenditures in lieu of AFUDC, and this amount was collected through a current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to basecustomer billing rates.

The environmental regulatory requirements for Taconite Harbor Unit 3 are pending approval of the Minnesota Regional Haze implementation by the EPA. We are evaluating compliance requirements for this Unit. Environmental retrofits at Laskin and Taconite Harbor Units 1 and 2 have been completed and are in-service.

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

ALLETE 20092012 Form 10-K
16

13


REGULATED OPERATIONSRegulated Operations (Continued)
Regulatory Matters (Continued)

Transmission Investments. Transmission. We have an approved cost recovery rider in-placein place for certain transmission expenditures and the continued use of our current2009 billing factor was approved by the MPUC in June 2009.May 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. Our 2010 rate case proposesIn June 2011, we filed a request with the MPUC to move completedapprove an updated billing factor that includes additional transmission projects fromexpenditures, which we expect to be approved in the current cost recovery rider to base rates.first quarter of 2013.

Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues from service provided in the state on energy CIPs each year. These investments are recovered from retail customers through a billing adjustment and amountscombination of the conservation cost recovery charge included in retail base rates.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, as well asany financial incentive earned for cost-effective program achievements, and a carrying charge on the deferred account balance. Minnesota’s Next Generation Energy Act of 2007 introduced, in addition to the minimum spending requirements, an energy-saving goal of 1.5 percent of gross annual retail electric energy sales bybeginning with program year 2010. In June 2008,2010, a biennialtriennial filing was submitted for 20092011 through 2010,2013, and was subsequently approved by the OES. For future program years, Minnesota Power will build upon current successful CIPs in an effort to meet the newly established 1.5 percent energy-saving goal.Department of Commerce. Minnesota Power’s CIP investment goal was $6.0 million for 2012 ($5.9 million for 2011; $4.6 million for 2009 ($3.7 million for 2008; $3.2 million for 2007)2010), with actual spending of $5.5$6.8 million in 20092012 ($4.86.3 million in 2008; $3.92011; $5.6 million in 2007)2010).

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

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

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

Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. In 2008, Minnesota Power entered into newPower’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with thesethe remaining 15 Minnesota municipal customers which transitioned customers to formula-basedand SWL&P are effective through June 30, 2019. The rates allowing rates to be adjusted annually based on changesincluded in cost. In February 2009, the FERC approved our municipalthese contracts which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are calculated using a cost-based formula methodology that is set at the beginning of the year based on expectedeach July 1, using estimated costs and providea 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. Wholesale rate increases totaling approximately $6 million and $10 million annually were implementedcosts incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin. This customer submitted a cancellation notice with termination effective on February 1, 2009 and January 1, 2010, respectively, with approximately $6 millionDecember 31, 2013. The 17 MW of additional revenues under the true-up provision accruedaverage monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in 2009, which will be billed in 2010.2014.


ALLETE 2012 Form 10-K
17


Regulated Operations (Continued)
Regulatory Matters (Continued)

In August 2005, the Energy Policy Act of 2005 (EPAct 2005) was signed into law, which enacted PUHCA 2005. PUHCA 2005 gives FERC certain authority over books and records of public utility holding companies and their affiliates. It also addresses FERC review and authorization of the allocation of costs for non-power goods, or administrative or management services when requested by a holding company system or state commission. In addition, EPAct 2005 directs the FERC to issue certain rules addressing electricity reliability, investment in energy infrastructure, fuel diversity for electric generation, promotion of energy efficiency and wise energy use.

We believe the overall impact of the EPAct 2005 on the electric utility industry has been positive and are continuing to evaluate the effects on our business as this legislation is being implemented. This federal legislation is designed to bring more certainty to energy markets in which ALLETE participates, as well as to provide investment incentives for energy efficiency, energy infrastructure (such as electric transmission lines), and energy production. The FERC has the responsibility of implementing numerous new standards as a result of the promulgation of the EPAct 2005. To date, the FERC’s regulatory efforts under the EPAct 2005 appear to be generally positive for the utility industry.

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

During 2012, SWL&P’s currentretail rates were based on a 2010 PSCW retail rate order, which was effective January 1, 2011. SWL&P’s 2013 retail rates are based on a December 20082012 PSCW retail rate order, that became effective January 1, 2009,2013, and allows for an 11.1a 10.9 percent return on common equity. The new rates reflected a 3.5reflect an average overall increase of 2.4 percent average increase infor retail utility rates for SWL&P customers (a 13.413.8 percent increase in water rates, a 4.71.2 percent increase in electric rates, and a 0.62.0 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3$1.7 million in additional revenue.

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

On September 29, 2009, the NDPSC authorized site construction for Bison I. On October 2, 2009, Minnesota Power filed a route permit application with the NDPSC for the 22 mile, 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. An order is expected in the first quarter 2010.


ALLETE 2009 Form 10-K
14


Regional Organizations

Midwest Independent Transmission System Operator, Inc. (MISO).Minnesota Power and SWL&P are members of MISO, a regional transmission organization. While Minnesota Power and SWL&P retain ownership of their respective transmission assets, and control area functions, their transmission network isnetworks 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 broad region, encompassingwhich encompasses all or parts of 1511 states and onethe Canadian province of Manitoba, and over 100,000 MWsMW of generating capacity.

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

In January 2009, MISO launched the new Ancillary Services Market (ASM), aimed at establishingMidwest Reliability Organization (MRO).MinnesotaPoweris a market for energy and operating reserves. In May 2008, in preparationmember of the new market,MRO, one of the eight regional entities overseen by the NERC that is responsible for: (1) developing and implementing electricity reliability standards; (2) enforcing compliance with those standards; (3) providing seasonal and long-term assessments of the bulk power system’s ability to meet demand for electricity; and (4) providing an appeals and dispute resolution process.

The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, all of North Dakota, Minnesota, PowerNebraska and the othermajority of South Dakota, Iowa and Wisconsin. The region includes more than 100 organizations that are involved in the production and delivery of power to more than 20 million people. These organizations include municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown corporations, independent power producers and others who have interests in Minnesota prepared a joint filing seeking MPUC approval for the authority to account for costs and revenues that resulted from the institutionreliability of the ASM market. The MPUC conditionally approved Minnesota investor-owned utility participation in the MISO ASM market in an order dated March 17, 2009. Under this approval, recovery of ASM charges is subject to refund pending the MPUC’s review of our February 5, 2010 filing which documents the cost effectiveness of ASM. The utilities must validate ASM cost recovery to date, as well as on-going recovery, through a review of the cost and benefits of ASM participation. The Company cannot predict the outcome of this proceeding.bulk power system.

Mid-Continent Area Power Pool (MAPP). Minnesota Power also participates in MAPP, a power pool operating in parts of nine states in the Upper Midwest and in two Canadian provinces. MAPP functions include a regional transmission committee that is charged with planning for the future transmission needs of the region as well as ensuring that all electric industry participants have equal access to the transmission system.

Minnesota Legislation

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and municipal energy sales in Minnesota comebe from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. Minnesota Power has identified a plan to meet the renewable goals set by Minnesota and has included this in the most recent filing of the IRP with the MPUC. The law allows the MPUC to modify or delay meeting a standard obligationmilestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard,milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developingmet the 2012 milestone and makinghas developed a plan to meet the future renewable supply additions as part ofmilestones which is included in its generation planning strategy prior to2010 Integrated Resource Plan. The MPUC approved the enactment of this lawIntegrated Resource Plan in its order issued in May 2011. Minnesota Power will submit its next Integrated Resource Plan on March 1, 2013, and this activity continues.include an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025.


Greenhouse Gas Reduction. In 2007,
ALLETE 2012 Form 10-K
18


Regulated Operations (Continued)
Minnesota passed legislation establishing non-binding targets for carbon dioxide reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025, and at least 80 percent below 2005 levels by 2050. Minnesota is also participating in the Midwestern Greenhouse Gas Reduction Accord, a regional effort to develop a multi-state approach to GHG emission reductions.Legislation (Continued)

Minnesota Power has taken several steps in executing its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. We cannot predicthave executed two long-term PPAs with an affiliate of NextEra Energy, Inc. for wind energy in North Dakota (Oliver Wind I and II). Other steps include Taconite Ridge, our 25 MW wind facility located in northeastern Minnesota, and our 292 MW Bison Wind Energy Center in North Dakota. Approximately 20 percent of the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2013.


Competition

Retail electric energy sales in Minnesota and Wisconsin are made to customers in assigned service territories. As a result, most retail electric customers in Minnesota do not have the ability to choose their electric supplier. Large energy users outside of a municipality of 2 MW and above that are located outside of a municipality may be allowed to choose a supplier upon MPUC approval. Minnesota Power serves 10 Large Power facilities over 10 MW, none of which have engaged in a competitive rate process. TwoNo other large commercial or small industrial customers within the past 15 years that are over 2 MW but less than 10 MW under our Large Light and Power tariffin Minnesota Power’s service territory have participated inattempted to seek a competitive rate process with neighboring electric cooperatives but were ultimately retained byprovider outside Minnesota Power.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 fuelsforms of energy for their manufacturing processes.

For the year ended December 31, 2009, 2012, 8 percent of the Company’s electric energy sales were sales to municipal customers in Minnesota and a private non-affiliated utility in Wisconsin by contract under a formula-based rate approved by FERC. These customers have the right to seek an energy supply from any wholesale electric service provider upon contract expiration. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

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


ALLETE 2009 Form 10-K
15


Franchises

Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 93 cities and towns located within its electric service territory. SWL&P holds similar franchises for electric, natural gas and/or water systems in 15 cities and towns within its service territory.94 cities. The remaining cities, villages and towns served by us do not require a franchise to operate within their boundaries. Our exclusive service territories are established by state regulatory agencies.operate. SWL&P serves customers with electric, natural gas and/or water systems in 1 city and 16 villages and towns.


INVESTMENTS AND OTHERInvestments and Other

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 7,0006,100 acres of land available-for-sale in Minnesota, and earnings on cash and investments.

BNI Coal

BNI Coal operates a lignite mine in North Dakota. BNI Coal is a low-cost supplier of lignite in North Dakota, producing about 4 million tons annually. Two electric generating cooperatives, Minnkota Power and Square Butte, presently consume virtually all of BNI Coal’s production of lignite under cost-plus,a cost plus fixed fee coal supply agreementsagreement extending through 2026. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 11. Commitments, Guarantees and Contingencies.) The mining process disturbs and reclaims between 200 and 250 acres per year. Laws require that the reclaimed land be at least as productive as it was prior to mining. The average cost to reclaim one acreAs of land is approximately $35,000; however, dependingDecember 31, 2012, BNI had a $11.0 million asset reclamation obligation ($10.3 million at December 31, 2011) included in other non-current liabilities on conditions, it could be significantly higher. Reclamationour 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 coal passed through to customers. Withcredit. (See Note 11. Commitments, Guarantees and Contingencies.) BNI Coal has lignite reserves of an estimated 600650 million tons, BNI Coal has ample capacity to expand production.tons.

ALLETE 2012 Form 10-K
19


Investments and Other (Continued)

ALLETE Properties

ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, and sell the portfolio over time or in bulk transactions. ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise and reinvest the proceeds in itsour 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, a third major project that is currently in the planning stage, received land use approvals in December 2006. However, due to a change in Florida law that became effective in July 2009, those approvals are being revised. It is anticipated that thepermitting stage. The City of Ormond Beach, FL will approveFlorida, approved a new Development Agreementdevelopment agreement for Ormond Crossings in the first quarter of 2010. The new agreementwhich 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.

Town Center. Town Center, which is located in the City of Palm Coast, is a mixed-use development with a neo-traditional downtown core area. Construction of the major infrastructure improvements at Town Center was substantially complete at the end of 2008. At build-out, Town Center is expected to include approximately 3,000 residential units and 4.0 million square feet of various types of non-residential space. Sites have also been set aside for a new city hall, a community center, an art and entertainment center, and other public uses. Market conditions will determine how quickly Town Center builds out.

Palm Coast Park. Palm Coast Park, which is located in the City of Palm Coast, is a 4,700-acre mixed-use development. Construction of the major infrastructure improvements at Palm Coast Park was substantially complete at the end of 2007. At build-out, Palm Coast Park is expected to include approximately 4,000 residential units, 3.0 million square feet of various types of non-residential space and public facilities. Market conditions will determine how quickly Palm Coast Park builds out.

Ormond Crossings. Ormond Crossings, which is located in the City of Ormond Beach, is a 3,000-acre, mixed-use development. Planning, engineering design, and permitting of the master infrastructure are ongoing. At build out, Ormond Crossings is expected to include approximately 3,000 residential units, 5.0 million square feet of various types of non-residential space and public facilities. Market conditions will determine when Ormond Crossings will be built out. We do not expect any development activity at Ormond Crossings in 2010.

Lake Swamp. Lake Swamp wetland mitigation bank is a 1,900 acre regionally significant wetlands mitigation bank that was permitted by the St. Johns River Water Management District in 2008 and the U.S. Army Corps of Engineers in December 2009. Wetland mitigation credits will be used at Ormond Crossings and will also be available for sale to developers of other projects that are located in the bank’s service area. Applications are currently being prepared to expand the bank by approximately 1,000 acres.

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook for more information on ALLETE Properties’ land holdings.

ALLETE 2009 Form 10-K
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INVESTMENTS AND OTHER (Continued)

Seller Financing. ALLETE Properties occasionally provides seller financing to certain qualified buyers. At December 31, 2009,2012, outstanding finance receivables were $12.9$1.4 million, net of reserves, with maturities up to 3 years.through 2014. These finance receivables accrue interest at market-based rates and are collateralized by the financed properties.

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


ALLETE Clean Energy

In June 2011, we established ALLETE Clean Energy, a wholly-owned subsidiary of ALLETE. ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. (See Item 1. Business – Regulated Operations – Regulatory Matters.)


Non-Rate Base Generation

As of December 31, 2009,2012, non-rate base generationconsists of 30 MWs29 MW of generation at Rapids Energy Center. For January through October non-rate base generation also included Cloquet Energy Center (23 MWs of generation), which was transferred to rate base as a result of our 2008 rate order. In 2009,2012, we sold 0.20.1 million MWh of non-rate base generation (0.2(0.1 million in 20082011 and 2007)0.1 million in 2010).

Non-Rate Base Power SupplyUnit No.
Year
Installed
Year
Acquired
Net
Capability (MW)
Steam    
Biomass (a)
    
Cloquet Energy Center (b)
52001200122
    in Cloquet, MN    
Rapids Energy Center (c)
6 & 71969, 1980200029
in Grand Rapids, MN    
Hydro    
Conventional Run-of-River    
Rapids Energy Center (c)
4 & 5191720001
in Grand Rapids, MN    
Non-Rate Base Power SupplyUnit No.
Year
Installed
Year
Acquired
Net
Capability (MW)
Rapids Energy Center (a)
    
in Grand Rapids, MN    
Steam – Biomass (b)
6 & 71969, 1980200028
Hydro – Conventional Run-of-River4 & 51917, 194820001

(a)Cloquet Energy Center is supplemented by natural gas; Rapids Energy Center is supplemented by coal.
(b)Transferred to Regulated Operations as a result of our 2008 rate order on November 1, 2009.
(c)(a)The net generation is primarily dedicated to the needs of one customer.
(b)Rapids Energy Center’s fuel supply is supplemented by coal.

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



Other
ALLETE 2012 Form 10-K
20


Minnesota Land. We have approximately 7,000 acres of land available-for-sale in Minnesota. We acquired the land in 2001 when we purchased the Taconite Harbor generating facilities.


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 the Congress and the EPA. Most notably, clean energy technologies and the regulation of GHGs have taken a lead in these discussions. Minnesota Power’s fossil fueledfuel facilities will likely to be subject to regulation under these climate change policies.proposals. Our intention is to reduce our exposure to possible future carbon and GHG legislationthese requirements by reshaping our generation portfolio over time to reduce our reliance on coal.

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

We review environmental matters for disclosure on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accrualsAccruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomebecomes available. Accruals for environmental liabilities are included in the consolidated balance sheetConsolidated 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.

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Environmental Matters (Continued)

Air.Clean Air Act. The electric utility industry is heavily regulated both at the federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2and system-wide average NOlimits.state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of theseMinnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses or electrostatic precipitators. Minnesota Power’s generatingand low NOX technologies. Under currently applicable environmental regulations, these facilities are currently in compliancesubstantially compliant with applicable emission requirements.

New Source Review. Review (NSR)On. In August 8, 2008, Minnesota Power received a Notice of Violation (NOV) from the United States EPA asserting violations of the New Source Review (NSR)NSR requirements of the Clean Air Act at Boswell Units 1-41, 2, 3 and 4 and Laskin Unit 2. The NOV also asserts that the Boswell Unit 4 Title V permit was violated, and that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements.requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits.

Resolution of the NOVs will likely result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predictestimate the outcomeexpenditures, or range of these discussions. Since 2006, Minnesota Power has significantly reduced, and continues to reduce, emissions at Boswell and Laskin. The resolution could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements.expenditures that may be required upon resolution. Any costs of installing additional pollution control technologyequipment would likely be eligible for recovery in rates over time subject to MPUC and FERCregulatory approval in a rate proceeding.

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

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


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Environmental Matters (Continued)
Air (Continued)

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

EPA Clean Air Interstate Rule. In March 2005, the EPA announced the Clean Air Interstate Rule (CAIR) that sought to reduce and permanently cap emissions of SO2, NOX, and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit (Court) vacated the CAIR and remanded the rulemaking to the EPA for reconsideration while also granting our petition that the EPA reconsider including Minnesota asif a CAIR state. In September 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested that the CAIR be remanded without a court order. In December 2008, the Court granted the request that the CAIR be remanded without a court order, effectively reinstating a January 1, 2009, compliance date for the CAIR, including Minnesota. However, in the May 12, 2009, Federal Register, the EPA issued a proposedCSAPR replacement rule that would amend the CAIR to stay its effectiveness with respect to Minnesota until completion of the EPA’s determination of whether Minnesota should be included as a CAIR state. The formal administrative stay of CAIR for Minnesota was published in the November 3, 2009, Federal Register with an effective date of December 3, 2009. The EPA has indicated the CAIR Replacement Rule is expected in April 2010 with finalization in early 2011. At this time we do not have any indication whether Minnesota will be included in the Replacement Rule.promulgated.

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

Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007, the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was never filed due to the Court’s review of CAIR as more fully described above under “EPA Clean Air Interstate Rule.” Subsequently, theThe MPCA requested that companies with BART eligibleBART-eligible units complete and submit a BART emissions control retrofit study, which was done oncompleted for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirementrequirements for that unit. OnIn December 15, 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA.

In December 2011, the EPA published in the Federal Register a proposal to approve the trading program in the CSAPR as an alternative to determining BART. However, as a result of the August 2012 District of Columbia Circuit Court of Appeals decision to vacate the CSAPR (See CSAPR), Minnesota Power is now evaluating whether significant additional expenditures at Taconite Harbor Unit 3 will be required to comply with BART requirements under the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation to bring Taconite Harbor Unit 3 into compliance with the Regional Haze Rule requirements. It is uncertain what controls willwould ultimately be required at Taconite Harbor Unit 3 under this scenario. On January 30, 2013, Minnesota Power announced “EnergyForward”, a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes retiring Taconite Harbor Unit 3 in connection2015, subject to MPUC approval. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)
Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register on February 16, 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the regional haze rule.rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that they have approved Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas addressing the MATS requirements. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

EPA National Emission Standards for Hazardous Air Pollutants.Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2005,2011, a final rule was published in the Federal Register for industrial boiler maximum achievable control technology (Industrial Boiler MACT). The rule was stayed by the EPA also announcedin May 2011, to allow the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped electric utility mercury emissionsEPA time to consider additional comments received. The EPA re-proposed the rule in the continental United States through a cap-and-trade program. In February 2008,December 2011. On January 9, 2012, the United States District Court of Appeals for the District of Columbia Circuit vacated the CAMR and remanded the rulemaking toruled that the EPA for reconsideration. In October 2008,stay of the EPA petitionedIndustrial Boiler MACT was unlawful, effectively reinstating the Supreme CourtMarch 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released on December 21, 2012. Major sources have three years to reviewachieve compliance with the Court’s decisionfinal rule. Minnesota Power is in the CAMR case. In January 2009,process of assessing the EPA withdrew its petition, pavingimpact of this rule on our affected units including the way for possible regulation of mercuryHibbard Renewable Energy Center and other hazardous air pollutant emissions through Section 112 of the Clean Air Act, setting Maximum Achievable Control Technology standards for the utility sector. In December 2009, Minnesota Power and other utilities received an Information Collection Request from the EPA, requiring that emissions data be provided and stack testing be performed in order to develop an improved database with which to base future regulations. Cost estimatesRapids Energy Center. Costs for complying with potential future mercury and other hazardous air pollutant regulations under the Clean Air Actfinal rule cannot be estimated at this time.


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Environmental Matters (Continued)

Minnesota Mercury EmissionEmissions Reduction Act.Act This legislation requires. Under the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power is required to fileimplement a mercury emissionemissions reduction plansproject for Boswell Units 3 andUnit 4 with a goal of 90 percent reduction in mercury emissions. The Boswell Unit 3 emission reduction plan wasby December 31, 2018. On August 31, 2012, Minnesota Power filed with the MPCA in October 2006. Mercury control equipment has been installed and was placed into service in November 2009. (See Item 1. Business – Regulated Operations – Minnesota Public Utilities Commission – Emission Reduction Plans.) Aits mercury emissions reduction plan for Boswell Unit 4 is required by July 1, 2011, with implementation no later than December 31, 2014.the MPUC and the MPCA. The legislation calls forplan proposes that Minnesota Power install pollution controls to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule, which also regulates mercury emissions. Minnesota Power's request of an evaluationadditional year extending the date of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’s customers. Cost estimatescompliance for the Boswell Unit 4 emissionretrofit to April 1, 2016, was approved by the MPCA. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are not available at this time.included in the estimated capital expenditures required for compliance with the MATS rule discussed above.

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

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to reducerevise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA was scheduled to decide upon the 2008 eight-hour ozone standard in July 2011, but has since announced that it is deferring revision of this standard until 2013.

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM2.5) standard; the annual PM2.5 standard and the 24-hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM2.5 standards on June 14, 2012.

On December 14, 2012, the EPA confirmed in a final rule that the current annual PM2.5 standard, which has been in place since 1997, will be lowered, while retaining the current 24-hour PM2.5 standard. To implement the new lower annual PM2.5 standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects stating rulesand permits must comply with the new lower standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling. To bridge the transition to addressthe lower standard, the EPA is finalizing a grandfathering provision to ensure that projects and pending permits already underway are not unduly delayed.

Under the final rule, states will be responsible for additional PM2.5 monitoring, which will likely be accomplished by relocation or repurposing of existing monitors. States are expected to propose attainment designations by December 2013, based on already available monitoring data. The EPA believes that most U.S. counties currently already meet the new standard and plans to finalize designations of attainment by December 2014. For those counties that the EPA does not designate as having already met the requirements of the new standard, specific dates for required attainment will depend on technology availability, state permitting goals, potential legal challenges and other factors.

SO2 and NO2 NAAQS. During 2010, the EPA finalized new one-hour NAAQS for SO2 and NO2. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO2 NAAQS also require the EPA to evaluate modeling data to determine attainment. The EPA has notified states that their SIPs for attainment of these new, more stringent standardsthe standard will be required to be submitted to the EPA for approval by June 2013 but will not be required to include the evaluation of modeling data until December 2013.2017.

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


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Environmental Matters (Continued)

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

·Expand our renewable energy supply.
·Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies.
·Provide energy conservation initiatives with our customers and demand side efforts.
·Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.
·Achieve overall carbon emission reductions.

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

Expand our renewable energy supply;
Provide energy conservation initiatives for our customers and engage in other demand side efforts;
Support research of technologies to reduce carbon emissions from generation facilities and carbon sequestration efforts; and
Evaluating and developing less carbon intense future generating assets such as efficient and flexible natural gas generating facilities.

Federal Legislation. We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals at the Federal level to “cap” the amountEPA Regulation of GHG emissions have been made. On June 26, 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. H.R. 2454 is a comprehensive energy bill that also includes a cap-and-trade program. H.R. 2454 allocates a significant number of emission allowances to the electric utility sector to mitigate cost impacts on consumers. Based on the emission allowance allocations, we expect we would have to purchase additional allowances. We’re unable to predict at this time the value of these allowances.Emissions.

On September 30, 2009, the Senate introduced S. 1733, the Senate version of H.R. 2454. This legislation proposes a more stringent, near-term greenhouse emissions reduction target in 2020 of 20 percent below 2005 levels, as compared to the 17 percent reduction proposed by H.R. 2454. 

Congress may consider proposals other than cap-and-trade programs to address GHG emissions. We are unable to predict the outcome of H.R. 2454, S. 1733, or other efforts that Congress may make with respect to GHG emissions, and the impact that any GHG emission regulations may have on the Company. We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.

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

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

Greenhouse Gas Emissions Reporting. In May 2008, Minnesota passed legislation that required the MPCA to track emissions and make interim emissions reduction recommendations towards meeting the State’s goal of reducing GHG by 80 percent by 2050. GHG emissions from 2008 were reported in 2009.

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

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Environmental Matters (Continued)
Climate Change (Continued)

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

EPA Greenhouse Gas Reporting Rule. On September 22, 2009,2010, the EPA issued the final rule mandating that certain GHG emission sources, including electric generating units, are required to report emission levels. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule was effective January 1, 2010, and all GHG emissions must be reported on an annual basis by March 31 of the following year. Currently, we have the equipment and data tools necessary to report our 2010 emissions to comply with this rule.

Title V Greenhouse Gas Tailoring Rule. On October 27, 2009, the EPA issued the proposed Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring rule. This proposed regulation addresses the six primary greenhouse gases and newRule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds for when permits will be required to address GHG emissions for new andfacilities, at existing facilities whichthat undergo major modifications. The rule would require large industrialmodifications and at other facilities including power plants, to obtain construction and operating permits that demonstrate Best Available Control Technologies (BACT) are being used atcharacterized as major sources under the facility to minimize GHG emissions. The EPA is expected to propose BACT standards for GHG emissions from stationary sources.

Clean Air Act’s Title V program. For our existing facilities, the proposed rule does not require amending our existing Title V operating permits to include GHG requirements. However, GHG requirements are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

In late 2010, the EPA issued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the project-specific, top-down BACT determination process used for other pollutants will also be used to determine BACT for GHGs. However, modifyingGHG 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 installing units with GHG emissionslikely to be available to sources. It is possible that trigger the PSD permitting requirementsthese control technologies could require amending operating permitsbe determined to incorporatebe BACT to control GHG emissions.on a project-by-project basis.

EPA Endangerment Findings.On December 15, 2009,March 28, 2012, the EPA publishedannounced its findingsproposed rule to apply CO2 emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The proposed NSPS apply only to new or re-powered units and were open for public comment through June 25, 2012. It is anticipated that the emissionsEPA will issue NSPS for existing fossil fuel-fired generating units in the future. We cannot predict what CO2 control measures, if any, may be required by such NSPS.

Legal challenges have been filed with respect to the EPA’s regulation of six GHG, including CO2, methane, and nitrous oxide, endanger human health or welfare. This finding may result in regulations that establish motor vehicle GHG emissions, standards in 2010. There is also a possibility thatincluding the endangerment finding will enable expansion of the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. withTailoring Rule. On June 26, 2012, the United States District Court Circuit Court of Appeals on December 23, 2009.

Research and Study Initiatives. We participate in several research and study initiatives aimed at mitigating the potential impact of carbon emissions regulation on our business. Through this research, we cannot be certain that carbon emissions will be reduced or avoided through use of renewable energy sources or through implementing efficiency and conservation efforts. In developing strategies for our comprehensive approach to reducing our carbon emissions, we participate in and fund organizations and studies.

As an example, we commissioned a study with the University of Minnesota titled: Assessment of Carbon Flows Associated with Forest Management and Biomass Procurement for the Laskin Biomass Facility. This study wasDistrict of Columbia upheld most of the first of its kindEPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to comprehensively look at the carbon lifecycle as it relates to burning biomass for electrical generationregulate in the region.manner the EPA proposed. Comments to the permitting guidance were submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

We participateare 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 the Electric Power Research Institute’s CoalFleet for Tomorrow program, which reviews advanced clean coal generation and carbon capture research and assessment. Similarly, we participate as a North Dakota Lignite Interest member of the Canadian Clean Power Coalition. It also reviews advanced clean coal technologies focusing on lower rank sub-bituminous and lignite fuel energy conversion technologies and carbon control options. These provide Minnesota Power the ability to assess what technologies will best fit the economic fuels that are available in our region and when they may be available.general rate case.

We also participate in research through the Plains COWater.2 Reduction Partnership (PCOR). PCOR is looking at CO2 capture technology through research conducted at the Energy and Environmental Research Center, University of North Dakota. Minnesota Power is a partner, along with a number of other utilities, technology providers, and consultants, to further research on CO2 capture techniques, operational issues and costs. The partnership is funded by the members as well as the Department of Energy.

We cannot predict whether our participation in any of these activities will result in a benefit to ALLETE or impact the future financial position or results of operations of the Company.

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

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


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Environmental Matters (Continued)
Water (Continued)

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

Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA. The Toxic Substances Control Act regulates the management and disposal of materials containing polychlorinated biphenyl (PCB). In response to the EPA Region V’s request for utilities to participate in the Great Lakes Initiative by voluntarily removing remaining PCB inventories, Minnesota Power is in the process of voluntarily replacing its remaining PCB capacitor banks. Known PCB-contaminated oil in substation equipment was replaced by June 2007. We are in material compliance with these rules.

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its steamcoal-fired electric stations.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. Minnesota Power continues to monitor state and federal legislative andIn June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory activities that may affect its ash management practices. The EPA is expected to propose new regulationsschemes for coal ash. Comments on the proposed rule were due in February 2010 pertaining to the management of coal ash by electric utilities.November 2010. It is unknown how potential coal ash managementestimated that the final rule changes will affect Minnesota Power’s facilities. On March 9, 2009, the EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received an additional EPA information request pertaining to Boswell. Minnesota Power responded to both these information requests. On August 19, 2009, the Minnesota DNR visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findings or concerns from the DNR staff during the inspections.

Manufactured Gas Plant Site.be published in 2013. We are reviewing and addressing environmental conditions at a former manufactured gas plant site withinunable to predict the City of Superior, Wisconsin, and formerly operated by SWL&P.compliance costs we might incur; however, the costs could be material. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. At December 31, 2009, we have a $0.5 million liability for this site, which was accrued on December 31, 2003, and a corresponding regulatory asset as we expectwould seek recovery of remediationany additional costs to be allowed by the PSCW.through cost recovery riders or in a general rate case.


Employees

At December 31, 2009,2012, ALLETE had 1,4741,361 employees, of which 1,4111,322 were full-time.

Minnesota Power and SWL&P havehad an aggregate 614593 employees who are members of the International Brotherhood of Electrical Workers (IBEW)IBEW Local 31. Throughout 2009, Minnesota Power, SWL&P andThe current labor agreements with IBEW Local 31 worked under contract extensions of the agreements which expired on January 31, 2009. On April 10, 2009, IBEW Local 31 requested binding arbitration in accordance with the provisions of the contracts which also provided Minnesota Power and SWL&P with the protections of no strike clauses. Arbitration hearings took place October 5, 2009, with final resolution for Minnesota Power occurring in January 2010. The terms of the agreement are retro active to February 1, 2009, and will expire on January 31, 2012. SWL&P continues to work with its union and the arbitrator to resolve the remaining differences between the parties.2014.

BNI Coal has 137had 162 employees, of which 100117 are members of the IBEW Local 1593. The current labor agreement between BNI Coal and IBEW Local 1593 have a labor agreement which expires on March 31, 2011.2014.


Availability of Information

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


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Executive Officers of the Registrant

As of February 12, 2010,15, 2013, these are the executive officers of ALLETE:

Executive OfficersInitial Effective Date
  
Donald J. Shippar,Alan R. Hodnik, Age 60
53
 
Chairman and Chief Executive OfficerMay 12, 2009
Chairman, President and Chief Executive Officer – ALLETEJanuary 1, 2006May 10, 2011
President and Chief Executive Officer – ALLETEJanuary 21, 2004
Alan R. Hodnik, Age 50
May 1, 2010
President – ALLETEMay 12,1, 2009
Chief Operating Officer – Minnesota PowerMay 8, 2007
Senior Vice President – Minnesota Power OperationsSeptember 22, 2006
Vice President – Minnesota Power GenerationMay 1, 2005
  
Robert J. Adams,, Age 47
50
 
Vice President – Business Development and Chief Risk OfficerMay 13, 2008
Vice President – Utility Business DevelopmentFebruary 1, 2004
  
Deborah A. Amberg,, Age 44
47
 
Senior Vice President, General Counsel and SecretaryJanuary 1, 2006
Vice President, General Counsel and SecretaryMarch 8, 2004
  
Steven Q. DeVinck,, Age 50
53
 
Controller and Vice President – Business SupportDecember 17,5, 2009
ControllerJuly 12, 2006
  
David J. McMillan, Age 51
Senior Vice President – External Affairs – ALLETEJanuary 1, 2012
Senior Vice President – Marketing, Regulatory and Public Affairs – ALLETEJanuary 1, 2006
Executive Vice President – Minnesota PowerJanuary 1, 2006
Mark A. Schober,, Age 5457 
Senior Vice President and Chief Financial OfficerJuly 1, 2006
Senior Vice President and ControllerFebruary 1, 2004
  
Donald W. Stellmaker,, Age 52
55
 
Vice President, Corporate TreasurerAugust 19, 2011
TreasurerJuly 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 positions shown above, the following executives held other positions with the Company during the past five years.

Mr. DeVinck was Director of Nonutility Business Development, and Assistant Controller.
Mr. Hodnik was General Manager of Thermal Operations.

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 11, 2010.14, 2013.



ALLETE 20092012 Form 10-K
26

22


Item 1A.
Item 1A. Risk Factors

Readers are cautioned that forward-looking statements, including those containedThe risks and uncertainties discussed below, as well as other information set forth in this Form 10-K, could materially affect our business, financial condition and results of operations and should be read in conjunction with our disclosures under the heading: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” located on page 5 of this Form 10-K and the factors described below.carefully considered by stakeholders. The risks and uncertainties described in this Form 10-Ksection are not the only ones facing our Company.we face. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the concerns set forth below are realized.

Our results of operations could be negatively impacted if our Large Power Customers experience an economic down cycledownturn,incurwork stoppages or fail to compete effectively in the global economy.effectively.

Our ten9 Large Power Customers accounted for approximately 2333 percent of our 20092012 consolidated operating revenue (36(34 percent in 2008)2011; 31 percent in 2010). One of these customers accounted for 812.3 percent of consolidated revenue in 2009 (12.52012 (12.6 percent in 2008)2011; 12.5 percent in 2010). These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the global marketplace. AnMany 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 failureother events), fail to compete effectively in the global economy, or incur decreased demand for their product, there could have abe material adverse effecteffects on their operations and, consequently, could negativelyhave 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 governmentallegal 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 prevailing governmental policiesan extensive legal and regulatory actions,framework imposed under federal and state law including those of the United States Congress, state legislatures,regulations administered by the FERC, the MPUC, the PSCW, the NDPSC and the NDPSC.EPA as well as regulations administered by other organizations including the NERC. These governmentallaws and regulations relate to allowed rates of return, capital structure, financings, industryrate and ratecost structure, acquisition and disposal of assets and facilities, construction and operation of generation, transmission and constructiondistribution facilities (including the ongoing maintenance and reliable operation of plant facilities,such facilities), recovery of purchased power costs and capital investments, approval of integrated resource plans and present or prospective wholesale and retail competition, (including butamong other things. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. Compliance with these standards may lead to increased operating costs and capital expenditures. If we were found to not limited to transmission costs). be in compliance with these mandatory reliability standards or other statutes, rules and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations.(See Item 1. Business – Regulated Operations – Regulatory Matters.)

These governmentallaws and regulations significantly influence our operating environmentoperations 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 have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.

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


ALLETE 2012 Form 10-K
27


Item 1A. Risk Factors (Continued)

Our operations could be adversely impacted by emissions of greenhouse gases (GHG) that are linked to globalthe physical risks associated with climate change.

The scientific community generally accepts that emissions of GHGs are linked to global climate change. ClimatePhysical risks of climate change, creates physical and financial risk. These physical risks could include, but are not limited to, increasedsuch as more frequent or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency ofmore extreme weather events.events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs. An extreme weather event within our utility service areas can also directly affect our capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. These all have the potential to adversely affect the Company’sour business and operations.

Our operations could be adversely impacted by initiatives designed to reduce the impact of greenhouse gas (GHG)GHG emissions such as carbon dioxide CO2from our generating facilities.

Proposals for voluntary initiatives and mandatory controls to reduce GHGs such as carbon dioxide,CO2, a by-product of burning fossil fuels, are beinghave been discussed within Minnesota, among a group of Midwestern states that includes Minnesota and in the United States Congress and worldwide. WeCongress. Coal is currently use coal as the primary fuel in 95source for 92 percent of the energy produced by our generating facilities.

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



ALLETE 2009 Form 10-K
23


Risk Factors (Continued)

The cost of environmental emission allowances could have a negative financial impact on our operations.

Minnesota Power is subject to numerous environmental laws and regulations which cap emissions and could require us to purchase environmental emissions allowances to be in compliance. The laws and regulations expose us to emission allowance price fluctuations which could increase our cost of operations. We are unable to predict the emission allowance pricing, regulatory recovery or ratepayer impact of these costs.

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

We are subject to extensive environmental laws and regulations affecting many aspects of our present and future operations, including air quality, water quality, waste management, reclamation, hazardous wastes and other environmental considerations.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. emissions, coal ash and water discharge.

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

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

There are no assurances that existingExisting environmental regulations will notmay be revised or thatand new regulations seeking to protect the environment will notmay be adopted or become applicable to us. Revised or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our results of operations.

We cannot predict with certainty the amount or timing of all future expenditures related to environmental matters because of the difficulty of estimating such costs.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.

The operation Violations of certain environmental statutes, rules and maintenance of our generating facilities involve risks thatregulations could significantly increase the cost of doing business.

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

Our electrical generating operations must have adequate and reliable transmission and distribution facilities to deliver electricity to our customers.

Minnesota Power depends on transmission and distribution facilities owned by other utilities, and transmission facilities primarily operated by MISO, as well as its own such facilities, to deliver the electricity we produce and sell to our customers, and to other energy suppliers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered. We may have to forego sales or we may have to buy more expensive wholesale electricity that is available in the capacity-constrained area. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact the satisfaction of our customers with our service.sanctions for non-compliance.


ALLETE 20092012 Form 10-K
28

24


Item 1A. Risk Factors (Continued)

In our operations the price of electricity and fuel may be volatile.

Volatility in market prices for electricity and fuel may result from:

·severe or unexpected weather conditions;
·seasonality;
·changes in electricity usage;
·transmission or transportation constraints, inoperability or inefficiencies;
·availability of competitively priced alternative energy sources;
·changes in supply and demand for energy;
·changes in power production capacity;
·outages at Minnesota Power’s generating facilities or those of our competitors;
·changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
·natural disasters, 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 mainly impacts our wholesale power sales.

We are dependent on good labor relations.

We believe our relations to be good with our 1,474 employees. Failure to successfully renegotiate labor agreements could adversely affect the services we provide and our results of operations. Currently, 714 of our employees are members of either the IBEW Local 31 or Local 1593. The labor agreement with Local 31 at Minnesota Power and SWL&P expired on January 31, 2009. A new agreement between Minnesota Power and Local 31 went into effect in January 2010. The terms of the agreement are retroactive to February 1, 2009 and will expire on January 31, 2012. SWL&P continues to work with its union and the arbitrator to resolve the remaining differences between the parties. The labor agreement with Local 1593 at BNI Coal expires on March 31, 2011.

The current downturn in economic conditions may continue to adversely affect our real estate investment.

The ability of our real estate investment to generate revenue is directly related to the Florida real estate market, the national and local economy in general and changes in interest rates and the availability of credit. While conditions in the Florida real estate market may fluctuate over the long-term, continued demand for land is dependent on long-term prospects for strong, in-migration population expansion.

Our real estate investment is subject to extensive regulation through Florida laws regulating planning and land development which makes it difficult and expensive for us to conduct our operations.

Development of real property in Florida entails an extensive approval process involving overlapping regulatory jurisdictions. Real estate projects must generally comply with the provisions of the Local Government Comprehensive Planning and Land Development Regulation Act (Growth Management Act). In addition, development projects that exceed certain specified regulatory thresholds require approval of a comprehensive DRI application. The Growth Management Act, in some instances, can significantly affect the ability of developers to obtain local government approval in Florida. In many areas, infrastructure funding has not kept pace with growth. As a result, substandard facilities and services can delay or prevent the issuance of permits. Consequently, the Growth Management Act could adversely affect the cost of and our ability to develop future real estate projects. Changes in the Growth Management Act or DRI review process or the enactment of new laws regarding the development of real property could adversely affect our ability to develop future real estate projects.

Market performance and other changes could decrease the value of pension and postretirement health benefit plan assets, which then could require significant additional funding and increase annual expense.

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 Company holds significant assets in these trusts. 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 will increase the funding requirements under our benefit plans if the actual 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.


ALLETE 2009 Form 10-K
25


Risk Factors (Continued)

If we are not able to retain our executive officers and key employees, we may not be able to implement our business strategy and our business could suffer.

The success of our business heavily depends on the leadership of our executive officers, all of whom are employees-at-will and none of whom are subject to any agreements not to compete. If we lose the service of one or more of our executive officers or key employees, or if one or more of them decides to join a competitor or otherwise compete directly or indirectly with us, we may not be able to successfully manage our business or achieve our business objectives. We may have difficulty in retaining and attracting customers, developing new services, negotiating favorable agreements with customers and providing acceptable levels of customer service.

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

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

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

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

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

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

The price of electricity and fuel may be volatile.

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

severe or unexpected weather conditions and natural disasters;
seasonality;
changes in electricity usage;
transmission or transportation constraints, inoperability or inefficiencies;
availability of competitively priced alternative energy sources;
changes in supply and demand for energy;
changes in power production capacity;
outages at Minnesota Power’s generating facilities or those of our competitors;
availability of fuel transportation;
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
wars, sabotage, terrorist acts or other catastrophic events; and
federal, state, local and foreign energy, environmental, or other regulation and legislation.

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

ALLETE 2012 Form 10-K
29


Item 1A. Risk Factors (Continued)

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

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

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

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

Emerging technologies may adversely affect our business operations.

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

We may be vulnerable to cyber attacks.

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

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

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


ALLETE 2012 Form 10-K
30


Item 1A. Risk Factors (Continued)

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

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

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

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


Item 1B.
Item 1B. Unresolved Staff Comments

None.


Item 2.
Item 2. Properties

Properties are included in theA discussion of our businessesproperties is included in Item 11. Business and areis incorporated by reference herein.


Item 3.
Item 3. Legal Proceedings

MaterialA discussion of material legal and regulatory proceedings areis included in the discussion of our businesses in Item 11. Business and areis incorporated by reference herein.

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

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


Item 4.Submission of Matters to a Vote of Security Holders
Item 4. Mine Safety Disclosures

NoInformation concerning mine safety violations or other regulatory matters were submittedrequired by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to a vote of security holders during 2009.

this Form 10-K.


ALLETE 20092012 Form 10-K
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26


Part II

Item 5.
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 $0.44$0.475 per share on our common stock will be paidis payable on March 1, 2010,2013, to the holdersshareholders of record on February 15, 2010.2013.

The following table shows dividends declared per share, and the high and low prices forof our common stock for the periods indicated as reported by the NYSE:
20092008 2012  2011 
Price RangeDividendsPrice RangeDividendsPrice RangeDividendsPrice RangeDividends
QuarterHighLowDeclaredHighLowDeclaredHighLowDeclaredHighLowDeclared
      
First$33.27$23.35$0.44$39.86$33.76$0.43$42.49$39.98
$0.46
$39.36$36.33
$0.445
Second29.1424.450.4446.1138.820.43$41.99$38.030.46
$41.43$37.870.445
Third34.5727.750.4449.0038.050.43$42.66$40.330.46
$42.10$35.510.445
Fourth35.2932.230.4444.6328.280.43$42.09$37.730.46
$42.54$35.140.445
Annual Total  $1.76  $1.72 
$1.84
 
$1.78

At February 1, 2010,2013, there were approximately 29,00026,000 common stock shareholders of record.

Common Stock Repurchases. We did not repurchase any ALLETE common stock during 2009.



ALLETE 20092012 Form 10-K
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27


Item 6.
Item 6. Selected Financial Data


2009 2008 2007 2006 2005 2012
2011
2010
2009
2008
Millions           
Operating Revenue$759.1 $801.0 $841.7 $767.1 $737.4 
$961.2

$928.2

$907.0

$759.1

$801.0
Operating Expenses653.1 679.2 710.0 628.8 692.3(e)806.0
778.2
771.2
653.1
679.2
Income from Continuing Operations Before Non-Controlling Interest – Net of Tax60.7 83.0 89.5 81.9 20.3(e)
Income (Loss) from Discontinued Operations – Net of Tax   (0.9) (4.3)(e)
Net Income60.7 83.0 89.5 81.0 16.0 97.1
93.6
74.8
60.7
83.0
Less: Non-Controlling Interest in Subsidiaries(a)(0.3) 0.5 1.9 4.6  2.7 
(0.2)(0.5)(0.3)0.5
Net Income Attributable to ALLETE61.0 82.5 87.6 76.4 13.3 97.1
93.8
75.3
61.0
82.5
Common Stock Dividends56.5 50.4 44.3 40.7 34.4 69.1
62.1
60.8
56.5
50.4
Earnings Retained in (Distributed from) Business$4.5 $32.1 $43.3 $35.7 $(21.1) 
Earnings Retained in Business
$28.0

$31.7

$14.5

$4.5

$32.1
Shares Outstanding – Millions           
Year-End35.2 32.6 30.8 30.4 30.1 39.4
37.5
35.8
35.2
32.6
Average (a)(b)
              
Basic32.2 29.2 28.3 27.8 27.3 37.6
35.3
34.2
32.2
29.2
Diluted32.2 29.3 28.4 27.9 27.4 37.6
35.4
34.3
32.2
29.3
Diluted Earnings (Loss) Per Share          
Continuing Operations$1.89 $2.82 $3.08 $2.77 $0.64(e)
Discontinued Operations (b)
   (0.03) (0.16) 
$1.89 $2.82 $3.08 $2.74 $0.48 
Diluted Earnings Per Share
$2.58

$2.65

$2.19

$1.89

$2.82
Total Assets$2,393.1 $2,134.8 $1,644.2 $1,533.4(d)$1,398.8 
$3,253.4

$2,876.0

$2,609.1

$2,393.1

$2,134.8
Long-Term Debt695.8 588.3 410.9 359.8 387.8 933.6
857.9
771.6
695.8
588.3
Return on Common Equity6.9% 10.7% 12.4% 12.1% 2.2%(e)8.6%9.1%7.8%6.9%10.7%
Common Equity Ratio57.0% 58.0% 63.7% 63.1% 60.7% 54%56%56%57%58%
Dividends Declared per Common Share$1.76 $1.72 $1.64 $1.45 $1.245 
$1.84

$1.78

$1.76

$1.76

$1.72
Dividend Payout Ratio93% 61% 53% 53% 259%(e)71%67%80%93%61%
Book Value Per Share at Year-End$26.39 $25.37 $24.11 $21.90 $20.03 
$30.50

$28.77

$27.25

$26.39

$25.37
Capital Expenditures by Segment (c)
          
Capital Expenditures by Segment  
Regulated Operations$299.2 $317.0 $220.6 $107.5 $46.5 
$418.2

$228.0

$256.4

$299.2

$317.0
Investments and Other4.5 5.9 3.3  1.9 12.1 14.0
18.8
3.6
4.5
5.9
Discontinued Operations    4.5 
Total Capital Expenditures$303.7 $322.9 $223.9 $109.4 $63.1 
$432.2

$246.8

$260.0

$303.7

$322.9

(a)In 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased.
(b)Excludes unallocated ESOP shares.
(b)Operating results of our Water Services businesses and our telecommunications business are included in discontinued operations, and accordingly, amounts have been restate for all periods presented.
(c)In 2008, we made changes to our reportable business segments in our continuing effort to manage and measure performance of our operations based on the nature of products and services provided and customers served. (See Note 2. Business Segments.)
(d)Included $86.1 million of assets reflecting the adoption of Plan Accounting – Defined Benefit Pension Plans, and Health and Welfare Benefit Plans.
(e)Impacted by a $50.4 million, or $1.84 per share, charge related to the assignment of the Kendall County power purchase agreement.


ALLETE 20092012 Form 10-K
33

28


Item 7.
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: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995”“Forward-Looking Statements” located on page 56 and “Risk Factors” located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only ones facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the concerns set forth in this Form 10-K are realized.

Overview

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to 144,000approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and wholesale electric service to 16 municipalities. Minnesota Power also provides regulated utility electric service to 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (Seeauthorities. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 7,0006,100 acres of land available-for-sale in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2009,2012, unless otherwise indicated. All subsidiaries are wholly ownedwholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.


20092012 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2009,2012, to the year ended December 31, 2008.2011.

NetConsolidated net income attributable to ALLETE for 20092012 was $61.0$97.1 million, or $1.89$2.58 per diluted share, compared to $82.5$93.8 million, or $2.82$2.65 per diluted share, for 2008.2011. Net income for 2011 included the reversal of a $6.2 million, or $0.18 per share, deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. Net income for 2011 also included the recognition of a $2.9 million, or $0.08 per share, income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. Net income for 2012 reflected higher cost recovery rider revenue and renewable tax credits and increased sales to our industrial customers. These increases were partially offset by increased operation and maintenance, depreciation and interest expenses, as well as higher costs under our Square Butte PPA. Earnings per diluted share decreased approximately $0.19 compared to 2008dilution was $0.16 as a result of additional shares of common stock outstanding in 2009.2012. (See Note 12. Common Stock and Earnings Per Share.)

Regulated Operations net income attributable to ALLETE was $65.9$96.1 million in 2009 ($67.92012, compared to $100.4 million in 2008)2011. The decrease is primarily attributableNet income for 2011 included the reversal of a $6.2 million, or $0.18 per share, deferred tax liability related to lower net income ata revenue receivable Minnesota Power dueagreed to forgo as part of a 4.1 percent decreasestipulation and settlement agreement in kilowatt-hour sales, higher depreciation and interest expense, andits 2010 rate case. Net income for 2011 also included the accrualrecognition of retail rate refundsa $2.9 million, or $0.08 per share, income tax benefit related to 2008.the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. Net income for 2012 reflected higher cost recovery rider revenue and renewable tax credits, and increased sales to industrial customers. These decreasesincreases were partially offset by increased FERC-approved wholesale ratesoperating and MPUC-approved current cost recovery revenue. In addition, 2009 reflected $1.4 million in additional after-tax earnings frommaintenance, depreciation and interest expenses, as well as higher costs under our investment in ATC as a result of additional investments made to fund our pro-rata share of ATC’s voluntary capital contribution program.Square Butte PPA.

Investments and Other reflected a net loss attributable to ALLETE of $4.9 million in 2009 ($14.6 million of net income attributable to ALLETE in 2008). The decrease is primarily attributableof $1.0 million for 2012, compared to a $6.5 million reduction in earnings at ALLETE Properties and the absence of non-recurring items recorded in 2008. In 2009, ALLETE Properties recorded a net loss of $4.7$6.6 million versus net income of $1.8 million in 2008. In 2008, we recorded a $3.8 million non-recurring gain on the sale of certain available-for-sale securities and $5.8 million2011. The increase in non-recurring tax benefits and related interest2012 was primarily due to the closing of alower state income tax year and the completion of an IRS review.interest expense, partially offset by increased business development expenses.

ALLETE 20092012 Form 10-K
34

29


20092012 Compared to 20082011

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

Regulated Operations

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

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

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

Fuel adjustment clause recoveries decreased $30.4$1.7 million or 4 percent, from 2008 due to lower fuel and purchased power recoveries, lowercosts attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.)

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

Revenue from Regulated Operations decreased $1.1 million due to a 0.7 percent reduction in kilowatt-hour sales. The decrease in kilowatt-hour sales was primarily due to lower natural gas revenuesales to residential customers and Other Power Suppliers. Residential sales, as compared to 2011, were down primarily due to unseasonably warm weather during the first four months of 2012; heating degree days in Duluth, Minnesota were approximately 22 percent lower than in the first four months of 2011. Total kilowatt-hour sales to Other Power Suppliers decreased 9.3 percent from 2011. Sales to Other Power Suppliers are sold at SWL&P, andmarket-based prices into the accrualMISO market on a daily basis or through bilateral agreements of prior year retail rate refunds related to our 2008 retail rate case.various durations. These decreases were partially offset by higher sales to Other Power Suppliers, higher FERC-approved wholesale rates andour industrial customers, which increased revenue from MPUC-approved current cost recovery riders.1.9 percent over 2011.

Lower
 
Kilowatt-hours Sold
2012
2011
Quantity
Variance
%
Variance
Millions    
Regulated Utility    
Retail and Municipals    
Residential1,132
1,159
(27)(2.3)
Commercial1,436
1,433
3
0.2
Industrial7,502
7,365
137
1.9
Municipals1,020
1,013
7
0.7
Total Retail and Municipals11,090
10,970
120
1.1
Other Power Suppliers1,999
2,205
(206)(9.3)
Total Regulated Utility Kilowatt-hours Sold13,089
13,175
(86)(0.7)

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

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

Fuel and Purchased Power Expenseincreased$2.1 million, or 1 percent, from 2011 primarily due to a $3.2 million increase in the capacity component of our Square Butte PPA; the capacity component is not recovered through our fuel and purchased power recoveries along with a decrease in retail and municipal kilowatt-hour sales combined for a total revenue reduction of $116.2 million.adjustment clause. Fuel and purchased power recoveriesexpense related to our retail and municipal customers is recovered through the fuel adjustment clause (see Operating Revenue).

ALLETE 2012 Form 10-K
35


2012 Compared to 2011 (Continued)
Regulated Operations (Continued)

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

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

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

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

Investments and Other

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

ALLETE Properties20122011
Revenue and Sales Activity
Acres (a)

Amount
Acres (a)

Amount
Dollars in Millions    
Revenue from Land Sales

3

$0.4
Other Revenue (b)
 
$2.1
 
0.9
Total ALLETE Properties Revenue 
$2.1
 

$1.3
(a)Acreage amounts are shown on a gross basis, including wetlands.
(b)For the year ended December 31, 2012, Other Revenue includes wetland mitigation bank credit sales of $1.1million. For the year ended December 31, 2011, Other Revenue includes a $0.4 million forfeited deposit due to the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables.

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

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

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


ALLETE 2012 Form 10-K
36


2012 Compared to 2011 (Continued)

Income Taxes – Consolidated

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


2011 Compared to 2010

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

Regulated Operations

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

Revenue and Purchased Power Expense.) Total kilowatt-hour sales to retail and municipal customers decreased 26increased $21.5 million and 5.6 percent, respectively, from 20082010 primarily due to idled production lines and temporary closures at some of our taconite customers’ plants.

Natural gas revenue at SWL&P was lower by $7.8 million due to a 278.2 percent decrease in the price of natural gas and a 9 percent decline in sales. Natural gas revenue is primarily a flow-through of the natural gas costs. (See Operating and Maintenance Expense.)

Prior year retail rate refunds resulting from the 2009 MPUC Order and August 2009 Reconsideration Order were recorded in 2009 and resulted in a reduction in revenues of $7.6 million.

The decreaseincrease in kilowatt-hour sales to our industrial customers and the implementation of final retail and municipal customers has been partiallyrates. Increased revenue from those sales was offset by a $30.5 million and a 19.7 percent decrease in revenue from marketing the powerand kilowatt-hour sales, respectively, to Other Power Suppliers, which increased $77.2 million in 2009.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.

Higher rates from the March 1, 2008, and February 1, 2009, FERC-approved wholesale rate increases for our municipal customers increased revenue by $13.2 million.

MPUC-approved current cost recovery rider revenue increased $10.4 million in 2009 from 2008 primarily due to increased capital expenditures related to our Boswell Unit 3 emission reduction plan.

Kilowatt-hours Sold20092008Quantity Variance
%
Variance
2011
2010
Quantity
Variance
%
Variance
Millions      
Regulated Utility     
Retail and Municipals      
Residential1,1641,172(8)(0.7) %1,159
1,150
9
0.8
Commercial1,4201,454(34)(2.3) %1,433
1,433


Industrial4,4757,192(2,717)(37.8) %7,365
6,804
561
8.2
Municipals9921,002(10)(1.0) %1,013
1,006
7
0.7
Total Retail and Municipals8,05110,820(2,769)(25.6) %10,970
10,393
577
5.6
Other Power Suppliers4,0561,8002,256125.3 %2,205
2,745
(540)(19.7)
Total Regulated Utility Kilowatt-hours Sold
12,10712,620(513)(4.1) %13,175
13,138
37
0.3

Revenue from electric sales to taconite customers accounted for 1526 percent of consolidated operating revenue in 2009 (262011 (24 percent in 2008). The decrease in revenue from our taconite customers was partially offset by revenue from electric sales to Other Power Suppliers, which accounted for 20 percent of consolidated operating revenue in 2009 (10 percent in 2008)2010). Revenue from electric sales to paper, pulp and pulp millswood product customers accounted for 9 percent of consolidated operating revenue in 20092011 (9 percent in 2008)2010). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2009 (72011 (6 percent in 2008)2010).

Operating expenses decreased $20.1Cost recovery rider revenue increased $12.2 million due to higher capital expenditures primarily related to our Bison 1 and CapX2020 projects.

Fuel adjustment clause recoveries increased $6.3 million, or 38 percent, from 2008.

Fuel and Purchased Power Expense decreased $26.1 million, or 9 percent, from 20082010 due to decreasedan increase in kilowatt-hour sales and higher fuel and purchased power generationcosts attributable to lower kilowatt-hour sales, as well as a reduction in wholesale electricity prices. Minnesota Power’s coal generating fleet produced fewer kilowatt-hours of electricity due to planned outages to implement environmental retrofitsour retail and to respond to decreased demand from our taconitemunicipal customers.

Operating and Maintenance Expense decreased $3.5 million from 2008 primarily due to $7.4 million in lower natural gas costs at SWL&P from a decline in the price and quantity of natural gas purchased. This decrease was partially offset by increased salaries and benefits costs, rate case expenses and plant maintenance.

ALLETE 20092012 Form 10-K
37

30


20092011 Compared to 20082010 (Continued)
Regulated Operations (Continued)

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

Wholesale rate revenue increased $5.6 million reflecting higher rates.

Operating Expenses were consistent with 2010 overall.

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

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

Depreciation Expenseincreased $9.5$9.3 million, or 1912 percent, from 20082010 reflecting higheradditional property, plant and equipment balances placed in service.

Interest expense Expenseincreased $4.3$3.5 million, or 1811 percent, from 20082010 primarily due to additionalhigher long-term debt issued to fund new capital investments and $0.5 million related to retail rate refunds.balances.

Income Tax ExpenseEquity earnings increased $2.2 decreased $8.4 million, or 1416 percent, from 2008 reflecting higher earnings2010 primarily due to the reversal of a $6.2 million deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, increased renewable tax credits of $3.2 million and the recognition of a non-recurring $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from our increased investmentthe PPACA. Also contributing to the decrease was a non-recurring income tax charge of $3.6 million resulting from the PPACA in ATC.the first quarter of 2010. (See Note 6. Investment in ATC.5. Regulatory Matters.)

Investments and Other

Operating revenueRevenue decreased $11.5 increased $4.8 million, or 137 percent, from 2008 primarily due to2010 reflecting a $14.3$5.6 million reductionincrease in salesrevenue at BNI Coal, partially offset by a $0.9 million decrease in revenue at ALLETE Properties. In 2009, ALLETE Properties sold approximately 35 acres of properties located outside of our three main development projects for $3.8 million; no otherBNI Coal, which operates under a cost plus fixed fee contract, recorded higher sales were made in 2009 due to the continued lack of demand for our propertiesrevenue as a result of poor real estate market conditionshigher expenses in Florida. In 2008, ALLETE Properties sold approximately 219 acres of property located outside of our three main development projects for $6.3 million and recognized $3.7 million of previously deferred revenue under percentage of completion accounting. Revenue at ALLETE Properties in 2008 also included a pre-tax gain of $4.5 million from the sale of a retail shopping center in Winter Haven, Florida.2011. (See Operating Expense.)

ALLETE Properties20092008
Revenue and Sales ActivityQuantityAmountQuantityAmount
Dollars in Millions    
Revenue from Land Sales    
Acres (a)
35$3.8219$6.3
Contract Sales Price (b)
 3.8 6.3
Revenue Recognized from Previously Deferred Sales  3.7
Revenue from Land Sales 3.8 10.0
Other Revenue (c)
 0.2 8.3
 Total ALLETE Properties Revenue $4.0 $18.3
ALLETE Properties20112010
Revenue and Sales Activity
Acres (a)
Amount
Acres (a)
Amount
Dollars in Millions    
Revenue from Land Sales3

$0.4


Other Revenue (b)
 0.9
 
$2.2
Total ALLETE Properties Revenue 
$1.3
 
$2.2
(a)Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest.wetlands.
(b)Reflected total contract sales price on closed land transactions. Land sales are recorded usingFor the year ended December 31, 2011, Other Revenue included a percentage-of-completion method. (See Note 1. Operations$0.4 million forfeited deposit due to the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables. For the year ended December 31, 2010, Other Revenue included a $0.7 million pretax gain due to the return of seller-financed property from an entity which filed for Chapter 11 bankruptcy in June 2009. Also included in 2010 were $0.3 million of forfeited deposits and Significant Accounting Policies.)$0.3 million related to a lawsuit settlement.
(c)Included a $4.5 million pre-tax gain from the sale of a shopping center in Winter Haven, Florida in 2008.


BNI Coal, which operates under a cost-plus contract, recorded additional revenue of $5.6 million as a result of higher expenses. (See Operating Expenses.)
ALLETE 2012 Form 10-K
38


2011 Compared to 2010 (Continued)
Investments and Other (Continued)

Operating expensesExpenses decreased $6.0 increased $7.0 million, or 79 percent, from 20082010 reflecting lower fuel costs at our non-regulated generating facilities and decreased expense at ALLETE Properties due to both lower cost of land sold and reductions in general and administrative expenses. Expenses incurred as a result of a planned maintenance outage at a non-regulated generating facility in the third quarter of 2008 also contributed to the decrease in 2009. Partially offsetting these decreases was an increase in expensehigher expenses at BNI Coal of $5.1 million primarily due to higher permitting costs relating to mining expansion, a warranty credit in 2008, and dragline repairs in 2009. Thesefuel costs; these costs were recovered through the cost-pluscost plus fixed fee contract. (See Operating Revenue.Revenue.)

Interest expense increased $3.2 million from 2008 The remaining increase in 2011 was primarily dueattributable to a decrease in the proportion of ALLETEhigher business development, interest expense assigned to Minnesota Power. We record interest expense for Minnesota Power regulated operations based on Minnesota Power’s authorized capital structure and allocate the balance to Investments and Other. Effective August 1, 2008, the proportion of interest expense assigned to Minnesota Power decreased to reflect the authorized capital structure inherent in interim rates that commenced on that date. Interest expense was also higher in 2009 as 2008 included a $0.6 million reversal of interest expense previously accrued dueinvestment-related expenses. Also contributing to the closingincreased expenses was a $1.7 million pretax impairment charge taken at ALLETE Properties. In the fourth quarter of a tax year.

Other income (expense) decreased $16.0 million from 2008 primarily due2011, an impairment analysis of estimated future undiscounted cash flows was conducted and indicated that the cash flows were not adequate to a $6.5 million pre-tax gain realized fromrecover the salecarrying basis of certain available-for-sale securitiesproperties not strategic to our three major development projects. These increases were partially offset by a reduction in the first quarter of 2008, lower earnings on excess cash in 2009 of $1.9 million, and $1.4 million of interest income related to tax benefits recognized in the third quarter of 2008. Losses incurred on emerging technology investments totaled $4.6 million in 2009, and were $3.9 million higher than similar losses recorded in 2008.

operating expenses at ALLETE 2009 Form 10-K
31


2009 Compared to 2008 (Continued)Properties.

Income Taxes – Consolidated

For the year ended December 31, 2009,2011, the effective tax rate was 33.727.6 percent (34.3(37.2 percent for the year ended December 31, 2008)2010). The effective tax rate in each period deviated from the statutory rate (approximately 41 percent for 2009) due to deductions for Medicare health subsidies, AFUDC-Equity, investment tax credits, wind production tax credits, and depletion. In addition, the effective rate for 2009 was impacted by lower pre-tax income. In 2008, non-recurring tax benefits due to the closing of a tax year and the completion of an IRS review totaled $4.6 million.


2008 Compared to 2007

Regulated Operations

Regulated Operations contributed income of $67.9 million in 2008 ($62.4 million in 2007). The increase in earnings is primarily the result of higher rates and higher income from our investment in ATC. Higher rates resulted from a March 1, 2008, increase in FERC-approved wholesale rates, an August 1, 2008, MPUC-approved interim rate increase (subject to refund) for retail customers in Minnesota, and MPUC-approved current cost recovery on our environmental retrofit projects. These rate increases were partially offset by the expiration of sales contracts to Other Power Suppliers, and higher operations and maintenance expense, depreciation expense, and interest expense

Operating revenue decreased $11.6 million, or 2 percent, from 2007 primarily due to decreased fuel and purchased power recoveries and the expiration of sales contracts to Other Power Suppliers. These decreases were partially offset by higher rates and kilowatt-hour sales to retail and municipal customers.

Fuel and purchased power recoveries decreased due to a $42.0 million reduction in fuel and purchased power expense. (See Fuel and Purchased Power Expense discussion below.)

Revenue from sales to Other Power Suppliers decreased $21.1 million from 2007 due to the expiration of sales contracts.

Higher rates resulted from the August 1, 2008, interim rate increase for retail customers in Minnesota of approximately $13 million, current cost recovery on our environmental retrofit projects of approximately $21 million, and the March 1, 2008, increase in FERC-approved wholesale rates of approximately $6 million.

Kilowatt-hour sales to our retail and municipal customers increased 2 percent from 2007 primarily due to a 2 percent increase in industrial load. The increase in industrial sales was primarily due to an idled production line and production delays at one of our taconite customers in 2007. Total regulated utility kilowatt-hour sales were down 2 percent as the expiration of sales contracts to Other Power Suppliers more than offset the increased retail and municipal sales.

Kilowatt-hours Sold20082007Quantity Variance
%
Variance
Millions    
Regulated Utility    
Retail and Municipals    
Residential1,1721,141312.7%
Commercial1,4541,457(3)(0.2)%
Industrial7,1927,0541382.0%
Municipals1,0021,008(6)(0.6)%
Total Retail and Municipals10,82010,6601601.5%
Other Power Suppliers1,8002,157(357)(16.6)%
Total Regulated Utility Kilowatt-hours Sold
12,62012,817(197)(1.5)%

Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2008 (24 percent in 2007). Revenue from electric sales to paper and pulp mills accounted for 9 percent of consolidated operating revenue in 2008 (9 percent in 2007). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2008 (7 percent in 2007).

Operating expenses decreased $25.1 million, or 4 percent, from 2007.

Fuel and Purchased Power Expense decreased $42.0 million, or 12 percent, from 2007 primarily due to a decrease in purchased power expense, as a result of higher electricity production at the Company’s generation facilities. Megawatt-hour generation at our facilities and Square Butte increased 9 percent over 2007.

ALLETE 2009 Form 10-K
32


2008 Compared to 2007 (Continued)
Regulated Operations (Continued)

Operating and Maintenance Expense increased $10.0 million, or 4 percent, over 2007 primarily due to $3.3 million in increased natural gas purchases at SWL&P, reflecting a colder 2008, $2.5 million higher salaries and wages, $1.8 million in increased transmission costs, and $1.5 million in conservation improvement costs.

Depreciation Expense increased $6.9 million, or 16 percent, from 2007 reflecting higher property, plant, and equipment balances placed in service and higher annual depreciation rates for distribution and transmission effective January 1, 2008.

Interest expense increased $3.0 million, or 14 percent, from 2007 primarily due to higher long-term debt balances from increased construction activity.

Equity earnings increased $2.7 million, or 21 percent, from 2007 reflecting higher earnings from our investment in ATC. (See Note 6. Investment in ATC.)


Investments and Other

Investments and Other reflected net income of $14.6 million in 2008 ($25.2 million in 2007). The decrease in 2008 is primarily due to lower net income at ALLETE Properties, which continues to experience difficult real estate market conditions in Florida. This decrease was partially offset by the sale of certain available-for-sale securities in the first quarter of 2008, and tax benefits and related interest recognized in the third quarter of 2008.

Operating revenue decreased $29.1 million, or 25 percent, from 2007 primarily due to a decrease in sales revenue at ALLETE Properties in 2008. ALLETE Properties sold 219 acres of property in 2008 compared to 483 acres in 2007. In addition, 580,059 of non-residential square footage and 736 residential units were sold in 2007 compared to no non-residential or residential sales in 2008. Operating revenue in 2008 included a pre-tax gain of $4.5 million for the sale of our retail shopping center in Winter Haven, Florida in May 2008.


ALLETE Properties20082007
Revenue and Sales ActivityQuantityAmountQuantityAmount
Dollars in Millions    
Revenue from Land Sales    
Non-residential Sq. Ft.580,059$17.0
Residential Units73614.8
Acres (a)
219$6.348310.6
Contract Sales Price (b)
 6.3 42.4
Revenue Recognized from Previously Deferred Sales 3.7 3.1
Deferred Revenue  (1.2)
Revenue from Land Sales 10.0 44.3
Other Revenue (c)
 8.3 6.2
 Total ALLETE Properties Revenue $18.3 $50.5

(a)Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest.
(b)Reflected total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-completion method. (See Note 1. Operations and Significant Accounting Policies.)
(c)Included a $4.5 million pre-tax gain from the sale of a shopping center in Winter Haven, Florida in 2008.

Operating expenses decreased $5.7 million, or 6 percent, from 2007, primarily due to a $4.8 million decrease in the cost of real estate sold in Florida.

Interest expense increased $0.7 million in 2008 primarily due to higher interest expense at ALLETE, a portion of which is assigned to Minnesota Power and the remainder is reflected in the Investments and Other segment.

Other income increased $0.6 million, or 5 percent, from 2007 primarily due to a $6.5 million pre-tax gain realized from the sale of certain available-for-sale securities in the first quarter of 2008 and interest income related to tax benefits recognized in the third quarter of 2008. The gain was triggered when securities were sold to reallocate investments to meet defined investment allocations based upon an approved investment strategy. The increase was partially offset by fewer gains from land sales in Minnesota during 2008, and lower earnings on cash and short-term investments reflecting lower average cash balances, and the 2007 release from a loan guarantee for Northwest Airlines, Inc. of $1.0 million.

ALLETE 2009 Form 10-K
33


2008 Compared to 2007 (Continued)

Income Taxes – Consolidated

For the year ended December 31, 2008, the effective tax rate on income from continuing operations before non-controlling interest was 34.3 percent (34.8 percent for the year ended December 31, 2007).2011, was lowered by 4.8 percentage points due to the non-recurring reversal of the deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, and by 2.2 percentage points due to the income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. The decrease in the effective tax rate from the year ended December 31, 2010, was due to the 2011 non-recurring items above, and an increase in renewable tax credits. The effective tax rate in both years deviated from the statutory rate (approximately 40 percent)of approximately 41 percent primarily due to the recognition of various tax benefits as well as deductions for Medicare health subsidies, AFUDC-Equity,depletion, investment tax credits, and wind productionrenewable tax credits. In 2007, a tax benefit was realized as a result of a state income tax audit settlement ($1.6 million). In 2008, non-recurring tax benefits due to the closing of a tax year and the completion of an IRS review totaled $4.6 million.(See Note 14. Income Tax Expense.)


Critical Accounting EstimatesPolicies

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 subject toaccounted for in accordance with the guidance on accounting standards for the effects of certain types of regulation. This guidance requiresThese standards require us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets or liabilities arise as a result of a difference between GAAP and the accounting principles imposed by the regulatory agencies. 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.

We recognize The Company assesses quarterly whether regulatory assets and liabilities in accordance with applicable state and federal regulatory rulings. The recoverabilitymeet the criteria for probability of regulatory assets is periodically assessed by consideringfuture recovery or deferral. This assessment considers factors such as, but not limited to, changes in the regulatory rulesenvironment and recent rate orders issued by applicable regulatory agencies. The assumptions and judgments used by regulatory authorities may have an impact onto other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the rate of return on invested capital,assets and the timing and amount of assets toliabilities would be recovered by rates. A changerecognized in these assumptions may result in a material impact on our results of operations.current period net income or other comprehensive income. (See Note 5. Regulatory Matters.)


Valuation of Investments. Our long-term investment portfolio includes the real estate assets of
ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits, auction rate securities, and investments in emerging technology funds. Our policy is to review these investments for impairment on a quarterly basis by assessing such factors as continued commercial viability of products, cash flow and earnings. Our consideration of possible impairment for our real estate assets requires us to make judgments with respect to the current fair values of this real estate. The poor market conditions for real estate in Florida at this time require us to make certain assumptions in the determination of fair values due to the lack of current comparable sales activity. Any impairment would reduce the carrying value of our investments and be recognized as a loss. In 2009, we recorded an impairment loss on these investments of $1.1 million pretax (none in 2008; $0.5 million pretax in 2007), primarily due to our emerging technology funds. (See Note 7. Investments.)2012 Form 10-K
39


Critical Accounting Policies (Continued)

Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and postretirement benefit obligations in accordance with the accounting standards for defined benefit pension and other postretirement plans. These standards require the use of several important assumptions, including the expected long-term rate of return on plan assets and the discount rate, among others, in determining our obligations and the annual cost of our pension and postretirement benefits. An important actuarial assumption for pension and other postretirement benefit plans isIn establishing the expected long-term rate of return on plan assets. In establishing the expected long-term return on plan assets, we take into accountdetermine the actual long-term historical performance of our plan assets, the actual long-term historical performanceeach asset class, adjust these for the type of securities we are invested in,current economic conditions, and apply the historical performance utilizing the target allocation of our plan assets, to forecast anthe expected long-term return.  Our expected rate of return is then selected after considering the results of each of those factors, in addition to considering the impact of current economic conditions, if applicable, on long-term historical returns.return. Our pension asset allocation at December 31, 2009,2012, was approximately 5354 percent equity securities, 28 percent debt, 1413 percent private equity, and 5 percent real estate. Our postretirement health and life asset allocation at December 31, 2009,2012, was approximately 5456 percent equity 38securities, 35 percent debt, and 89 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. We currently use anIn 2012 we used expected long-term raterates of return of 8.58.25 percent in our actuarial determination of our pension expense and6.60 percent to 8.25 percent in our actuarial determination of our other postretirement expense. The actuarial determination uses an asset smoothing methodology for actual returns to reduce the volatility of varying investment performance over time. We review our expected long-term rate of return assumption annually and will adjust it to respond to any 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 $1.3$1.4 million pre-tax., pretax.


ALLETE 2009 Form 10-K
34


Critical Accounting Estimates (Continued)
Pension and Postretirement Health and Life Actuarial Assumptions (Continued)

The discount rate is computed using the Citigroup Pension Discount Curvea yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The Citigroup Pension Discount Curveyield curve is determined using high-quality, long-term corporate bond rates at the valuation date. We believe the adjustedIn 2012, we used discount curve usedrates of 4.54 percent and 4.56 percent in this comparison does not materially differ in duration and cash flows forour actuarial determination of our pension obligation.and other postretirement expense, respectively. We review our discount rate annually and will adjust it to respond to changing market conditions. A one-quarter percent decrease in the discount rate would increase the annual expense for pension and other postretirement benefits by approximately $2.2 million, pretax. (See Note 16.15. Pension and Other Postretirement Benefit Plans.)

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

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

Taxation.We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate and sales/use taxes. Judgments related to income taxes require the recognition in our financial statements of the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit. Tax positions that do not meet the “more-likely-than-not” criteria are reflected as a tax liability in accordance with the guidance for accounting standards for uncertainty in income taxes. We must also assess our ability to generate capital gains to realize tax benefits associated with capital losses. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the two prior or five succeeding years for federal purposes. We have recordedrecord a valuation allowance against our deferred tax assets associated with realized capital losses to the extent it has been determined that it is more-likely-than-not that some portion or all of the deferred tax assetassets will not be realized.

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


ALLETE 2012 Form 10-K
40


Outlook

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

We believe that, over the long term, windlong-term, less carbon intensive and more sustainable energy sources will play an increasingly important role in our nation’s energy mix. We intend to pursue the establishment of aMinnesota Power has developed renewable energy business focused initially on developing wind assets in North Dakota and the upper Midwest. We intend to develop wind resources which will be used to meet regulated renewable supply requirements and is considering additional investments. In addition, in June 2011, we established ALLETE Clean Energy, a wholly-owned subsidiary of our regulated businesses as well asALLETE. ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, thatclean coal and other clean energy innovations. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements, and will be marketedsubject to others. We willapplicable state and federal regulatory approvals. For wind development, we intend to capitalize on our existing presence in North Dakota through BNI Coal, our recently acquired DC transmission line and our Bison 1 wind project. Through BNI Coal weWind Energy Center. We have a long-term business presence and established landowner relationships in North Dakota. See page 38 for more discussion on the DC line acquisition and our Bison I project. For projects to be marketed to others, we intend to secure long-term power purchase agreements prior to construction of the wind generation facilities. Establishment of the business is subject to appropriate MPUC approvals.

We also plan to make investments in upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid or take advantage of our geographical location between sources of renewable energy and end users. In addition, we plan to make additionalThis includes the Great Northern Transmission Line and the CapX2020 initiative, as well as investments to fundenhance our pro rata share of ATC’s future capital expansion program.own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. Transmission investments could be made by Minnesota Power is also participating with other regional utilities in making regional transmission investments asor a membersubsidiary of the CapX2020 initiative. The CapX2020 initiative is discussed in more detail on page 40.ALLETE. (See Regulated Operations – Transmission.)

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

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

Regulated Operations.Minnesota Power’s long-term strategy is to maintain its competitively priced production ofbe the leading electric energy reduce customer concentration exposure, complyprovider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable requirements, and earn our allowed rate of return.requirements. Keeping the productioncost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain the viability of its customers. As part of maintaining cost competitiveness, Minnesota Power intends to reduce its exposure to possible future carbon and GHG legislation by reshaping its generation portfolio, over time, to reduce its reliance on coal. Minnesota Power intends to reduce its customer concentration risk to reduce exposure to cyclical industries; this may include restructuring commercial contracts, additional sales to other regional power suppliers, and reshaping our power supply to be more flexible to swings in customer demand. We will monitor and review proposed environmental proposalsregulations and may challenge those that add considerable cost with limited environmental benefit. Current economic conditions require a very careful balancing of the benefit of furtherMinnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, controls with the impacts of the costs of those controls on our customersrenewable and transmission investments, as well as on the company, and its competitive position. We will pursue current cost recovery riders to recover environmental and renewable investments, and will work with our legislators and regulators to earn a fair rate of return. We project that our Regulated Operations will not earn its allowed rate of return in 2013.

Regulatory Matters.Rates. Entities within our Regulated Operations segment file for periodic rate revisions withare under the jurisdiction of the MPUC, the FERC or the PSCW.

ALLETE 2009 Form 10-K
35


Outlook (Continued)
Rates (Continued)

2008 Rate Case. In May 2008, See Item 1. Business – Regulated Operations – Regulatory Matters for discussion of regulatory matters within our Minnesota, Power filed a retail rate increase request with the MPUC seeking additional revenues of approximately $40 million annually; the request also sought an 11.15 percent return on equity,FERC, Wisconsin and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. As a result of a May 2009 Order and an August 2009 Reconsideration Order, the MPUC granted Minnesota Power a revenue increase of approximately $20 million, including a return on equity of 10.74 percent and a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.North Dakota jurisdictions.

Interim rates, subject to refund, were in effect from August 1, 2008 through October 31, 2009. During 2009, Minnesota Power recorded a $21.7 million liability for refunds of interim rates, including interest, required to be made as a result of the May 2009 Order and the August 2009 Reconsideration Order. In 2009, $21.4 million was refunded, with a remaining $0.3 million balance to be refunded in early 2010; $7.6 million of the refunds required to be made were related to interim rates charged in 2008.

With the May 2009 Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel began with the implementation of final rates on November 1, 2009. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

2010 Rate Case. Minnesota Power previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of 11.50 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue.

Minnesota law allows the collection of interim rates while the MPUC processes the rate filing. On December 30, 2009, the MPUC issued an Order (the Order) authorizing $48.5 million of Minnesota Power’s November 2, 2009, interim rate increase request of $73.0 million. The MPUC cited exigent circumstances in reducing Minnesota Power’s interim rate request. Because the scope and depth of this reduction in interim rates was unprecedented, and because Minnesota law does not allow Minnesota Power to formally challenge the MPUC’s action until a final decision in the case is rendered, on January 6, 2010, Minnesota Power sent a letter to the MPUC expressing its concerns about the Order and requested that the MPUC reconsider its decision on its own motion. Minnesota Power described its belief the MPUC’s decision violates the law by prejudging the merits of the rate request prior to an evidentiary hearing and results in the confiscation of utility property. Further, the Company is concerned that the decision will have negative consequences on the environmental policy directions of the State of Minnesota by denying recovery for statutory mandates during the pendency of the rate proceeding. The MPUC has not acted in response to Minnesota Power’s letter.

The rate case process requires public hearings and an evidentiary hearing before an administrative law judge, both of which are scheduled for the second quarter of 2010. A final decision on the rate request is expected in the fourth quarter. We cannot predict the final level of rates that may be approved by the MPUC, and we cannot predict whether a legal challenge to the MPUC’s interim rate decision will be forthcoming or successful.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts with these customers which transitioned customers to formula-based rates, allowing rates to be adjusted annually based on changes in cost. In February 2009, the FERC approved our municipal contracts which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are set at the beginning of the year based on expected costs and provide for a true-up calculation for actual costs. Wholesale rate increases totaling approximately $6 million and $10 million annually were implemented on February 1, 2009 and January 1, 2010, respectively, with approximately $6 million of additional revenues under the true-up provision accrued in 2009, which will be billed in 2010.

2009 Wisconsin Rate Increase. SWL&P’s current retail rates are based on a December 2008 PSCW retail rate order that became effective January 1, 2009, and allows for an 11.1 percent return on equity. The new rates reflected a 3.5 percent average increase in retail utility rates for SWL&P customers (a 13.4 percent increase in water rates, a 4.7 percent increase in electric rates, and a 0.6 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3 million in additional revenue.

Industrial CustomersCustomers.. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, production,pulp and wood products, and pipeline industries. In 2009, approximately 372012, 57 percent (57 (56 percent in 2008),2011) of our Regulated Utility kilowatt-hour sales were made to our industrial customers which includes the taconite, paper and pulp, and pipelinein these industries.

BeginningMinnesota Power provides electric service to five taconite customers capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the fallmanufacture of 2008, worldwide steel makers began to dramatically cut steel productionautomobiles, appliances, pipe and tube products for the gas and oil industry, and in response to reduced demand driven largely by the global credit concerns. United States raw steel production ran at approximately 50construction industry. Historically, less than five percent of capacity in 2009, reflecting poor demand in automobiles, durable goods, and structural and other steel products.Minnesota taconite production is exported outside of North America.

ALLETE 20092012 Form 10-K
41

36


Outlook (Continued)
Industrial Customers (Continued)

In late 2008,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, begannational and regional steel industry associations, and steel research institutes representing around 85 percent of world steel production, projected U.S. steel consumption in 2013 will be similar to feel the impacts2012. The American Iron and Steel Institute (AISI), an association of decreasedNorth American steel demand, and reducedproducers, reported that U.S. raw steel production operated at approximately 75 percent of capacity in 2012 (75 percent in 2011, 70 percent in 2010). Based on these projections, 2013 taconite production levels occurred in 2009. Annual taconite production in Minnesota wasare expected to be similar to 2012. The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years.

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

Our taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We estimate that a one million ton change in our taconite customers’ production would change our annual earnings per share by approximately 18 million tons$0.03, net of power marketing sales at 2012 year-end prices. Changes in 2009 (40 million tonswholesale electric prices or customer contractual demand nominations could impact this estimate. Long-term reductions in 2008 and 39 million tons in 2007). Consequently, 2009 kilowatt-hour salesproduction 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, were lower by approximately 54 percent from 2008 levels, and we sold available power to Other Power Suppliers to partially mitigate the earnings impact of these lower taconite sales.

Raw steel production in the United States is projected to improve in 2010, and is estimated to run at approximately 60 percent of capacity. As a result, Minnesota Power expects an increase in taconite production in 2010 compared to 2009, although production will still be less than previous years’ levels. We will continue to market available power to Other Power Suppliers in an effort to mitigate the earnings impact of these lower industrial sales. Sales to Other Power Suppliers are dependent upon the availability of generation and are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. We can make no assurances that our power marketing efforts will fully offset the reduced earnings resulting from lower demand nominations from our industrial customers.

Minnesota Power’s four major paper and pulp customersmills ran at, or very near, full capacity for the majority of 2009, despite the fact that the industry as a whole experienced the impacts of the global recession2012. Similar levels are expected in reduced sales of nearly every paper grade. Federal tax credits provided a subsidy for paper producers which allowed them to remain competitive. Minnesota Power’s paper and pulp customers benefited from the temporary or permanent idling of competitor plants both in North America and in Europe, as well as continued strength of the Canadian dollar and the Euro which has reduced imports both from Canada and Europe.

Our pipeline customers continued to operate at near capacity levels. As Western Canadian oil sands reserves continue to develop and expand, pipeline operators served by the Company are executing expansion plans to transport Western Canadian crude oil reserves (Alberta Oil Sands) to United States markets. Access to traditional Midwest markets is being expanded to Southern markets as the Canadian supply is displacing domestic production and deliveries imported from the Gulf Coast. We believe we are strategically positioned to serve these expanding pipeline facilities.2013.

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

Prospective Additional Load. SeveralMinnesota Power is pursuing new wholesale and retail loads in and around its service territory. Currently, several companies in northeastern Minnesota continue to progress in the development of natural resource based projects that represent long-term growth potential and load diversity for Minnesota Power. These potential projects are in the ferrous and non-ferrous mining and steel industries. These projectsindustries and include PolyMet, Mining Corporation (PolyMet), Mesabi Nugget, Delaware, LLC (Mesabi Nugget), and United States SteelUSS Corporation’s expansion at its Keewatin Taconite facility. Additionally,taconite facility, Essar Steel Limited Minnesota (Essar), continuesand Magnetation. We cannot predict the outcome of these projects, but if these projects are constructed, Minnesota Power could serve up to work with local agencies on infrastructure development for its taconite mine, direct reduction iron-making facility, and steel mill within the Nashwauk, MN municipal utility service boundary.approximately 600 MW of new retail or wholesale load.


ALLETE 2012 Form 10-K
42


Outlook (Continued)
Industrial Customers (Continued)

PolyMet. Minnesota Power has executed a long-term contract with PolyMet, a new industrial customer planning to start a copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. PolyMet is currently in the environmental permitting process, and the public comment periodbegan work on itsa Supplemental Draft Environmental Impact Statement (DEIS) closed on February 3,(SDEIS) in 2010. Assuming that the DEIS is judged to be complete, the Minnesota Department of Natural ResourcesThe SDEIS will address environmental issues, including those dealing with a land exchange between PolyMet and the U.S. Army CorpsForest Service (USFS), which is critical to the mine site development. The EPA and the USFS joined as lead agencies in the SDEIS process. Release of Engineers may issuethe SDEIS is expected in the first half of 2013, to be followed by a Statementpublic review and comment period. Assuming successful completion of Adequacy by mid-year 2010, withthe SDEIS process and subsequent issuance of environmental permitting to follow. Should these events occur, operations could begin in late 2011 andpermits, Minnesota Power willcould begin to supply approximatelybetween 45 MW and 70 MW of powerload as early as 2015 through a 10-year power supply contract lasting at least through 2018.that would begin upon start-up of the mining operations.

Mesabi Nugget.The construction of the initial Mesabi Nugget facility is essentially complete and the first production occurredbegan in January 2010. Steel Dynamics, Inc., the principal owner of Mesabi Nugget has indicated that commissioning and production ramp-up activities will occur throughout 2010, with full production levels expectedcontinues to be reached during the year. Mesabi Nugget is currently pursuingpursue permits for taconite mining activities on lands formerly mined by Erie Mining Company and LTV Steel Mining Company near Hoyt Lakes, MN. AssumingMinnesota. Upon receipt of environmental permits to mine, by the end of 2010, mining activities could begin in 2011, which would allow Mesabi Nugget tocould mine and self-supply its own taconite concentrates andiron ore concentrate about a year later, which would result in increased electrical loads. Minnesota Power has a 15loads above our current 20 MW long-term power supply contract with Mesabi Nugget lastingwhich lasts at least through 2017. In the meantime, Mesabi Nugget will receive iron ore concentrate from a new Mining Resources, LLC facility located near Chisholm, Minnesota.

Keewatin Taconite.In February 2008, United States SteelUSS Corporation announced its intent to restart a pellet line at its Keewatin Taconite (Keetac) processing facility (Keetac). Thisfacility. If restarted, this pellet line, which has been idledidle since 1980, could be restarted and updated as part of a $300 million investment, bringing aboutbring 3.6 million tons of additional pellet making capability to northeastern Minnesota and could result in over 60 MW of additional load for Minnesota Power. Project permits have been received and should the project be approved by USS Corporation’s Board of Directors, construction activities could commence immediately thereafter with production expected to begin approximately two to three years later.

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

Magnetation. In December 2011, the MPUC approved Minnesota Power’s electric service agreement with Magnetation. Magnetation, a company in northeastern Minnesota, produces iron ore concentrate from low-grade natural ore tailing basins, already mined stockpiles and newly mined iron formations. Magnetation’s facility near Taconite, Minnesota is fully operational with equipment additions currently underway at the facility.

In October 2011, Magnetation and integrated steelmaker, AK Steel Corporation (AK Steel), announced a joint venture, Magnetation LLC, under which construction activities for two new facilities, near Calumet and Coleraine, Minnesota, are expected to commence in 2013. The public comment periodCalumet facility could come on line in late 2014 and the Coleraine facility shortly thereafter to supply iron ore concentrate to Magnetation’s new pellet plant that is under construction in Reynolds, Indiana. Construction of these new iron ore concentrate facilities could result in approximately 20 MW of additional load for a Draft Environmental Impact Statement for the Keetac facility ended on January 26, 2010.Minnesota Power.


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Outlook (Continued)

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

Major wind investments in North Dakota. Including the 210 MW of wind generation commissioned in December 2012, our total Bison Wind Energy Center now has 292 MW of nameplate capacity (see Renewable Energy).
Planned installation of approximately $350 to $400 million in emissions control technology at our Boswell Unit 4 to further reduce emissions of SO2, particulates and mercury. (See Item 1. Business – Regulated Operations – Regulatory Matters – Boswell Mercury Emissions Reduction Plan.)
Planning for the proposed Great Northern Transmission Line to deliver hydroelectric power from northern Manitoba by 2020. (See Item 1. Business – Regulated Operations – Transmission and Distribution.)
The conversion of our Laskin Energy Center from coal to cleaner-burning natural gas in 2015.
Retiring Taconite Harbor Unit 3, one of three coal units at our Taconite Harbor Energy Center, in 2015.

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

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

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and wholesale energy sales in Minnesota comebe from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. Minnesota Power has identified a plan to meet the renewable goals set by Minnesota and has included this in the most recent filing of the IRP with the MPUC. The law allows the MPUC to modify or delay meeting a standard obligationmilestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard,milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developingmet the 2012 milestone and makinghas developed a plan to meet the future renewable supply additions as part ofmilestones which is included in its generation planning strategy prior to2010 Integrated Resource Plan. The MPUC approved the enactment of this lawIntegrated Resource Plan in its final order issued in May 2011. Minnesota Power will submit its next Integrated Resource Plan on March 1, 2013, and this activity continues.include an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025.

We areMinnesota Power has taken several steps in executing ourits renewable energy strategy. In 2006 and 2007,strategy through key renewable projects that will ensure we entered intomeet the identified state mandate at the lowest cost for customers. We have executed two long-term power purchase agreementsPPAs with an affiliate of NextEra Energy, Inc., for a total of 98 MWs of wind energy constructed in North Dakota (Oliver Wind I and II). Other steps include Taconite Ridge, Wind I, our $50 million, 25-MW25 MW wind facility located in northeastern Minnesota, became operationaland our 292 MW Bison Wind Energy Center in 2008.North Dakota. Approximately 20 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2013.

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

On July 7, 2009,Our Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity. The 82 MW Bison 1 wind facility was completed in two phases; the first phase in 2010 and the second phase in January 2012. The 105 MW Bison 2 and 105 MW Bison 3 wind facilities were completed in December 2012. Total project costs for our Bison Wind Energy Center were $473.3 million through December 31, 2012. In September 2011, and November 2011, the MPUC approved ourMinnesota Power’s petition seeking current cost recovery offor investments and expenditures related to Bison I2 and Bison 3, respectively.


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Outlook (Continued)
Renewable Energy (Continued)

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated transmission upgrades.with our Bison Wind Energy Center through that period. We anticipate filing a cost recovery petition with the MPUC in the first quarterhalf of 20102013 to establishupdate customer billing rates for the approved cost recovery. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will fulfill the 2025 renewable energy supply requirement for our retail load. Bison I, located near Center, North Dakota, will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 MWssubsequent investments and will be phased into service in late 2010 andexpenditures since 2011.

Our current capital expenditures plan includes additional wind energy investments in North Dakota in 2016 and 2017 to meet Minnesota’s 25 percent renewable energy mandate by 2025 (see Liquidity and Capital Resources – Capital Requirements). On September 29, 2009,January 2, 2013, The American Taxpayer Relief Act of 2012 extended the NDPSC authorized siteavailability of the production tax credit for renewable energy facilities that commence construction for Bison I. On October 2, 2009, Minnesota Power filedby December 31, 2013. As a route permit application withresult, we are evaluating the NDPSC for a 22 mile, 230 kV Bison I transmission lineacceleration of these investments so that will connect Bison I to the DC transmission line at the Square Butte Substationconstruction would commence in Center, North Dakota. An order is expected in the first quarter of 2010.2013.

Manitoba Hydro. Minnesota Power has a long-term powerPPA with Manitoba Hydro for the purchase of 50 MW of capacity and energy associated with that capacity, which expires in April 2015. In addition, Minnesota Power signed a separate PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only transaction primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement with Manitoba Hydro, expiringMinnesota Power will be purchasing at least one million MWh of energy over the contract term.

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2015. (See2020. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for a change in a governmental inflationary index and a natural gas index, as well as market prices. The agreement is subject to construction of additional transmission capacity between Manitoba and Minnesota’s Iron Range. In addition, we are exploring other regional grid enhancements that would allow for the movement of more renewable energy in the Upper Midwest while at the same time strengthening electric reliability in the region.

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

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

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

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

The policy does not cover damage to land and earthen structures, which includes the majority of the damage to the forebay canal at the Thomson facility. Minnesota Power is currently negotiating definitive agreementscontinuing to assess options for rebuilding the forebay canal and is in close contact with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs. Until that assessment is complete, we are not able to fully estimate the capital cost and schedule for rebuilding the forebay canal and resuming generation; however, based on two additional purchased power transactions with Manitoba Hydro: an initial purchasea preliminary evaluation, the capital rebuild cost is estimated to be approximately $15 million to $25 million. Any expenditures to rebuild the forebay canal would be capitalized. Minnesota Power is working towards returning to partial generation from the Thomson Energy Center by the end of surplus energy over2013 and to full generation by the next ten years, followed by an anticipated long-term purchaseend of a 250-MW capacity and energy agreement beginning in approximately 2020. The 250-MW long-term purchase will require construction of hydroelectric facilities in Manitoba and major new transmission facilities between Canada and the United States. Transmission studies and definitive agreement negotiations are ongoing. Both purchases require MPUC approval.2014.

Hibbard Renewable Energy Center. On September 30, 2009, we purchased boilers and associated systems previously owned by the City of Duluth. This facility was initially built in the late 1930s as a coal burning power plant, and retrofitted to burn wood-based biomass fuel as well as coal. Over time, Minnesota Power intends to invest approximately $20 million to upgrade the boilers and associated systems to increase biomass energy generation at the plant. Hibbard’s current generating capacity is approximately 50 MWs. This purchase will help us achieve Minnesota’s mandate of providing 25 percent of our retail energy from renewable resources by 2025.

Integrated Resource Plan. On October 5, 2009, Minnesota Power filed with the MPUC its 2010 Integrated Resource Plan, a comprehensive estimate of future capacity needs within Minnesota Power’s service territory. Minnesota Power does not anticipate the need for new base load generation within the Minnesota Power service territory over the next 15 years, and plans to meet estimated future customer demand while achieving:

·Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios;
·Reductions in the emission of GHGs (primarily carbon dioxide); and
·Compliance with mandated renewable energy standards.

To achieve these objectives over the coming years, we plan to reshape our generation portfolio by adding 300 to 500 megawatts of renewable energy to our generation mix, and exploring options to incorporate peaking or intermediate resources. Our 76 MW Bison I Wind Project in North Dakota is expected to be in service in late 2010 and 2011.

We project average annual long-term growth of approximately one percent in electric usage over the next 15 years. We will also focus on conservation and demand side management to meet the energy savings goals established in Minnesota legislation.

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Outlook (Continued)

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

·Expand our renewable energy supply.
·Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies.
·Provide energy conservation initiatives with our customers and demand side efforts.
·Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.
·Achieve overall carbon emission reductions.
Hydro Operations (Continued)

The scientific community generally accepts that emissionsThomson facility represents approximately 5 percent of GHGs are linkedtotal company electric generation capability. Additional purchased power expense required due to global climate change. Climate change creates physical and financial risk. These physical risks could include, but arethe Thomson facility outage will be recovered through our fuel adjustment clause. We do not limited to, increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations.

Federal Legislation. We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals at the Federal level to “cap” the amount of GHG emissions have been made. On June 26, 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. H.R. 2454 is a comprehensive energy bill that also includes a cap-and-trade program. H.R. 2454 allocates a significant number of emission allowances to the electric utility sector to mitigate cost impacts on consumers. Based on the emission allowance allocations, we expect we would have to purchase additional allowances. We’re unable to predict at this time the value of these allowances.

On September 30, 2009, the Senate introduced S. 1733, the Senate version of H.R. 2454. This legislation proposes a more stringent, near-term greenhouse emissions reduction target in 2020 of 20 percent below 2005 levels, as compared to the 17 percent reduction proposed by H.R. 2454. 

Congress may consider proposals other than cap-and-trade programs to address GHG emissions. We are unable to predict the outcome of H.R. 2454, S. 1733, or other efforts that Congress may make with respect to GHG emissions, and the impact that any GHG emission regulations may have on the Company. We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs couldevent will have a material impact on our financial results.position or results of operations.

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

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

Greenhouse Gas Emissions Reporting. In May 2008, Minnesota passed legislation that required the MPCA to track emissions and make interim emissions reduction recommendations towards meeting the State’s goal of reducing GHG by 80 percent by 2050. GHG emissions from 2008 were reported in 2009.

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

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

EPA Greenhouse Gas Reporting Rule. On September 22, 2009, the EPA issued the final rule mandating that certain GHG emission sources, including electric generating units, are required to report emission levels. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule was effective January 1, 2010, and all GHG emissions must be reported on an annual basis by March 31 of the following year. Currently, we have the equipment and data tools necessary to report our 2010 emissions to comply with this rule.

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Outlook (Continued)
Climate Change (Continued)

Title V Greenhouse Gas Tailoring Rule. On October 27, 2009, the EPA issued the proposed Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring rule. This proposed regulation addresses the six primary greenhouse gases and new thresholds for when permits will be required for new facilities and existing facilities which undergo major modifications. The rule would require large industrial facilities, including power plants, to obtain construction and operating permits that demonstrate Best Available Control Technologies (BACT) are being used at the facility to minimize GHG emissions. The EPA is expected to propose BACT standards for GHG emissions from stationary sources.

For our existing facilities, the proposed rule does not require amending our existing Title V operating permits to include BACT for GHGs. However, modifying or installing units with GHG emissions that trigger the PSD permitting requirements could require amending operating permits to incorporate BACT to control GHG emissions.

EPA Endangerment Findings. On December 15, 2009, the EPA published its findings that the emissions of six GHG, including CO2, methane, and nitrous oxide, endanger human health or welfare. This finding may result in regulations that establish motor vehicle GHG emissions standards in 2010. There is also a possibility that the endangerment finding will enable expansion of the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. with the United States District Court Circuit Court of Appeals on December 23, 2009.

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its steam electric stations. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use, or trucked to state permitted landfills. Minnesota Power continues to monitor state and federal legislative and regulatory activities that may affect its ash management practices. The EPA is expected to propose new regulations in February 2010 pertaining to the management of coal ash by electric utilities. It is unknown how potential coal ash management rule changes will affect Minnesota Power’s facilities. On March 9, 2009, the EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received an additional EPA information request pertaining to Boswell. Minnesota Power responded to both these information requests. On August 19, 2009, the Minnesota DNR visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findings or concerns from the DNR staff during the inspections.

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

Minnesota Power intends to invest in two lines, a 250-mile 345 kV line between Fargo, North Dakota and Monticello, Minnesota, and a 70-mile, 230 kV line between Bemidji and Grand Rapids, Minnesota. The MPUC issued the Certificate of Need for the 230 kV line in July 2009. The MPUC decision on the Route Permit application is expected in 2010. Our total investment in these lines is expected to be approximately $100 million. We intend to seek recovery of these costs in a filing with the MPUC in the first quarter of 2010, under a Minnesota Power transmission cost recovery tariff rider authorized by Minnesota legislation. Construction of the lines is targeted to begin in late 2010 and may take up to four years.

Emission Reduction Plans. We have made investments in pollution control equipment at our Boswell Unit 3 generating unit that reduces particulates, SO2, NOx and mercury emissions to meet future federal and state requirements. This equipment was placed in service in November 2009. During the construction phase, the MPUC authorized a cash return on construction work in progress in lieu of AFUDC, and this amount was collected through a current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to base rates.

The environmental regulatory requirements for Taconite Harbor Unit 3 are pending approval of the Minnesota Regional Haze implementation by the EPA. We are evaluating compliance requirements for this Unit. Environmental retrofits at Laskin and Taconite Harbor Units 1 and 2 have been completed and are in-service.

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

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Outlook (Continued)

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

Power Sales Agreement. On October 29, 2009, Minnesota Power entered into an agreement to sell Basin 100 MWs of capacity and energy for the next ten years. The transaction is scheduled to begin in May 2010, following the expiration of two wholesale power sales contracts on April 30, 2010. The Basin agreement contains a fixed monthly schedule of capacity charges with an annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro-rata share of increased costs related to emissions that may occur during the last five years of the contract. (See Item 3. Power Marketing.)

Investment in ATC. At December 31, 2009, our equity investment was $88.4 million, representing an approximate 8 percent ownership interest. ATC provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of establishing the independent operation and ownership of, and investment in, transmission facilities. ATC rates are based on a 12.2 percent return on common equity dedicated to utility plant. ATC has identified $2.5 billion in future projects needed over the next 10 years to improve the adequacy and reliability of the electric transmission system. This investment is expected to be funded through a combination of internally generated cash, debt, and investor contributions. As additional opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro-rata ownership interest in ATC. On January 29, 2010, we invested an additional $1.2 million in ATC. In total, we expect to invest approximately $2 million throughout 2010. (See Note 6. Investment in ATC.)

Investments and Other

BNI Coal. In 2009,2012, BNI Coal sold approximately 4.24.4 million tons of coal (4.5(4.3 million tons in 2008)2011) and anticipates 2013 sales will be similar sales in 2010.to 2012. BNI continues to operate under a cost plus fixed fee agreement extending through 2026.

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

Our two major development projects are Town Center and Palm Coast Park. Another major project, Ormond Crossings, a third major project that is currently in the planning stage, received land use approvals in December 2006. However, due to a change in the Florida law that became effective in July 2009, those approvals are being revised. It is anticipated that thepermitting stage. The City of Ormond Beach, FL will approveFlorida, approved a new Development Agreementdevelopment agreement for Ormond Crossings in the first quarter of 2010. The new agreementwhich will facilitate development of the project as currently planned. Separately, the Lake Swamp wetland mitigation bank was permitted on land that was previously part of Ormond Crossings.

Summary of Development Projects TotalResidentialNon-residential
Summary of Development Projects (100% Owned)   Residential Non-residential
Land Available-for-SaleOwnership
Acres (a)
Units (b)
Sq. Ft. (b, c)
 
Acres (a)
 
Units (b)
 
Sq. Ft. (b,c)
Current Development Projects          
Town Center80%8542,2642,238,400 965
 2,485
 2,246,200
Palm Coast Park100%3,1433,1543,555,000 3,888
 3,554
 3,096,800
Total Current Development Projects 3,9975,4185,793,400 4,853
 6,039
 5,343,000
Proposed Development Project    
      
Planned Development Project      
Ormond Crossings100%2,924(d)(d) 2,914
 2,950
 3,215,000
Other          
Lake Swamp Wetland Mitigation Project100%3,034(e)(e) 3,044
 (d)
 (d)
Total of Development Projects 9,9555,4185,793,400 10,811
 8,989
 8,558,000

(a)Acreage amounts are approximate and shown on a gross basis, including wetlands and non-controlling interest.wetlands.
(b)EstimatedUnits and includes non-controlling interest.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)A development order that was approved by the City of Ormond Beach is being replaced by a development agreement to facilitate development of Ormond Crossings as currently planned. At build-out, we expect the project to include 2,950 residential units, 4.87 million square feet of various types of non-residential space and public facilities.
(e)The Lake Swamp wetland mitigation bank is a permitted, regionally significant wetlands mitigation bank that was permitted by the St. Johns River Water Management District in 2008 and by the U.S. Army Corps of Engineers in December 2009.bank. Wetland mitigation credits will be used at Ormond Crossings and will also be available for saleare available-for-sale to developers of other projects that are located in the bank’s service area.

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

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


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Outlook (Continued)
Investments and Other (Continued)

Other Land Available-for-Sale (a)
TotalMixed UseResidentialNon-residentialAgricultural
Acres (b)
     
Other Land1,277394113267503

(a)Other land includes land located in Palm Coast, Lehigh, and Cape Coral, Florida.
(b)Acreage amounts are approximate and shown on a gross basis, including wetlands and non-controlling interest.

Long-term finance receivables as of December 31, 2009, were $12.9 million, which included $7.8 million due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June 2009. The estimated fair value of the collateral relating to these receivables was greater than the $7.8 million amount due at December 31, 2009, and no impairment was recorded on these receivables; however, $0.3 million of impairments was recorded on other receivables.

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. In many cases, contract purchasers incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they have substantially more at risk than the deposit.

ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise. However, if weak market conditions continue for an extended period of time, the impact on our future operations would be the continuation of little to no sales while still incurring operating expenses such as community development district assessments and property taxes. This could result in annual net losses for ALLETE Properties similar to 2009.

Income TaxesTaxes.. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2010.2012. On an ongoing basis, ALLETE has certain tax credits and other tax adjustments that will reduce the statutory rate to the expected effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, wind productionrenewable tax credits, AFUDC-Equity, domestic manufacturer’s deduction, depletion, Medicare prescription reimbursement, as well as other items. The annual effective rate can also be impacted by such items as changes in income from operations before non-controlling interest and income taxes, state and federal tax law changes that become effective during the year, business combinations and configuration changes, tax planning initiatives and resolution of prior years’ tax matters. WeDue primarily to increased renewable tax credits as a result of additional wind generation, we expect our effective tax rate to be approximately 3520 percent for 2010.2013. We also expect that our effective tax rate will be lower than the statutory rate over the next ten years due to production tax credits attributable to our wind generation.


Liquidity and Capital Resources

Liquidity Position.ALLETE is well-positioned to meet the Company’s immediate cash flowliquidity needs. At As of December 31, 2009,2012, we have ahad cash balanceand cash equivalents of approximately $26$80.8 million $87.8, $406.4 million of unused in available consolidated lines of credit ($157.0 million net of $69.2 million drawn down as of December 31, 2009), and a debt-to-capital ratio of 4346 percent. In the first quarter 2010, we expect to use proceeds from the sale of $80 million First Mortgage Bonds to repay the amount drawn down on the line of credit.

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

Year Ended December 312009%2008%2007%
Millions      
Common Equity$929.557$827.157$742.663
Non-Controlling Interest9.59.819.31
Long-Term Debt (Including Current Maturities)701.043598.742422.736
Short-Term Debt1.96.0
 $1,641.9100$1,441.6100$1,174.6100
Year Ended December 312012
%2011
%2010
%
Millions      
Common Equity
$1,201.0
54
$1,079.3
56
$976.0
55
Non-Controlling Interest

9.0
1
Long-Term Debt (Including Current Maturities)1,018.1
46863.3
44785.0
44
Short-Term Debt
1.1
1.0
 
$2,219.1
100
$1,943.7
100
$1,771.0
100



ALLETE 2009 Form 10-K
42


Liquidity and Capital Resources (Continued)

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

Year Ended December 31200920082007
Millions   
Cash and Cash Equivalents at Beginning of Period$102.0$23.3$44.8
Cash Flows from (used for)   
Operating Activities137.4153.6124.2
Investing Activities(320.0)(276.1)(154.1)
Financing Activities106.3201.28.4
    Change in Cash and Cash Equivalents(76.3)78.7(21.5)
Cash and Cash Equivalents at End of Period$25.7$102.0$23.3
Year Ended December 312012
2011
2010
Millions   
Cash and Cash Equivalents at Beginning of Period
$101.1

$44.9

$25.7
Cash Flows from (for)   
Operating Activities239.6
241.7
228.7
Investing Activities(420.1)(240.9)(250.9)
Financing Activities160.2
55.4
41.4
Change in Cash and Cash Equivalents(20.3)56.2
19.2
Cash and Cash Equivalents at End of Period
$80.8

$101.1

$44.9

Operating Activities. Cash from operating activities was $137.4$239.6 million for 2009 ($153.62012 ($241.7 million for 2008; $124.22011; $228.7 million for 2007)2010). Cash from operating activities was similar to 2011 as lower cash contributions to pension and other postretirement benefit plans ($8.8 million in 2009 primarily due to lower net income, an increase2012 and $24.7 million in accounts receivable, and higher deferred regulatory assets, partially2011) were offset by higher deferred taxcost recovery rider receivables in 2012 and depreciation expense. Accounts receivable increased due a receivable for 2009 income tax refunds primarily resulting from substantial income tax deductions under the bonus depreciation provision of the American Recovery and Reinvestment Act of 2009 (the Act). Deferred regulatory assets increased due to the collection of certain current cost recovery rider revenue attributable to 2009 being deferred into a later year. Deferred tax expense increased also due to the bonus depreciation provisions of the Act, and depreciation expense increasedreceived in conjunction with the increase in property, plant and equipment.2011.

Cash from operating activities was higher in 20082011 than 20072010 primarily due to an increasehigher 2011 net income primarily from our Regulated Operations segment, decreased cash contributions to our pension and other postretirement employee benefit plans ($24.7 million in deferred income tax expense2011 and decreased working capital requirements, which was$39.3 million in 2010), and increased customer deposits, partially offset by lower net incomea decrease in accounts payable and higher contributions to defined benefit pension and postretirement health plans (included in Other Liabilities on the Consolidated Statement of Cash Flows). Working capital requirements decreased mainly due to lower uncollected purchased power costs (included in Prepayments and Other on the Consolidated Statement of Cash Flows). Deferred income tax expense increased due to the Economic Stimulus Act of 2008, and contributions to defined benefit pension and postretirement health plans increased $15.6 million during 2008.inventory balances.

Investing Activities. Cash used for investing activities was $320.0$420.1 million for 2009 ($276.12012 ($240.9 million for 2008; $154.12011; $250.9 million for 2007)2010). CashThe increase in cash used for investing activities was higher than 2008 reflecting increased capital additions to property, plant, and equipment. Capital additions to property, plant, and equipment increasedprimarily due to the purchase of an existing 250 kV DC transmission line for $69.7 million offset by a decreasehigher capital expenditures in other capital additions because of the completion of some major capital projects in 20082012 primarily related to our Bison Wind Energy Center.


ALLETE 2012 Form 10-K
47


Liquidity and 2009. In addition, 2008 included higher net sales of short-term investments and proceeds from the sale of assets (retail shopping center) in Winter Haven, Florida.Capital Resources (Continued)
Investing Activities (Continued)

Cash used for investing activities in 2011 was higher in 2008lower than 2007 reflecting increased capital additions to property, plant, and equipment which were partially offset by the proceeds from the sale of assets (retail shopping center) in Winter Haven, Florida. Capital additions to property, plant, and equipment increased2010 primarily due to construction activitylower capital expenditures in 2011 and the redemption of ARS for environmental retrofit projects, AREA Plan projects, Taconite Ridge, and additional investments$6.7 million in ATC.January 2011.

Financing Activities. Cash from financing activities was $106.3$160.2 million for 2009 ($201.22012 ($55.4 million for 2008; $8.42011; $41.4 million for 2007)2010). CashThe increase in cash from financing activities in 2012 was lower in 2009 than 2008primarily due to lessincreased proceeds from long-term debt and common stock issuance. During 2009, $111.4 million of debt was issued, while in 2008 $198.7 million of debt was issued. During 2009, proceeds from common stock issuances totaled $65.2 million, while in 2008, proceeds from common stock issuances totaled $71.1 million. Lower debt and common stock issuance in 2009 was a result of issuing capital in 2008 ahead of the need for this capital.issuances.

Cash from financing activities was higher in 2008 than 20072011 compared to 2010 primarily due to increased proceeds from the issuanceissuances of debt for $198.7 million. In addition, common stock, was issued forpartially offset by lower net proceeds of $71.1 million. Financing activities increased to support our capital expenditure program.long-term debt in 2011.

Working Capital.Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit or the sale of securities or commercial paper. We haveAs of December 31, 2012, we had available consolidated bank lines of credit aggregating $87.8$406.4 million the majority, of which expire$150.0 million expires in January 2012.2014, and $250.0 million expires in June 2015. In addition, we have 0.40.9 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 3.34.5 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.


ALLETE 2009 Form 10-K
43


Liquidity and Capital Resources (Continued)

Securities. In January 2009, we issued $42.0 million in principal amount of unregistered First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019, and carry a coupon rate of 8.17 percent. We have the option to prepay all or a portion of the Bonds at our discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for this type of transaction. We are using the proceeds from the sale of the Bonds to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

In December 2009, we agreed to sell $80.0 million in principal amount of First Mortgage Bonds (Bonds) in the private placement market in three series as follows:

Issue Date
(on or about)
MaturityPrincipal AmountCoupon
February 17, 2010April 15, 2021$15 Million4.85%
February 17, 2010April 15, 2025$30 Million5.10%
February 17, 2010April 15, 2040$35 Million6.00%

We expect to use the proceeds from the February 2010 sale of Bonds to pay down the syndicated revolving credit facility, to fund utility capital investments or for general corporate purposes.

We entered into a Distribution Agreementdistribution agreement with KCCI, Inc., originating in February 2008, and subsequentlyas amended in February 2009,most recently on August 3, 2012, with respect to the issuance and sale of up to an aggregate of 6.69.6 million shares of our common stock, without par value.value, of which 4.5 million remain available for issuance. For the quarter ended December 31, 2012, 0.4 million shares of common stock were issued under this agreement, resulting in net proceeds of $17.9 million (for the quarter ended December 31, 2011, no shares were issued). For the year ended December 31, 2012, 1.3 million shares of common stock were issued under this agreement, resulting in net proceeds of $53.1 million (0.4 million shares for net proceeds of $16.0 million for the year ended December 31, 2011). The shares issued in 2012 were, and the remaining shares may be, offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-147965. During 2009, 1.7 million shares of common stock were issued under this agreement resulting in net proceeds of $51.9 million. In 2008, 1.6 million shares were issued for net proceeds of $60.8 million.Nos. 333-170289.

In March 2009, we contributed 463,000 shares of ALLETE common stock, with an aggregate value of $12.0 million, to our pension plan. On May 19, 2009, we registeredFor the 463,000 shares of ALLETE common stock with the SEC pursuant to Registration Statement No. 333-147965.

In 2009,year ended December 31, 2012, we issued 0.4a 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 $13.3 million.$23.9 million. These shares of common stock were registered under the following Registration Statement Nos. 333-150681,333-166515, 333-105225, 333-183051 and 333-124455,333-162890, respectively.

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

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition,See Note 10. Short-Term and Long-Term Debt for information regarding our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. The most restrictive covenant requires ALLETE to maintain a ratio of its Funded Debt to Total Capital (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00 measured quarterly. As of December 31, 2009, our ratio was approximately 0.41 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of December 31, 2009, ALLETE was in compliance with its financial covenants.

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


ALLETE 2009 Form 10-K
44


Liquidity and Capital Resources (Continued)

Contractual Obligations and Commercial Commitments. Minnesota PowerALLETE has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. The followingFollowing is a summarized table of contractual obligations and other commercial commitments at December 31, 2009.2012.


 Payments Due by Period
Contractual Obligations Less than1 to 34 to 5After
As of December 31, 2009Total1 YearYearsYears5 Years
Millions     
Long-Term Debt (a)
$1,172.1$41.5$196.6$98.2$835.8
Pension and Other Postretirement Benefit Plans194.136.6105.452.1
Operating Lease Obligations89.18.826.415.838.1
Uncertain Tax Positions (b)
Unconditional Purchase Obligations394.0114.1102.730.4146.8
 $1,849.3$201.0$431.1$196.5$1,020.7
ALLETE 2012 Form 10-K
48


 Payments Due by Period
Contractual Obligations Less than1 to 34 to 5After
As of December 31, 2012Total1 YearYearsYears5 Years
Millions     
Long-Term Debt
$1,613.0

$129.8

$258.2

$127.6

$1,097.4
Pension202.8
31.2
99.8
71.8

Other Postretirement Benefit Plans53.9
7.6
26.6
19.7

Operating Lease Obligations87.4
11.5
32.4
15.7
27.8
Uncertain Tax Positions (a)





Unconditional Purchase Obligations (b)
576.7
125.3
179.3
82.8
189.3
 
$2,533.8

$305.4

$596.3

$317.6

$1,314.5
(a)Includes interest and assumes variable interest rates in effect at December 31, 2009, remains constant through remaining term.
(b)Excludes $9.5$2.7 million of noncurrentnon-current unrecognized tax benefits due to uncertainty regarding the timing of future cash payments related to the guidance in accounting for uncertain tax positions.
(b)Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only. Also excludes the agreement with Manitoba Hydro expiring in 2035, as our obligation under this contract is subject to the construction of a hydro generation facility by Manitoba Hydro and additional transmission capacity. Also, excludes Oliver I and II, as we only pay for energy as it is delivered to us. (See Item 1. Business – Regulated Operations – Power Supply.)

Long-Term Debt.Our long-term debt obligations, including long-term debt due within one year, represent the principal amount of bonds, notes and loans which are recorded on our consolidated balance sheet,Consolidated Balance Sheet, plus interest. The table above assumes that the interest raterates in effect at December 31, 2009, remains2012, remain constant through the remaining term. (See Note 10. Short-Term and Long-Term Debt.)

Pension and Other Postretirement Benefit Plans. The funded status of the defined Our pension and other postretirement benefit plan obligations refers to the difference between plan assets and estimated obligations under the plans. The funded status may change over time due torepresent our current estimate of employer contributions. Pension contributions will be dependent on several factors including contribution levels, assumedrealized asset performance, future discount ratesrate and actualother actuarial assumptions, IRS and assumed rates of return on plan assets.

Management considers various factors when making funding decisions such asother regulatory requirements, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the pension plans. Estimated defined benefit pension contributions for years 2010 through 2014 are expected to be up to $25 million per year, and are based on estimates and assumptions that are subject to change. Funding for the other postretirement benefit plans is impacted by realized asset performance, future discount rate and other actuarial assumptions, and utility regulatory requirements. Estimated postretirement healthThese amounts are estimates and life contributions for years 2010 through 2014 are approximately $11 million per year, and arewill change based on estimatesactual market performance, changes in interest rates and assumptions that are subject to change.any changes in governmental regulations. (See Note 15. Pension and Other Postretirement Benefit Plans.)

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

Under our power purchase agreementMinnesota 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-MW455 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. This debt service may be reduced if the contingent power sales agreement with Minnkota Power goes into effect in 2013. For further information on Square Butte see(See Note 11. Commitments, Guarantees and Contingencies.)

We have two wind power purchase agreementsa PPA with an affiliateManitoba Hydro that expires in April 2015. Under this agreement, Minnesota Power is purchasing 50 MW of NextEra Energy to purchase the output from two wind facilities, Oliver Wind I and Oliver Wind II located near Center, North Dakota. We began purchasing the output from Oliver Wind I, a 50-MW facility, in December 2006capacity and the output from Oliver Wind II,energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a 48-MW facility in November 2007. Eachgovernmental inflationary index.

On December 12, 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement is for 25 yearsMinnesota Power will purchase 50 MW of capacity and provides for the purchase of all output fromenergy associated with that capacity over the facilities. There are noterm June 1, 2016 through May 31, 2020. The agreement includes a fixed capacity charges,charge and we only pay for energy as it is delivered to us.pricing that escalates at a fixed rate annually over the term.


ALLETE 2012 Form 10-K
49


Liquidity and Capital Resources (Continued)

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

ALLETE 2009 Form 10-K
45


Liquidity and Capital Resources (Continued)
Credit Ratings (Continued)

Credit RatingsStandard & Poor’sMoody’s
Issuer Credit RatingBBB+Baa1
Commercial PaperA-2P-2
Senior Secured  
First Mortgage Bonds (a)
A–A2
Unsecured Debt
Collier County Industrial Development Revenue Bonds – Fixed RateBBB

(a)Includes collateralized pollution control bonds.

Common Stock Dividends. ALLETE is committed to providing an attractive, securea competitive dividend to its shareholders while at the same time funding its growth strategy.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 2009,2012, we paid out 9371 percent (61(67 percent in 2008; 532011; 80 percent in 2007)2010) of our per share earnings in dividends. On January 21, 2010,23, 2013, our Board of Directors declared a dividend of $0.44$0.475 per share, unchanged from 2009, which is payable on March 1, 2010,2013, to shareholders of record at the close of business on February 15, 2010.2013.

Capital Requirements

ALLETE’s projected capital expenditures for the years 20102013 through 20142017 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, or capital market conditions.conditions or executions of new business strategies.

Capital Expenditures
20102011201220132014Total
Regulated Utility Operations      
 Base and Other$156$82$81$82$89$490
 
Current Cost Recovery (a)
      
  Environmental22
  Renewable8166147
  Transmission521274213108
  Generation
 Total Current Cost Recovery8887274213257
Regulated Utility Capital Expenditures244169108124102747
Other 618248864
Total Capital Expenditures$250$187$132$132$110$811

Capital Expenditures2013
2014
2015
2016
2017
Total
Millions      
Regulated Utility Operations      
 Base and Other
$171

$168

$147

$155

$138

$779
 
Cost Recovery (a)
      
 
Environmental (b)
93
133
87
3

316
 
Renewable (c)
2
8

68
158
236
 
Transmission (d)
30
28
11
3
40
112
 Total Cost Recovery125
169
98
74
198
664
Regulated Utility Capital Expenditures296
337
245
229
336
1,443
Other 14
25
11
9
3
62
Total Capital Expenditures
$310

$362

$256

$238

$339

$1,505
(a)Estimated current capital expenditures recoverable outside of a rate case.
(b)Environmental capital expenditures primarily relate to compliance with the MATS rule for Boswell Unit 4. (See Note 11. Commitments, Guarantees and Contingencies.) Boswell Unit 4 capital expenditures included above reflect Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4. (See Note 4. Jointly-Owned Facilities.)
(c)Includes a total of $226 million in 2016 and 2017 related to additional wind generation of 100 MW. On January 2, 2013, the American Taxpayer Relief Act of 2012 extended the availability of the production tax credit for renewable energy facilities that commence construction by December 31, 2013. As a result, we are evaluating the acceleration of these investments so that construction would commence in 2013.
(d)Transmission capital expenditures related to CapX2020 are estimated at approximately $50 million over the 2013 to 2015 period. Capital expenditures of $38 million are included related to commencement of construction of the Great Northern Transmission Line. (See Item 1. Business – Regulated Operations – Transmission and Distribution.)


ALLETE 2012 Form 10-K
50


Liquidity and Capital Resources (Continued)
Capital Requirements (Continued)

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

Environmental and Other Matters

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

Market Risk

Securities Investments

Available-for-Sale Securities. At December 31, 2009,2012, our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities.benefits. (See Note 7. Investments.)

Interest Rate Risk. We are exposed to risks resulting from changes in interest rates as a result of our issuance of variable rate debt. We manage our interest rate risk by varying the issuance and maturity dates of our fixed rate debt, limiting the amount of variable rate debt, and continually monitoring the effects of market changes in interest rates. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. The table below presents the long-term debt obligations and the corresponding weighted average interest rate at December 31, 2009.2012

ALLETE 2009 Form 10-K
46


Market Risk (Continued)
Interest Rate Risk (Continued).

 Expected Maturity Date
Interest Rate Sensitive       Fair
Financial Instruments20102011201220132014ThereafterTotalValue
Dollars in Millions        
Long-Term Debt        
Fixed Rate (a)
$1.6$1.6$1.6$71.1$19.6$528.1$623.6$657.3
Average Interest Rate – %5.95.95.95.26.95.95.8 
         
Variable Rate$3.6$12.3$1.7$2.8$57.0$77.4$77.5
Average Interest Rate – % (b)
0.43.61.90.30.30.9 

 Expected Maturity Date
Interest Rate Sensitive       Fair
Financial Instruments2013
2014
2015
2016
2017
Thereafter
Total
Value
Dollars in Millions        
Long-Term Debt        
Fixed Rate
$72.2

$19.8

$1.7

$21.7

$51.2

$707.2

$873.8

$999.4
Average Interest Rate – %5.2
6.6
3.2
7.3
5.9
5.2
5.3
 
         
Variable Rate
$12.3

$75.0

$15.7



$41.3

$144.3

$144.3
Average Interest Rate – % (a)
3.6
1.2
0.2


0.2
1.0
 
(a)The $65 million line of credit is included in the fixed rate maturity of $528.1 as it will be refinanced with long-term debt in the first quarter of 2010.
(b)Assumes raterates in effect at December 31, 2009, remains2012 remain constant through remaining term. The $75 million term loan maturing in 2014 has an effective fixed rate of 1.825% due to an interest rate swap.

Interest rates on variable rate long-term debt are reset on a periodic basis reflecting currentprevailing market conditions. Based on the variable rate debt outstanding at December 31, 2009,2012, and assuming no other changes to our financial structure, an increase or decrease of 100 basis points in interest rates would impact the amount of pretax interest expense by $0.8$0.7 million. This amount was determined by considering the impact of a hypothetical 100 basis point increase to the average variable interest rate on the variable rate debt outstanding as of December 31, 2012.

Commodity Price Risk. Our regulated utility operations in Minnesota and Wisconsin incur costs for power and fuel (primarily coal and related transportation), in Minnesota and power and natural gas purchased for resale in our regulated service territories.territory in Wisconsin. Our Minnesota regulated utilities’utility’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory environment,framework, which allows recovery of fuel costs in excess of those included in the 2008 retail rate case filing.base rates. Conversely, costs below those in the 2008 retail rate case filingbase 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 power (in Minnesota), powerrelated transportation costs (Minnesota Power) and natural gas (in Wisconsin), and related transportation costs.(SWL&P).


ALLETE 2012 Form 10-K
51


Market Risk (Continued)

Power Marketing. Our power marketing activities consist ofof: (1) purchasing energy in the wholesale market for resale into serve our regulated service territoriesterritory when retail energy requirements exceed generation outputoutput; 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 wholesalemunicipal customers in our regulated service territory. We actively sell thisany excess energy to the wholesale market to optimize the value of our generating facilities.

In 2009 kilowatt-hour sales to our taconite customers were lower by approximately 54 percent from 2008 levels. During 2009, we sold available power to Other Power Suppliers to partially mitigate the earnings impact of these lower industrial sales. Minnesota Power expects an increase in taconite production in 2010 compared to 2009, although production will still be less than previous years’ levels.

For the year ended December 31, 2009, we have entered into financial derivative instruments to manage price risk for certain power marketing contracts. Outstanding derivative contracts at December 31, 2009, consist of cash flow hedges for an energy sale that includes pricing based on daily natural gas prices, and FTRs purchased to manage congestion risk for forward power sales contracts. These derivative instruments are recorded on our consolidated balance sheet at fair value. As of December 31, 2009, we recorded approximately $0.7 million of derivatives in other assets on our consolidated balance sheet of which the entire balance relates to our FTRs. These derivative instruments settle monthly throughout the first five months of 2010. (See Note 8. Derivatives.)

Approximately 200 MWs of capacity and energy from our Taconite Harbor facility in northern Minnesota has been sold through two sales contracts totaling 175 MWs (201 MWs including a 15 percent reserve), which were effective May 1, 2005, and expire on April 30, 2010. Both contracts contain fixed monthly capacity charges and fixed minimum energy charges. One contract provides for an annual escalator to the energy charge based on increases in our cost of fuel, subject to a small minimum annual escalation. The other contract provides that the energy charge will be the greater of the fixed minimum charge or an annual amount based on the variable production cost of a combined-cycle, natural gas unit. Our exposure in the event of a full or partial outage at our Taconite Harbor facility is significantly limited under both contracts. When the buyer is notified at least two months prior to an outage, there is no liability. Outages with less than two months notice are subject to an annual duration limitation typical of this type of contract. These contracts qualify for the normal purchase normal sale exception under the guidance for derivative instruments and hedging activities and are not required to be recorded at fair value.

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


ALLETE 2009 Form 10-K
47


Market Risk (Continued)
Power Marketing (Continued)

Power Sales Agreement. On October 29, 2009, Minnesota Power entered into an agreement to sell Basin 100 MWs of capacity and energy for the next ten years. The transaction is scheduled to begin in May 2010, following the expiration of two wholesale power sales contracts on April 30, 2010. The Basin agreement contains a fixed monthly schedule of capacity charges with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro-rata share of increased costs related to emissions that may occur during the last five years of the contract.


NewRecently Adopted Accounting StandardsStandards.

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


Item 7A.
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.
Item 8. Financial Statements and Supplementary Data

See our consolidated financial statements as of December 31, 20092012 and 2008,2011, and for each of the three years in the period ended December 31, 2009,2012, and supplementary data, which are indexed in Item 15(a).


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

Not applicable.


Item 9A.
Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, as of December 31, 2012, we conducted an evaluation of the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures (as defined in Rules 13a-15(e) andor 15d-15(e) of the Securities Exchange Act of 1934 (“Exchange Act”)(Exchange Act)). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that, as of December 31, 2012, such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009,2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.


ALLETE 20092012 Form 10-K
52

48


Item 9A.Item 9A. Controls and Procedures (Continued)

Changes in Internal Controls

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


Item 9B.Item 9B. Other Information

None.Not applicable.



ALLETE 20092012 Form 10-K
53

49


Part III

Item 10.
Item 10. Directors, Executive Officers and Corporate Governance

Unless otherwise stated, the information required forby this Item is incorporated by reference herein from our Proxy Statement for the 20102013 Annual Meeting of Shareholders (2010(2013 Proxy Statement) under the following headings:

·
Directors. The information regarding directors will be included in the “Election of Directors” section;
·
Audit Committee Financial Expert. The information regarding the Audit Committee financial expert will be included in the “Audit Committee Report” section;
·
Audit Committee Members. The identity of the Audit Committee members is included in the “Audit Committee Report” section;
·
Executive Officers. The information regarding executive officers is included in Part I of this Form 10-K; and
·
Section 16(a) Compliance. The information regarding Section 16(a) compliance will be included in the “Section 16(a) Beneficial Ownership Reporting Compliance” section.

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

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

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

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

Our 20102013 Proxy Statement will be filed with the SEC within 120 days after the end of our 20092012 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 CompensationAudit Committee Charter; and
·
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.
Item 11. Executive Compensation

The information required for this Item is incorporated by reference herein from the “Compensation of Executive Officers,Discussion and Analysis,” the “Compensation Discussionof Directors and Analysis”,Executive Officers,” the “Executive Compensation Committee Report” and the “Director Compensation – 2009”2012 sections in our 20102013 Proxy Statement.


Item 12.
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 “Securities“Ownership of ALLETE Common Stock – Securities Owned by Certain Beneficial Owners,” the “Securities owned“Ownership of ALLETE Common Stock – Securities Owned by Directors and Management” and the “Equity Compensation Plan Information” sections in our 20102013 Proxy Statement.



ALLETE 2012 Form 10-K
54


Item 13.
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 20102013 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.
Item 14. Principal Accounting Fees and Services

The information required byfor this Item is incorporated by reference herein from the “Audit Committee Report” section in our 20102013 Proxy Statement.



ALLETE 20092012 Form 10-K
55

50


Part IV


Item 15.     Exhibits and Financial Statement Schedules
Item 15.
Exhibits and Financial Statement Schedules

(a)Certain Documents Filed as Part of this Form 10-K. 
(1)Financial StatementsPage
 ALLETE 
 57
 58
 For the Three Years Ended December 31, 20092012 
 59
 
 60
 61
 62
(2)Financial Statement Schedules 
 97
 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. 


Exhibit Number
ALLETE 2012 Form 10-K
56


Exhibit Number
*3(a)1-
Articles of Incorporation amended and restated as of May 8, 2001 (filed as Exhibit 3(b) to the March 31, 2001,
Form 10-Q, File No. 1-3548).
*3(a)2-Amendment to Articles of Incorporation, dated as of May 12, 2009 (filed as Exhibit 3 to the June 30, 2009, Form 10-Q, File No. 1-3548).
*3(a)3-Amendment to Articles of Incorporation, dated as of May 19, 2010 (filed as Exhibit 3(a) to the May 14, 2010, Form 8-K, File No. 1-3548).
*3(a)4
Amendment to Certificate of Assumed Name, filed with the Minnesota Secretary of State on May 8, 2001 (filed as
Exhibit 3(a) to the March 31, 2001, Form 10-Q, File No. 1-3548).
*3(b)-Bylaws, as amended effective August 24, 2004,May 11, 2010 (filed as Exhibit 33(b) to the August 25, 2004,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 Douglas J. MacInnesPhilip 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:
  NumberDated as ofReference FileExhibit
  FirstMarch 1, 19492-78267(b)
  SecondJuly 1, 19512-90367(c)
  ThirdMarch 1, 19572-130752(c)
  FourthJanuary 1, 19682-277942(c)
  FifthApril 1, 19712-395372(c)
  SixthAugust 1, 19752-541162(c)
  SeventhSeptember 1, 19762-570142(c)
  EighthSeptember 1, 19772-596902(c)
  NinthApril 1, 19782-608662(c)
  TenthAugust 1, 19782-628522(d)2
  EleventhDecember 1, 19822-566494(a)3
  TwelfthApril 1, 198733-302244(a)3
  ThirteenthMarch 1, 199233-474384(b)
  FourteenthJune 1, 199233-552404(b)
  FifteenthJuly 1, 199233-552404(c)
  SixteenthJuly 1, 199233-552404(d)
  SeventeenthFebruary 1, 199333-501434(b)
  EighteenthJuly 1, 199333-501434(c)
  NineteenthFebruary 1, 19971-3548 (1996 Form 10-K)4(a)3
  TwentiethNovember 1, 19971-3548 (1997 Form 10-K)4(a)3
  Twenty-firstOctober 1, 2000333-543304(c)3
  Twenty-secondJuly 1, 20031-3548 (June 30, 2003 Form 10-Q)4
  Twenty-thirdAugust 1, 20041-3548 (Sept. 30, 2004 Form 10-Q)4(a)
  Twenty-fourthMarch 1, 20051-3548 (March 31, 2005 Form 10-Q)4
  Twenty-fifthDecember 1, 20051-3548 (March 31, 2006 Form 10-Q)4
  Twenty-sixthOctober 1, 20061-3548 (2006 Form 10-K)4
  Twenty-seventhFebruary 1, 20081-3548 (2007 Form 10-K)4(a)3
  Twenty-eighthMay 1, 20081-3548 (June 30, 2008 Form 10-Q)4
  Twenty-ninthNovember 1, 20081-3548 (2008 Form 10-K)4(a)3
  ThirtiethJanuary 1, 20091-3548 (2008 Form 10-K)4(a)4
Thirty-firstFebruary 1, 20101-3548 (March 31, 2010 Form 10-Q)4
Thirty-secondAugust 1, 20101-3548 (Sept. 30, 2010 Form 10-Q)4
Thirty-thirdJuly 1, 20121-3548 (July 2, 2012 Form 8-K)4

ALLETE 20092012 Form 10-K
57

51


Exhibit Number
Exhibit Number
*4(b)1-
Indenture of Trust, dated as of August 1, 2004, between the City of Cohasset, Minnesota and U.S. Bank National Association, as Trustee relating to $111 Million Collateralized Pollution Control Refunding Revenue Bonds (filed as Exhibit 4(b) to the September 30, 2004, Form 10-Q, File No. 1-3548).
*4(b)2-
Loan Agreement, dated as of August 1, 2004, between the City of Cohasset, Minnesota and ALLETE relating to $111 Million Collateralized Pollution Control Refunding Revenue Bonds (filed as Exhibit 4(c) to the September 30, 2004, Form 10-Q, File No. 1-3548).
*4(c)1-
Mortgage and Deed of Trust, dated as of March 1, 1943, between Superior Water, Light and Power Company and Chemical Bank & Trust Company and Howard B. Smith, as Trustees, both succeeded by U.S. Bank National Association, as Trustee (filed as Exhibit 7(c), File No. 2-8668).
*4(c)2-
Supplemental Indentures to Superior Water, Light and Power Company’s Mortgage and Deed of Trust:
  NumberDated as ofReference FileExhibit
  FirstMarch 1, 19512-596902(d)(1)
  SecondMarch 1, 19622-277942(d)1
  ThirdJuly 1, 19762-574782(e)1
  FourthMarch 1, 19852-786414(b)
  FifthDecember 1, 19921-3548 (1992 Form 10-K)4(b)1
  SixthMarch 24, 19941-3548 (1996 Form 10-K)4(b)1
  SeventhNovember 1, 19941-3548 (1996 Form 10-K)4(b)2
  EighthJanuary 1, 19971-3548 (1996 Form 10-K)4(b)3
  NinthOctober 1, 20071-3548 (2007 Form 10-K)4(c)3
  TenthOctober 1, 20071-3548 (2007 Form 10-K)4(c)4
  EleventhDecember 1, 20081-3548 (2008 Form 10-K)4(c)3
*4(d)
Note Purchase Agreement, dated as of June 8, 2007, between ALLETE and Thrivent Financial for Lutherans and The Northwestern Mutual Life Insurance Company (filed as Exhibit 10(a) to the June 30, 2007, Form 10-Q, File No. 1-3548).
*4(e)
Term Loan Agreement, dated as of August 25, 2011, between ALLETE, Inc. and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4 to the August 31, 2011, Form 8-K, File No. 1-3548).
*10(a)-
Power Purchase and Sale Agreement, dated as of May 29, 1998, between Minnesota Power, Inc. (now ALLETE) and Square Butte Electric Cooperative (filed as Exhibit 10 to the June 30, 1998, Form 10-Q, File No. 1-3548).
*10(b)
*10(d)2-First Amendment to Fourth AmendedSole Lead Arranger and Restated Committed Facility Letter dated June 19, 2006, by and among ALLETE and LaSalle Bank National Association, as AgentSole Book Runner (filed as Exhibit 10(a)99 to the June 30, 2006,May 27, 2011, Form 10-Q,8-K, File No. 1-3548).
*10(c)*10(d)3-
Second Amendment to Fourth Amended and Restated Committed Facility LetterCredit Agreement, dated December 14, 2006, by andas of February 1, 2012, among ALLETE, Inc., as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and LaSalle Bank National Association,JPMorgan Securities LLC, as AgentSole Lead Arranger and Sole Book Runner (filed as Exhibit 10(d)310 to the 2006February 6, 2012, Form 10-K,8-K, File No. 1-3548).
*10(e)10(d)1-
Financing Agreement between Collier County Industrial Development Authority and ALLETE dated as of
July 1, 2006 (filed as Exhibit 10(b)1 to the June 30, 2006, Form 10-Q, File No. 1-3548).
*10(e)10(d)2-
Amended and Restated Letter of Credit Agreement, dated as of July 5, 2006,June 3, 2011, among ALLETE, the Participating Banksparticipating banks and Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (filed as Exhibit 10(b)2 to the June 30, 2006,2011, Form 10-Q, File No. 1-3548).
*10(e)
LLC (filed as Exhibit 10(g) to the 2009 Form 10-K, File No. 1-3548).
+*10(f)1
2011 (filed as Exhibit 10(h)1 to the 2010 Form 10-K, File No. 1-3548).
+*10(h)10(f)2-Form of
ALLETE Executive Annual Incentive Plan Form of Awards Effective 20092010 (filed as Exhibit 10(h)73 to the 2008 2009
Form 10-K, File No. 1-3548).
+*10(f)3
2011 (filed as Exhibit 10(h)4 to the 2010 Form 10-K, File No. 1-3548).
+*10(f)4
ALLETE Executive Annual Incentive Plan Form of Awards Effective 2012 (filed as Exhibit 10(h)4 to the 2011 Form 10-K, File No. 1-3548).
+10(f)5
ALLETE Executive Annual Incentive Plan Form of Awards Effective 2013.
+*10(i)10(g)1-
ALLETE and Affiliated Companies Supplemental Executive Retirement Plan I (SERP I), as amended and restated, effective January 1, 2009 (filed as Exhibit 10(i)4 to the 2008 Form 10-K, File No. 1-3548).
+*10(g)2
Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), effective January 1, 2011 (filed as Exhibit 10(i)2 to the 2010 Form 10-K, File No. 1-3548).
+*10(i)210(g)3-
ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2009,2011 (filed as Exhibit 10(i)53 to the 20082010 Form 10-K, File No. 1-3548).

ALLETE 2012 Form 10-K
58


+*10(i)3-January 2009 Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), effective January 20, 2009, (filed as Exhibit 10(i)6 to the 2008 Form 10-K, File No. 1-3548).Number
+*10(j)10(h)1-
Minnesota Power and Affiliated Companies Executive Investment Plan I, as amended and restated, effective
November 1, 1988 (filed as Exhibit 10(c) to the 1988 Form 10-K, File No. 1-3548).
+*10(j)10(h)2-
Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment
Plan I (filed as Exhibit 10(v)2 to the 2003 Form 10-K, File No. 1-3548).


ALLETE 2009 Form 10-K
52


Exhibit Number
+*10(j)10(h)3-
July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(b) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(j)10(h)4-
August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(b) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(k)10(i)1-
Minnesota Power and Affiliated Companies Executive Investment Plan II, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(d) to the 1988 Form 10-K, File No. 1-3548).
+*10(k)10(i)2-
Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment
Plan II (filed as Exhibit 10(w)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(k)10(i)3-
July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(c) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(k)10(i)4-
August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(c) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+10(j)+*10(l)-
ALLETE Deferred Compensation Trust Agreement, as amended and restated, effective January 1, 1989 (filed as Exhibit 10(f) to the 1988 Form 10-K, File No. 1-3548).December 15, 2012.
+*10(m)10(k)1-
ALLETE Executive Long-Term Incentive Compensation Plan as amended and restated effective January 1, 2006 (filed as Exhibit 10 to the May 16, 2005, Form 8-K, File No. 1-3548).
+*10(m)10(k)2-Form of
Amendment to the ALLETE Executive Long-Term Incentive Compensation Plan, 2006 Nonqualified Stock Option Granteffective January 1, 2011 (filed as Exhibit 10(a)110(m)2 to the January 30, 2006,2010 Form 8-K,10-K, File No. 1-3548).
+*10(m)10(k)3-
Form of ALLETE Executive Long-Term Incentive Compensation Plan Nonqualified Stock Option Grant Effective 2007 (filed as Exhibit 10(m)6 to the 2006 Form 10-K, File No. 1-3548).
+*10(m)10(k)4-
Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2007 (filed as Exhibit 10(m)7 to the 2006 Form 10-K, File No. 1-3548).
+*10(m)10(k)5-
Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2008 (filed as Exhibit 10(m)10 to the 2007 Form 10-K, File No. 1-3548).
+*10(m)10(k)6-
Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2009 (filed as Exhibit 10(m)11 to the 2008 Form 10-K, File No. 1-3548).
+*10(k)7+*10(m)7 -
Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2009 (filed as Exhibit 10(m)12 to the 2008 Form 10-K, File No. 1-3548).
+*10(k)8
2010 (filed as Exhibit 10(m)8 to the 2009 Form 10-K, File No. 1-3548).
+*10(k)9
2010 (filed as Exhibit 10(m)9 to the 2009 Form 10-K, File No. 1-3548).
+*10(k)10
Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2011 (filed as Exhibit 10(m)11 to the 2010 Form 10-K, File No. 1-3548).
+*10(n)10(k)11
Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2011 (filed as Exhibit 10(m)12 to the 2010 Form 10-K, File No. 1-3548).
+*10(k)12
Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2012 (filed as Exhibit 10(m)12 to the 2011 Form 10-K, File No. 1-3548).
+*10(k)13
Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2012 (filed as Exhibit 10(m)13 to the 2011 Form 10-K, File No. 1-3548).
+10(k)14
Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2013.
+10(k)15
Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2013.
+*10(l)1-
Minnesota Power (now ALLETE) Director Stock Plan, effective January 1,May 9, 1995 (filed as Exhibit 10 to the
March 31, 1995, Form 10-Q, File No. 1-3548).
+*10(n)10(l)2-
Amendments through December 2003 to the Minnesota Power (now ALLETE) Director Stock Plan (filed as
Exhibit 10(z)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(n)10(l)3-
July 2004 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(e) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(n)10(l)4-
January 2007 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(n)4 to the 2006 Form 10-K, File No. 1-3548).
+*10(n)10(l)5-
May 2009 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(b) to the June 30, 2009, Form 10-Q, File No. 1-3548).
+*10(l)6
May 2010 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(a) to the June 30, 2010, Form 10-Q, File No. 1-3548).

ALLETE 2012 Form 10-K
59


Exhibit Number
+*10(n)610(l)7-
October 2010 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10 to the September 30, 2010,
Form 10-Q, File No. 1-3548).
+*10(m)1
ALLETE Non-Management Director Compensation Summary Effective February 15, 2007May 1, 2010 (filed as Exhibit 10(n)610(b) to the 2006March 31, 2010, Form 10-Q, File No. 1-3548).
+*10(m)2
ALLETE Non-Management Director Compensation Summary effective January 19, 2011 (filed as Exhibit 10(n)9 to the 2010 Form 10-K, File No. 1-3548).
+*10(m)3
ALLETE Non-Management Director Compensation Summary effective January 19, 2012 (filed as Exhibit 10(n)10 to the 2011 Form 10-K, File No. 1-3548).
+*10(o)10(n)1-
Minnesota Power (now ALLETE) Director Compensation Deferral Plan Amended and Restated, effective
January 1, 1990 (filed as Exhibit 10(ac) to the 2002 Form 10-K, File No. 1-3548).
+*10(o)10(n)2-
October 2003 Amendment to the Minnesota Power (now ALLETE) Director Compensation Deferral Plan (filed as Exhibit 10(aa)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(o)10(n)3-
January 2005 Amendment to the ALLETE Director Compensation Deferral Plan (filed as Exhibit 10(c) to the
March 31, 2005, Form 10-Q, File No. 1-3548).
+*10(o)10(n)4-August
October 2006 Amendment to the ALLETE Director Compensation Deferral Plan (filed as Exhibit 10(d) to the
September 30, 2006, Form 10-Q, File No. 1-3548).


ALLETE 2009 Form 10-K
53


Exhibit Number
+10(n)5
July 2012 Amendment to the ALLETE Director Compensation Deferral Plan.
+*10(o)51-
ALLETE Non-Employee Director Compensation Deferral Plan II, effective May 1, 2009 (filed as Exhibit 10(a) to the June 30, 2009, Form 10-Q, File No. 1-3548).
+10(o)2
ALLETE Non-Employee Director Compensation Deferral Plan II, as amended and restated, effective July 24, 2012.
+*10(p)1-
ALLETE Director Compensation Trust Agreement, effective October 11, 2004 (filed as Exhibit 10(a) to the
September 30, 2004, Form 10-Q, File No. 1-3548).
+10(p)2
ALLETE Director Compensation Trust Agreement, as amended and restated, effective December 15, 2012.
+*10(q)-
ALLETE and Affiliated Companies Change ofin Control Severance Pay Plan, Effective February 13, 2008,as amended and restated, effective
January 19, 2011 (filed as Exhibit 10(q) to the 20072010 Form 10-K, File No. 1-3548).
12
21
23
31(a)
31(b)
32
95
Mine Safety.
99
-
101.INS
XBRL Instance
101.SCH
XBRL Schema
101.CAL
XBRL Calculation
101.DEF
XBRL Definition
101.LAB
XBRL Label
101.PRE
XBRL Presentation


ALLETE 2012 Form 10-K
SWL&P is a party to other60


ALLETE or its subsidiaries are obligors under various long-term debt instruments, including but not limited to, (1) $38,995,000 original principal amount, of City of Cohasset, Minnesota, Variable Rate Demand Revenue Refunding Bonds (ALLETE, formerly Minnesota Power & Light Company, Project) Series 1997A, Series 1997B and Series 1997C ($27,455,000 remaining principal balance) that, pursuant to Regulation S-K, Item 601(b)(4)(iii), (2) $6,370,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Refunding Bonds Series 2007A and $6,130,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Bonds Series 2007B,2007B; and (3) other long-term debt instruments that, pursuant to Regulation S-K, Item 601(b)(4)(iii), are not filed as exhibits sincebecause 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.

We are a party to another long-term debt instrument, $38,995,000 of City of Cohasset, Minnesota, Variable Rate Demand Revenue Refunding Bonds (ALLETE, formerly Minnesota Power & Light Company, Project) Series 1997A, Series 1997B and Series 1997C that, pursuant to Regulation S-K, Item 601(b)(4)(iii), is not filed as an exhibit since the total amount of debt authorized under this omitted instrument does not exceed 10 percent of our total consolidated assets. We will furnish copies of this instrument 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 20092012 Form 10-K
61

54


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 12, 201015, 2013ByDonald J. Shippar /s/ Alan R. Hodnik
 Donald J. ShipparAlan R. Hodnik
 Chairman, andPresident, 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
     
Donald J. Shippar/s/ Alan R. Hodnik Chairman, President, Chief Executive Officer and Director February 12, 201015, 2013
Donald J. ShipparAlan R. Hodnik 
and Director
(Principal Executive Officer)
  
     
Alan R. HodnikPresident and DirectorFebruary 12, 2010
Alan R. Hodnik
/s/ Mark A. Schober Senior Vice President and Chief Financial Officer February 12, 201015, 2013
Mark A. Schober (Principal Financial Officer)  
     
/s/ Steven Q. DeVinck Controller and Vice President – Business Support February 12, 201015, 2013
Steven Q. DeVinck (Principal Accounting Officer)  

ALLETE 20092012 Form 10-K
62

55


Signatures (Continued)



Signature Title Date
     
/s/ Kathleen A. Brekken Director February 12, 201015, 2013
Kathleen A. Brekken    
     
/s/ Kathryn W. Dindo Director February 12, 201015, 2013
Kathryn W. Dindo    
     
/s/ Heidi J. Eddins Director February 12, 201015, 2013
Heidi J. Eddins    
     
/s/ Sidney W. Emery, Jr. Director February 12, 201015, 2013
Sidney W. Emery, Jr.    
     
James S. Haines, Jr/s/ George G. Goldfarb Director February 12, 201015, 2013
James S. Haines, JrGeorge G. Goldfarb    
     
/s/ James S. Haines, Jr.DirectorFebruary 15, 2013
James S. Haines, Jr.
/s/ James J. Hoolihan Director February 12, 201015, 2013
James J. Hoolihan    
     
/s/ Madeleine W. Ludlow Director February 12, 201015, 2013
Madeleine W. Ludlow    
     
George L. MayerDirectorFebruary 12, 2010
George L. Mayer
/s/ Douglas C. Neve Director February 12, 201015, 2013
Douglas C. Neve    
     
Jack I. RajalaDirectorFebruary 12, 2010
Jack I. Rajala
/s/ Leonard C. Rodman Director February 12, 201015, 2013
Leonard C. Rodman    
     
/s/ Bruce W. Stender Director February 12, 201015, 2013
Bruce W. Stender    


ALLETE 20092012 Form 10-K
63

56



Report of Independent Registered Public Accounting Firm


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

In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of ALLETE, Inc. and its subsidiaries (the Company) at December 31, 20092012 and 2008,2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 2012in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the indexappearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company'sCompany’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'sManagement’s Report on Internal Control Overover 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'sCompany’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.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007.

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 12, 201015, 2013


ALLETE 20092012 Form 10-K
64

57


Consolidated Financial StatementsCONSOLIDATED FINANCIAL STATEMENTS


ALLETE Consolidated Balance Sheet

As of December 3120092008
Millions  
Assets  
Current Assets  
Cash and Cash Equivalents$25.7$102.0
Accounts Receivable (Less Allowance of $0.9 and $0.7)118.576.3
Inventories57.049.7
Prepayments and Other24.324.3
Total Current Assets225.5252.3
Property, Plant and Equipment – Net1,622.71,387.3
Regulatory Assets293.2249.3
Investment in ATC88.476.9
Other Investments130.5136.9
Other Assets32.832.1
Total Assets$2,393.1$2,134.8
   
Liabilities and Equity  
Liabilities  
Current Liabilities  
Accounts Payable$62.1$75.7
Accrued Taxes20.612.9
Accrued Interest11.18.9
Long-Term Debt Due Within One Year5.210.4
Notes Payable1.96.0
Other32.236.8
Total Current Liabilities133.1150.7
Long-Term Debt695.8588.3
Deferred Income Taxes253.1169.6
Regulatory Liabilities47.150.0
Other Liabilities325.0339.3
Total Liabilities1,454.11,297.9
   
Commitments and Contingencies (Note 11)  
   
Equity  
ALLETE’s Equity  
Common Stock Without Par Value, 80.0 Shares Authorized, 35.2 and 32.6  
Shares Outstanding613.4534.1
Unearned ESOP Shares(45.3)(54.9)
Accumulated Other Comprehensive Loss(24.0)(33.0)
Retained Earnings385.4380.9
Total ALLETE Equity929.5827.1
Non-Controlling Interest in Subsidiaries9.59.8
Total Equity939.0836.9
Total Liabilities and Equity$2,393.1$2,134.8
As of December 312012
2011
Millions  
Assets  
Current Assets  
Cash and Cash Equivalents
$80.8

$101.1
Accounts Receivable (Less Allowance of $1.0 and $0.9)89.0
79.7
Inventories69.8
69.1
Prepayments and Other33.6
27.1
Total Current Assets273.2
277.0
Property, Plant and Equipment – Net2,347.6
1,982.7
Regulatory Assets340.3
345.9
Investment in ATC107.3
98.9
Other Investments143.5
132.3
Other Non-Current Assets41.5
39.2
Total Assets
$3,253.4

$2,876.0
Liabilities and Equity  
Liabilities  
Current Liabilities  
Accounts Payable
$90.5

$71.8
Accrued Taxes30.2
26.4
Accrued Interest15.6
12.8
Long-Term Debt Due Within One Year84.5
5.4
Notes Payable
1.1
Other62.6
45.6
Total Current Liabilities283.4
163.1
Long-Term Debt933.6
857.9
Deferred Income Taxes423.8
373.6
Regulatory Liabilities60.1
43.5
Defined Benefit Pension and Other Postretirement Benefit Plans228.2
253.5
Other Non-Current Liabilities123.3
105.1
Total Liabilities2,052.4
1,796.7
Commitments and Contingencies (Note 11)

Equity  
Common Stock Without Par Value, 80.0 Shares Authorized, 39.4 and 37.5  
Shares Outstanding784.7
705.6
Unearned ESOP Shares(21.3)(29.0)
Accumulated Other Comprehensive Loss(22.0)(28.9)
Retained Earnings459.6
431.6
Total Equity1,201.0
1,079.3
Total Liabilities and Equity
$3,253.4

$2,876.0

The accompanying notes are an integral part of these statements.

ALLETE 20092012 Form 10-K
65

58


ALLETE Consolidated Statement of Income

Year Ended December 31200920082007
Millions Except Per Share Amounts   
Operating Revenue   
Operating Revenue$766.7$801.0$841.7
Prior Year Rate Refunds(7.6)
Total Operating Revenue759.1801.0841.7
Operating Expenses   
Fuel and Purchased Power279.5305.6347.6
Operating and Maintenance308.9318.1313.9
Depreciation64.755.548.5
Total Operating Expenses653.1679.2710.0
Operating Income106.0121.8131.7
Other Income (Expense)   
Interest Expense(33.8)(26.3)(22.6)
Equity Earnings in ATC17.515.312.6
Other1.815.615.5
Total Other Income (Expense)(14.5)4.65.5
    
Income Before Non-Controlling Interest and Income Taxes91.5126.4137.2
Income Tax Expense30.843.447.7
Net Income60.783.089.5
Less: Non-Controlling Interest in Subsidiaries(0.3)0.51.9
Net Income Attributable to ALLETE$61.0$82.5$87.6
    
Average Shares of Common Stock   
Basic32.229.228.3
Diluted32.229.328.4
    
Basic Earnings Per Share of Common Stock$1.89$2.82$3.09
Diluted Earnings Per Share of Common Stock$1.89$2.82$3.08
    
Dividends Per Share of Common Stock$1.76$1.72$1.64
Year Ended December 31201220112010
Millions Except Per Share Amounts   
Operating Revenue
$961.2

$928.2

$907.0
Operating Expenses   
Fuel and Purchased Power308.7
306.6
325.1
Operating and Maintenance397.1
381.2
365.6
Depreciation100.2
90.4
80.5
Total Operating Expenses806.0
778.2
771.2
Operating Income155.2
150.0
135.8
Other Income (Expense)   
Interest Expense(45.5)(43.6)(39.2)
Equity Earnings in ATC19.4
18.4
17.9
Other6.0
4.4
4.6
Total Other Expense(20.1)(20.8)(16.7)
Income Before Non-Controlling Interest and Income Taxes135.1
129.2
119.1
Income Tax Expense38.0
35.6
44.3
Net Income97.1
93.6
74.8
Less: Non-Controlling Interest in Subsidiaries
(0.2)(0.5)
Net Income Attributable to ALLETE
$97.1

$93.8

$75.3
Average Shares of Common Stock   
Basic37.6
35.3
34.2
Diluted37.6
35.4
34.3
Basic Earnings Per Share of Common Stock
$2.59

$2.66

$2.20
Diluted Earnings Per Share of Common Stock
$2.58

$2.65

$2.19
Dividends Per Share of Common Stock
$1.84

$1.78

$1.76

The accompanying notes are an integral part of these statements.


ALLETE 20092012 Form 10-K
66


ALLETE Consolidated Statement of Comprehensive Income

59
      
      
Comprehensive Income (Loss)2012 2011 2010
Millions     
Net Income
$97.1
 
$93.6
 
$74.8
Other Comprehensive Income (Loss)     
Unrealized Gain (Loss) on Securities     
Net of Income Taxes of $0.8, $(0.1) and $0.61.2
 (0.3) 0.8
Unrealized Loss on Derivatives     
Net of Income Taxes of $(0.1), $(0.2) and $—(0.2) (0.3) 
Defined Benefit Pension and Other Postretirement Benefit Plans     
Net of Income Taxes of $3.9, $(3.6), and $—5.9
 (5.1) 
Total Other Comprehensive Income (Loss)6.9
 (5.7) 0.8
Total Comprehensive Income
$104.0
 
$87.9
 
$75.6
Less: Non-Controlling Interest in Subsidiaries
 (0.2) (0.5)
Comprehensive Income Attributable to ALLETE
$104.0
 
$88.1
 
$76.1

The accompanying notes are an integral part of these statements.



ALLETE 2012 Form 10-K
67


ALLETE Consolidated Statement of Cash Flows

Year Ended December 31
        2009
        2008
       2007
2012
2011
2010
Millions  
Operating Activities  
Net Income$60.7$83.0$89.5
$97.1

$93.6

$74.8
Allowance for Funds Used During Construction(5.8)(3.3)(3.8)
Loss (Income) from Equity Investments, Net of Dividends0.1(3.1)(2.7)
Gain on Sale of Assets(0.2)(4.8)(2.2)
Gain on Sale of Available-for-sale Securities(6.4)
Allowance for Funds Used During Construction – Equity(5.1)(2.5)(4.2)
Income from Equity Investments, Net of Dividends(3.7)(3.2)(3.1)
Gain on Real Estate Foreclosure
(0.5)(0.7)
Loss (Gain) on Sale of Assets0.2
(0.9)
Loss on Impairment of Assets3.10.3
1.7

Depreciation Expense64.755.548.5100.2
90.4
80.5
Amortization of Debt Issuance Costs0.90.81.01.0
0.9
0.9
Deferred Income Tax Expense75.238.814.037.5
35.8
66.0
Stock Compensation Expense2.11.82.0
Share-Based Compensation Expense2.1
1.6
2.2
ESOP Compensation Expense7.7
7.4
7.1
Defined Benefit Pension and Other Postretirement Benefit Expense27.5
23.6
18.0
Bad Debt Expense1.30.71.01.0
1.2
1.1
Changes in Operating Assets and Liabilities  
Accounts Receivable(43.5)2.4(6.6)(10.1)18.6
17.9
Inventories(7.3)(0.2)(6.1)(0.7)(9.1)(3.0)
Prepayments and Other11.2(11.7)(6.5)1.5
(4.3)
Accounts Payable10.5(14.1)9.4(1.5)(9.5)5.8
Other Current Liabilities5.35.9(10.0)21.8
15.4
5.2
Regulatory and Other Assets(18.3)(1.8)0.9
Regulatory and Other Liabilities(11.4)(12.8)0.7
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans(8.8)(24.7)(39.3)
Changes in Regulatory and Other Non-Current Assets(20.9)(7.5)4.2
Changes in Regulatory and Other Non-Current Liabilities0.8
7.9
(0.4)
Cash from Operating Activities137.4153.6124.2239.6
241.7
228.7
Investing Activities  
Proceeds from Sale of Available-for-sale Securities8.962.3449.71.5
7.8
0.6
Payments for Purchase of Available-for-sale Securities(2.2)(44.8)(368.3)(1.8)(2.3)(2.3)
Investment in ATC(7.8)(7.4)(8.7)(4.7)(2.0)(1.6)
Changes to Other Investments(0.7)(9.2)(12.4)(9.6)(7.4)1.3
Additions to Property, Plant and Equipment(318.5)(301.1)(210.2)(405.8)(239.2)(248.9)
Proceeds from Sale of Assets0.320.41.50.3
2.2

Other3.7(5.7)
Cash for Investing Activities(320.0)(276.1)(154.1)(420.1)(240.9)(250.9)
Financing Activities  
Proceeds from Issuance of Common Stock65.271.120.677.0
39.1
20.5
Proceeds from Issuance of Long-Term Debt111.4198.7123.9180.6
81.4
155.0
Changes in Notes Payable(4.1)6.0(1.1)0.1
(0.9)
Reductions of Long-Term Debt(9.1)(22.7)(90.7)(25.9)(3.1)(71.0)
Debt Issuance Costs(0.6)(1.5)(1.1)(1.3)
(1.4)
Dividends on Common Stock(56.5)(50.4)(44.3)(69.1)(62.1)(60.8)
Cash from Financing Activities106.3201.28.4160.2
55.4
41.4
Change in Cash and Cash Equivalents(76.3)78.7(21.5)(20.3)56.2
19.2
Cash and Cash Equivalents at Beginning of Period102.023.344.8101.1
44.9
25.7
Cash and Cash Equivalents at End of Period$25.7$102.0$23.3
$80.8

$101.1

$44.9
`
The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K
68


ALLETE Consolidated Statement of Shareholders’ Equity

 
Total
Shareholders’
Equity
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Unearned
ESOP
Shares
Common
Stock
Millions     
Balance as of December 31, 2009
$929.5

$385.4
$(24.0)$(45.3)
$613.4
Comprehensive Income     
Net Income74.8
74.8
   
Other Comprehensive Income – Net of Tax     
Unrealized Gain on Securities – Net0.8
 0.8
  
Total Comprehensive Income75.6
    
Non-Controlling Interest in Subsidiaries0.5
0.5
   
Comprehensive Income Attributable to ALLETE76.1
    
Common Stock Issued – Net22.7
   22.7
Dividends Declared(60.8)(60.8)   
ESOP Shares Earned8.5
  8.5
 
Balance as of December 31, 2010976.0
399.9
(23.2)(36.8)636.1
Comprehensive Income     
Net Income93.6
93.6
   
Other Comprehensive Income – Net of Tax     
Unrealized Loss on Securities – Net(0.3) (0.3)  
Unrealized Loss on Derivatives – Net(0.3) (0.3)  
Defined Benefit Pension and Other Postretirement Plans – Net(5.1) (5.1)  
Total Comprehensive Income87.9
    
Non-Controlling Interest in Subsidiaries0.2
0.2
   
Comprehensive Income Attributable to ALLETE88.1
    
Common Stock Issued – Net69.5
   69.5
Dividends Declared(62.1)(62.1)   
ESOP Shares Earned7.8
  7.8
 
Balance as of December 31, 20111,079.3
431.6
(28.9)(29.0)705.6
Comprehensive Income     
Net Income97.1
97.1
   
Other Comprehensive Income – Net of Tax     
Unrealized Gain on Securities – Net1.2
 1.2
  
Unrealized Loss on Derivatives – Net(0.2) (0.2)  
Defined Benefit Pension and Other Postretirement Plans – Net5.9
 5.9
  
Total Comprehensive Income Attributable to ALLETE104.0
    
Common Stock Issued – Net79.1
   79.1
Dividends Declared(69.1)(69.1)   
ESOP Shares Earned7.7
  7.7
 
Balance as of December 31, 2012
$1,201.0

$459.6
$(22.0)$(21.3)
$784.7

The accompanying notes are an integral part of these statements.

ALLETE 20092012 Form 10-K
69

60


ALLETE Consolidated Statement of Shareholders’ Equity

    Accumulated  
 Total OtherUnearned 
 Shareholders’RetainedComprehensiveESOPCommon
 EquityEarningsIncome (Loss)SharesStock
Millions     
Balance as of December 31, 2006$665.8$307.8$(8.8)$(71.9)$438.7
Comprehensive Income     
Net Income89.589.5   
Other Comprehensive Income – Net of Tax     
Unrealized Gains on Securities – Net1.1 1.1  
Defined Benefit Pension and Other Postretirement Plans3.2 3.2  
Total Comprehensive Income93.8    
   Non-Controlling Interest in Subsidiaries (1.9)(1.9)   
Comprehensive Income Attributable to ALLETE91.9    
Adjustment to apply accounting standards for Income Taxes(0.7)(0.7)   
Common Stock Issued – Net22.5   22.5
Dividends Declared(44.3)(44.3)   
ESOP Shares Earned7.4  7.4 
Balance as of December 31, 2007742.6350.4(4.5)(64.5)461.2
Comprehensive Income     
Net Income83.083.0   
Other Comprehensive Income – Net of Tax     
Unrealized Loss on Securities – Net(6.0) (6.0)  
Reclassification Adjustment for Gains Included in Income(3.7) (3.7)  
Defined Benefit Pension and Other Postretirement Plans(18.8) (18.8)  
Total Comprehensive Income54.5    
   Non-Controlling Interest in Subsidiaries(0.5)(0.5)   
Comprehensive Income Attributable to ALLETE54.0    
Adjustment to apply change in Pension and Postretirement measurement date(1.6)(1.6)   
Common Stock Issued – Net72.9   72.9
Dividends Declared(50.4)(50.4)   
ESOP Shares Earned9.6  9.6 
Balance as of December 31, 2008827.1380.9(33.0)(54.9)534.1
Comprehensive Income     
Net Income60.760.7   
Other Comprehensive Income – Net of Tax     
Unrealized Gain on Securities – Net2.8 2.8  
Defined Benefit Pension and Other Postretirement Plans6.2 6.2  
Total Comprehensive Income69.7    
   Non-Controlling Interest in Subsidiaries0.30.3   
Comprehensive Income Attributable to ALLETE70.0    
Common Stock Issued – Net79.3   79.3
Dividends Declared(56.5)(56.5)   
ESOP Shares Earned9.6  9.6 
Balance as of December 31, 2009$929.5$385.4$(24.0)$(45.3)$613.4

The accompanying notes are an integral part of these statements.


ALLETE 2009 Form 10-K
61


Notes to Consolidated Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1.Operations and Significant Accounting Policies
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Preparation. References in this report to “we,” “us”“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 issuing the financial statements on February 12, 2010.issuance.

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

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

Regulated Operationsincludes retail and wholesale rate-regulated electric, natural gas, and water services in northeastern Minnesota and northwestern Wisconsin along with our Investment in ATC.regulated utilities, Minnesota Power provides regulated utility electric service to 144,000 retail customers in northeastern Minnesota.and SWL&P, a wholly-owned subsidiary, provides regulated utility electric, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Billings are rendered on a cycle basis. Revenue is accrued for service provided but not billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain environmental and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. Our Investment in ATC includesas well as our approximate 8 percent equity ownership interestinvestment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATCMinnesota Power provides transmissionregulated utility electric service in northeastern Minnesota to approximately 143,000 retail customers. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under rates regulated by the FERC that are set in accordance with the FERC’s policyjurisdiction of establishing the independent operationstate and ownership of, and investment in, transmission facilities. (See Note 6. Investment in ATC.)federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 7,0006,100 acres of land available-for-sale in Minnesota, and earnings on cash and investments.

BNI Coal, a wholly-owned subsidiary, mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2009,2012, Square Butte supplied approximately 50 percent (227.5 MWs) (227.5 MW) of its output to Minnesota Power under a long-term contract. (See Note 11. Commitments, Guarantees and Contingencies.) Coal sales are recognized when delivered at the cost of production plus a specified profit per ton of coal delivered.

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

Full profit recognition is recorded on sales upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. In certain cases, where there are obligations to perform significant development activities after the date of sale, we recognize profit on a percentage-of-completion basis. PursuantFrom time to this method of accounting, gross profit is recognized based upon the relationship of development costs incurred as of that date to the total estimated development costs of the parcels, including related amenities or common costs of the entire project. Revenue and cost of real estate sold in excess of the amount recognized based on the percentage-of-completion method is deferred and recognized as revenue and cost of real estate sold during the period in which the related development costs are incurred. Deferred revenue and cost of real estate sold are recorded net as Deferred Profit on Sales of Real Estate on our consolidated balance sheet. On December 31, 2009 and 2008, we had no deferred profit recorded on our consolidated balance sheet. Certaintime, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

ALLETE 2009 Form 10-K
62


Note 1.Operations and Significant Accounting Policies (Continued)

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


ALLETE 2012 Form 10-K
70


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Land held-for-sale is recorded atinventories are accounted for in accordance with the lower of cost or fair value determined by the evaluation of individual land parcelsaccounting standards for property, plant and isequipment, and are included in Other Investments on our consolidated balance sheet.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 guidancestandards for Real Estate.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 would beare recorded and the related assets would beare adjusted to their estimated fair value, less costs to sell.value. (See Note 7. Investments.)

Property, PlantALLETE Clean Energy, a wholly-owned subsidiary of ALLETE, operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and Equipment. Property, plantother clean energy innovations. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and equipment are recordedlarge end-users across North America through long-term contracts or other sale arrangements, and will be subject to applicable state and federal regulatory approvals.

Non-Controlling Interest in Subsidiaries. In August 2011, ALLETE purchased the remaining shares of the ALLETE Properties non-controlling interest at original cost and are reported on the balance sheet netbook value for $8.8 million by issuing 0.2 million shares of accumulated depreciation. Expenditures for additions and significant replacements and improvements are capitalized; maintenance and repair costs are expensed as incurred. Expenditures for major plant overhauls are alsoALLETE common stock. This was accounted for using this same policy. Gains or losses on non-rate base property, plantas an equity transaction, 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 iswas recognized pursuant to guidance on accounting for Regulated Operations. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. (See Note 3. Property, Plant and Equipment.)in net income or comprehensive income.

Cash and Cash Equivalents.Long-Lived Asset Impairments. We account for our long-lived assets at depreciated historical cost. A long-lived asset is tested for recoverability whenever eventsconsider all investments purchased with original maturities of three months or changes in circumstances indicate that its carrying amount may notless to be recoverable. We conduct this assessment using the accounting guidance for impairment or disposal of long-lived assets. Judgments and uncertainties affecting the application of accounting for asset impairment include economic conditions affecting market valuations, changes in our business strategy, and changes in our forecast of future operating cash flows and earnings. We would recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted future cash flows. Management judgment is involved in both deciding if testing for recoverability is necessary and in estimating undiscounted future cash flows.equivalents.

Supplemental Statement of Cash Flow Information
Consolidated Statement of Cash Flows   
Year Ended December 312012
2011
2010
Millions   
Cash Paid During the Period for Interest – Net of Amounts Capitalized
$42.7

$43.2

$35.7
Cash Received During the Period for Income Taxes (a)

$(11.4)$(54.2)
Noncash Investing and Financing Activities   
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment
$20.2

$5.9
$7.5
Capitalized Asset Retirement Costs
$17.1

$0.3

$2.8
AFUDC – Equity
$5.1

$2.5

$4.2
ALLETE Common Stock Contributed to the Pension Plan
$(20.0)
(a)Due to bonus depreciation provisions in 2009 and 2010 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and refunds were received from NOL carrybacks against prior years’ taxable income.

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

Accounts Receivable    
As of December 31
             2009
20082012
 2011
Millions     
Trade Accounts Receivable     
Billed$56.5$61.1
$70.4
 
$63.7
Unbilled15.115.917.4
 15.6
Less: Allowance for Doubtful Accounts0.90.71.0
 0.9
Total Trade Accounts Receivable70.776.386.8
 78.4
Income Taxes Receivable47.82.2
 1.3
Total Accounts Receivable – Net$118.5$76.3
Total Accounts Receivable - Net
$89.0
 
$79.7

ALLETE 2012 Form 10-K
71


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 12 large industrial customers.9 Large Power Customers. Receivables from these customers totaled approximately $10$11.6 million at December 31, 2009 ($112012 ($9.3 million at December 2008)31, 2011). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, our taconite-producing Large Power Customers, which are a part of our Regulated Operations segment, are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 12.3 percent of consolidated revenue in 2012 (12.8 percent in 2011; 12.5 percent in 2010). In the third quarter of 2011, one of Minnesota Power’s Large Power Customers, NewPage Corporation (NewPage), filed for Chapter 11 bankruptcy protection. In September 2012, NewPage submitted a motion to the bankruptcy court to approve amended and restated service agreements and payment of the pre-petition amount, which was approved on October 16, 2012. The agreement was subsequently approved by the MPUC in a December 10, 2012 order, which resulted in the pre-petition receivable of $3.2 million being paid as of December 31, 2012. Throughout the bankruptcy proceedings this customer’s operations continued without interruption and we continued to provide electric and steam service to this customer.

Long-Term Finance Receivables.Inventories. Inventories Long-term finance receivables relating to our real estate operations are statedcollateralized 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 lowerbalance of cost or market. Amounts removed from inventory are recorded on an average cost basis.

Inventories 
As of December 31
        2009
        2008
Millions  
Fuel$23.0$16.6
Materials and Supplies34.033.1
Total Inventories$57.0$49.7


ALLETE 2009 Form 10-K
63


Note 1.Operations and Significant Accounting Policies (Continued)

Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized oversuch receivables to the termsestimated fair value of the related debt instruments usingcollateralized property. If the effective interest method.fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals. (See Note 7. Investments.)

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 
Supplemental Disclosure 
Year Ended December 31200920082007
Millions   
Cash Paid During the Period for   
Interest – Net of Amounts Capitalized$29.8$25.2$26.3
Income Taxes$1.1$6.5$34.2
    
Noncash Investing and Financing Activities   
Changes in Accounts Payable for Capital Additions to Property, Plant and Equipment$24.1$17.1$9.8
AFUDC – Equity$5.8$3.3$3.8
ALLETE Common Stock contributed to the Pension Plan$(12.0)


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. Our auction rate securities (ARS), classified as available-for-sale securities, are recorded at cost because their cost approximates fair market value. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as the share price trends and the impact of overall market conditions. (See Note 7. Investments.)

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

Inventories   
As of December 312012
 2011
Millions   
Fuel
$28.0
 
$28.6
Materials and Supplies41.8
 40.5
Total Inventories
$69.8
 
$69.1

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

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

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


ALLETE 2012 Form 10-K
72


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

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

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

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

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

Accounting for Stock-Based Compensation.We apply the fair value recognition guidance for share-based payments. Under this method,guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate and only for those shares expected to vest over the required service period of the award.rate. (See Note 17.16. Employee Stock and Incentive Plans.)
Prepayments and Other Current Assets   
As of December 312012
 2011
Millions   
Deferred Fuel Adjustment Clause
$22.5
 
$17.5
Other11.1
 9.6
Total Prepayments and Other Current Assets
$33.6
 
$27.1


ALLETE 2012 Form 10-K
73


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Prepayments and Other Current Assets  
As of December 3120092008
Millions  
Deferred Fuel Adjustment Clause$15.5$13.1
Other8.811.2
Total Prepayments and Other Current Assets$24.3$24.3
Other Current Liabilities   
As of December 312012
 2011
Millions   
Customer Deposits (a)

$28.8
 
$16.3
Other33.8
 29.3
Total Other Current Liabilities
$62.6
 
$45.6
(a)Customer deposits were higher in 2012 primarily due to customer security deposits for capital expenditures relating to a transmission project.


Other Liabilities  
As of December 3120092008
Millions  
Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Plans$231.2$251.8
Asset Retirement Obligation (See Note 3. Property, Plant and Equipment)44.639.5
Other49.248.0
Total Other Liabilities$325.0$339.3
Other Non-Current Liabilities   
As of December 312012
 2011
Millions   
Asset Retirement Obligation
$77.9
 
$57.0
Other45.4
 48.1
Total Other Non-Current Liabilities
$123.3
 
$105.1

Environmental Liabilities. We review environmental matters for disclosure on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the balance sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to operating expense unless recoverable in rates from customers. (See Note 11. Commitments, Guarantees and Contingencies.)

ALLETE 2009 Form 10-K
Revenue Recognition. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for service provided but not billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. BNI recognizes revenue when coal is delivered.
64


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.

Derivatives. We review all material power purchaseUnamortized Discount and sales contracts for derivative treatment to determine if they qualify forPremium on Debt. Discount and premium on debt are deferred and amortized over the normal purchase normal sale exception underterms of the guidance for derivatives and hedging. (See Note 8. Derivatives.)related debt instruments using the straight-line method which approximates the effective interest method.

Income Taxes. We ALLETE and its subsidiaries file a consolidated federal income tax return.return and combined and separate state income tax returns. We account for income taxes using the liability method as prescribed byin accordance with the guidance in 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. InvestmentFederal 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. Effective January 1, 2007, we adoptedIn accordance with the guidanceaccounting standards for uncertainty in income taxes. Under this guidancetaxes, 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.percent likely. (See Note 14. Income Tax Expense.)


ALLETE 2012 Form 10-K
74


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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


New Accounting Standards.

Codification. In June 2009, the FASB approved the FASB Accounting Standards Codification (Codification) as the single source of authoritative nongovernmental GAAP. The Codification is an online research system that reorganizes the thousands of GAAP pronouncements into a topical structure. The Codification was launched on July 1, 2009, at which time all existingThere are no recently issued accounting standards documents were superseded and all existing accounting literature not includedstandard updates applicable for our adoption in the Codification was considered non-authoritative, except for guidance issued by the SEC, which remains a source of authoritative GAAP. The Codification was effective September 30, 2009.

Subsequent Events. In May 2009, the FASB issued guidance on accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Entities are required to disclose the date through which subsequent events have been evaluated and the basis for that date. The guidance on subsequent events was adopted on June 30, 2009, and did not have a material impact on our consolidated financial position, results of operations, or cash flows.

Non-controlling Interests. In December 2007, the FASB issued amended guidance to improve the relevance, comparability, and transparency of the financial information a reporting entity provides in its consolidated financial statements with regards to non-controlling interests. Non-controlling interest in a subsidiary is defined as an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. The amended guidance changes the presentation of the consolidated income statement by requiring consolidated net income to include amounts attributable to the parent and the non-controlling interest. A single method of accounting was established for changes in a parent’s ownership interest in a subsidiary which do not result in deconsolidation. Expanded disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners of a subsidiary are also required. The guidance for non-controlling interests was adopted on January 1, 2009. ALLETE Properties does have certain non-controlling interests in consolidated subsidiaries. The presentation of our consolidated financial statements was impacted, but the adoption of the guidance for non-controlling interests did not have a material impact on our consolidated financial position, results of operations or cash flows.

Derivatives and Hedging. In March 2008, the FASB issued guidance that amends and expands the disclosure requirements for derivatives and hedging. The guidance requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements are also required. The guidance on derivatives and hedging was adopted on January 1, 2009. As the amended guidance provides only disclosure requirements, the adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows. (See Note 8. Derivatives.)

Financial Instruments. In April 2009, the FASB issued amended guidance to require disclosure about fair value of financial instruments for interim reporting periods of publicly traded companies in addition to annual financial statements. This amended guidance was adopted on June 30, 2009. As the amended guidance provided only disclosure requirements, the adoption of this standard did not have a material impact on our consolidated financial position, results of operations or cash flows. (See Note 9. Fair Value.)

ALLETE 2009 Form 10-K
65


Note 1.Operations and Significant Accounting Policies (Continued)

Fair Value. In April 2009, the FASB issued additional guidance for applying the provisions of fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. This guidance requires an evaluation of whether there has been a significant decrease in the volume and level of activity for the asset or liability in relation to normal market activity for the asset or liability. If there has, transactions or quoted prices may not be indicative of fair value and a significant adjustment may need to be made to those prices to estimate fair value. Additionally, an entity must consider whether the observed transaction was orderly (that is, not distressed or forced). If the transaction was orderly, the obtained price can be considered a relevant observable input for determining fair value. If the transaction is not orderly, other valuation techniques must be used when estimating fair value. This additional guidance on fair value was adopted on June 30, 2009, and did not have a material impact on our consolidated financial position, results of operations or cash flows.

In August 2009, the FASB issued an amendment to the guidance for fair value measurement and disclosure of liabilities. This amendment provides clarification for measuring the fair value of liabilities in circumstances in which a quoted price in an active market for the identical liability is not available. The adoption of this standard on September 30, 2009, did not have an impact on our consolidated financial position, results of operations or cash flows.

In September 2009, the FASB issued an amendment to the fair value measurement and disclosure of investments in certain entities that calculate net asset value per share. This amendment requires disclosures, by major category of investment, about the attributes of investments, such as the nature of any restrictions on the investor’s ability to redeem its investments at the measurement date, any unfunded commitments, and the investment strategies of the investees. The amended guidance was adopted on December 31, 2009. As the amended guidance provides only disclosure requirements, the adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

In January 2010, FASB issued an amendment to the fair value measurement and disclosure standard improving disclosures about fair value measurements. This amendment requires disclosure about recurring or nonrecurring fair value measurements, such as transfers in and out of Levels 1 and 2 and activity in Level 3 fair value measurements. Separate disclosures on amounts of significant transfers in and out and reasons for the transfers for Level 1 and Level 2 fair value measurements are required. In Level 3 reconciliations, the activity, such as information about purchases, sales, issuances and settlements, must be presented separately. The guidance for the Level 1 and Level 2 disclosures and clarifications is effective on January 1, 2010. The guidance for the activity in Level 3 disclosures is effective January 1, 2011. As the amended guidance provides only disclosure requirements, the adoption of the amendments will not have an impact on our consolidated financial position, results of operations or cash flows.

Other-Than-Temporary Impairments. In April 2009, the FASB issued amended guidance on other-than-temporary impairments. If it is more likely than not that an impaired security will be sold before the recovery of its cost basis, either due to the investor’s intent to sell or because it will be required to sell the security, the entire impairment is recognized in earnings. Otherwise, only the portion of the impaired debt security related to estimated credit losses is recognized in earnings, while the remainder of the impairment is recorded in other comprehensive income and recognized over the remaining life of the debt security. In addition, the guidance expands the presentation and disclosure requirements for other-than-temporary impairments for both debt and equity securities. The amended guidance for other-than-temporary impairments was adopted on June 30, 2009, and did not have an impact on our consolidated financial position, results of operations or cash flows.

Pensions and Other Postretirement Benefits. In December 2008, the FASB issued guidance that amends employers’ disclosures about pensions and other postretirement benefits. These changes provide guidance on disclosures about plan assets, investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. These disclosure requirements will be effective for fiscal years ending after December 15, 2009. Upon initial adoption, the requirements within this guidance are not required for earlier periods that are presented for comparative purposes. This amended guidance was adopted on December 31, 2009. As the amended guidance provides only disclosure requirements, the adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows. (See Note 16. Pension and Other Postretirement Benefit Plans.)

Transfers of Financial Assets. In June 2009, the FASB issued amended guidance for the transfers of financial assets. The guidance was issued with the objective of improving the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. Key provisions of the amended guidance include (1) the removal of the concept of qualifying special purpose entities, (2) the introduction of the concept of a participating interest, in circumstances in which a portion of a financial asset has been transferred, and (3) the requirement that to qualify for sale accounting, the transferor must evaluate whether it maintains effective control over transferred financial assets either directly or indirectly. The amended guidance also requires enhanced disclosures about transfers of financial assets and a transferor’s continuing involvement. The amended guidance is effective January 1, 2010, and is required to be applied prospectively. We are currently assessing the impact of the adoption on our consolidated financial position, results of operations and cash flows, but we do not believe it will have a material impact on the Company.

ALLETE 2009 Form 10-K
66


Note 1.Operations and Significant Accounting Policies (Continued)

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


Note 2.Business Segments
NOTE 2. BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 7,0006,100 acres of land available-for-sale in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.
 ConsolidatedRegulated OperationsInvestments and Other
Millions   
2012   
Operating Revenue
$961.2

$874.4

$86.8
Fuel and Purchased Power Expense308.7
308.7

Operating and Maintenance Expense397.1
310.0
87.1
Depreciation Expense100.2
93.9
6.3
Operating Income (Loss)155.2
161.8
(6.6)
Interest Expense(45.5)(39.8)(5.7)
Equity Earnings in ATC19.4
19.4

Other Income6.0
5.1
0.9
Income (Loss) Before Non-Controlling Interest and Income Taxes135.1
146.5
(11.4)
Income Tax Expense (Benefit)38.0
50.4
(12.4)
Net Income97.1
96.1
1.0
Less: Non-Controlling Interest in Subsidiaries


Net Income Attributable to ALLETE
$97.1

$96.1

$1.0
Total Assets
$3,253.4

$2,962.4

$291.0
Capital Additions
$432.2

$418.2

$14.0

ALLETE 2012 Form 10-K
75


NOTE 2. BUSINESS SEGMENTS (Continued)

 RegulatedInvestments
 ConsolidatedOperationsand Other
Millions   
2009   
Operating Revenue$766.7$689.4$77.3
Prior Year Rate Refunds(7.6)(7.6)
Total Operating Revenue759.1681.877.3
Fuel and Purchased Power279.5279.5
Operating and Maintenance308.9235.873.1
Depreciation Expense64.760.24.5
Operating Income (Loss)106.0106.3(0.3)
Interest Expense(33.8)(28.3)(5.5)
Equity Earnings in ATC17.517.5
Other Income (Expense)1.85.8(4.0)
Income (Loss) Before Non-Controlling Interest and Income Taxes91.5101.3(9.8)
Income Tax Expense (Benefit)30.835.4(4.6)
Net Income (Loss)60.765.9 (5.2)
Less: Non-Controlling Interest in Subsidiaries(0.3)(0.3)
Net Income (Loss) Attributable to ALLETE$61.0$65.9$(4.9)
    
Total Assets$2,393.1$2,184.0$209.1
Capital Additions$303.7$299.2$4.5
 ConsolidatedRegulated OperationsInvestments and Other
Millions   
2011   
Operating Revenue
$928.2

$851.9

$76.3
Fuel and Purchased Power Expense306.6
306.6

Operating and Maintenance Expense381.2
301.5
79.7
Depreciation Expense90.4
85.4
5.0
Operating Income (Loss)150.0
158.4
(8.4)
Interest Expense(43.6)(35.8)(7.8)
Equity Earnings in ATC18.4
18.4

Other Income4.4
2.6
1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes129.2
143.6
(14.4)
Income Tax Expense (Benefit)35.6
43.2
(7.6)
Net Income (Loss)93.6
100.4
(6.8)
Less: Non-Controlling Interest in Subsidiaries(0.2)
(0.2)
Net Income (Loss) Attributable to ALLETE
$93.8

$100.4
$(6.6)
Total Assets
$2,876.0

$2,579.8

$296.2
Capital Additions
$246.8

$228.0

$18.8

 ConsolidatedRegulated OperationsInvestments and Other
Millions   
2010   
Operating Revenue
$907.0

$835.5

$71.5
Fuel and Purchased Power Expense325.1
325.1

Operating and Maintenance Expense365.6
292.3
73.3
Depreciation Expense80.5
76.1
4.4
Operating Income (Loss)135.8
142.0
(6.2)
Interest Expense(39.2)(32.3)(6.9)
Equity Earnings in ATC17.9
17.9

Other Income4.6
3.8
0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes119.1
131.4
(12.3)
Income Tax Expense (Benefit)44.3
51.6
(7.3)
Net Income (Loss)74.8
79.8
(5.0)
Less: Non-Controlling Interest in Subsidiaries(0.5)
(0.5)
Net Income (Loss) Attributable to ALLETE
$75.3

$79.8
$(4.5)
Total Assets
$2,609.1

$2,375.4

$233.7
Capital Additions
$260.0

$256.4

$3.6



ALLETE 20092012 Form 10-K
76

67


Note 2.                      Business Segments (Continued)

 RegulatedInvestments
 ConsolidatedOperationsand Other
Millions   
2008   
Operating Revenue$801.0$712.2$88.8
Fuel and Purchased Power305.6305.6
Operating and Maintenance318.1239.378.8
Depreciation Expense55.550.74.8
Operating Income121.8116.65.2
Interest Expense(26.3)(24.0)(2.3)
Equity Earnings in ATC15.315.3
Other Income15.63.612.0
Income Before Non-Controlling Interest and Income Taxes126.4111.514.9
Income Tax Expense (Benefit)43.443.6(0.2)
Net Income83.067.915.1
Less: Non-Controlling Interest in Subsidiaries0.50.5
Net Income Attributable to ALLETE$82.5$67.9$14.6
    
Total Assets$2,134.8$1,832.1$302.7
Capital Additions$322.9$317.0$5.9


 RegulatedInvestments
 ConsolidatedOperationsand Other
Millions   
2007   
Operating Revenue$841.7$723.8$117.9
Fuel and Purchased Power347.6347.6
Operating and Maintenance313.9229.384.6
Depreciation Expense48.543.84.7
Operating Income131.7103.128.6
Interest Expense(22.6)(21.0)(1.6)
Equity Earnings in ATC12.612.6
Other Income15.54.111.4
Income Before Non-Controlling Interest and Income Taxes137.298.838.4
Income Tax Expense47.736.411.3
Net Income89.562.427.1
Less: Non-Controlling Interest in Subsidiaries1.91.9
Net Income Attributable to ALLETE$87.6$62.4$25.2
    
Total Assets$1,644.2$1,396.6$247.6
Capital Additions$223.9$220.6$3.3


Note 3.Property, Plant and Equipment
NOTE 3. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment  
As of December 31
       2009
          2008
Millions  
Regulated Utility$2,415.7$1,837.2
Construction Work in Progress89.6303.0
Accumulated Depreciation(928.8)(806.8)
Regulated Utility Plant – Net1,576.51,333.4
Non-Rate Base Energy Operations87.094.0
Construction Work in Progress3.63.9
Accumulated Depreciation(45.5)(47.2)
Non-Rate Base Energy Operations Plant – Net45.150.7
Other Plant – Net1.13.2
Property, Plant and Equipment – Net$1,622.7$1,387.3


ALLETE 2009 Form 10-K
68


Note 3.Property, Plant and Equipment (Continued)
Property, Plant and Equipment   
As of December 312012 2011
Millions   
Regulated Utility
$3,232.9
 
$2,794.8
Construction Work in Progress151.8
 155.0
Accumulated Depreciation(1,102.8) (1,024.6)
Regulated Utility Plant - Net2,281.9
 1,925.2
Non-Rate Base Energy Operations118.0
 106.4
Construction Work in Progress4.2
 2.3
Accumulated Depreciation(56.7) (51.4)
Non-Rate Base Energy Operations Plant - Net65.5
 57.3
Other Plant - Net0.2
 0.2
Property, Plant and Equipment - Net
$2,347.6
 
$1,982.7

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets. The MPUC and the PSCW have approved depreciation rates for our Regulated Utility plant.

Estimated Useful Lives of Property, Plant and Equipment
     
Regulated Utility –Generation23 to 3435 yearsNon-Rate Base Operations3 to 61 years
 Transmission42 to 61 yearsOther Plant5 to 25 years
 Distribution14 to 65 years  

Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction or development and/or normal operation of the asset. Asset retirement obligations (ARO) relate primarily to the decommissioning of our utility steamcoal-fired and wind generating facilities and land reclamation at BNI Coal, and are included in Other Liabilitiesother non-current liabilities on our consolidated balance sheet. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.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 were included in accumulated depreciation. With the adoption of ARO guidance, accumulated plant removal costs were reclassifiedare 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, 20072010
$36.550.3
Accretion Expense2.06.4
Additional Liabilities Incurred in 200820111.00.3
Obligation as of December 31, 2008201139.557.0
Accretion Expense2.33.8
Additional Liabilities Incurred in 200920122.817.1
Obligation as of December 31, 20092012
$44.677.9



ALLETE 2012 Form 10-K
Note 4.Jointly-Owned Electric Facility
77


NOTE 4. JOINTLY-OWNED FACILITIES

Following are our investments in jointly-owned facilities and the related ownership percentages as of December 31, 2012:
Regulated Utility PlantPlant in ServiceAccumulated DepreciationConstruction Work in Progress% Ownership
Millions    
Boswell Unit 4
$413.1

$188.1

$25.0
80
CapX202022.8
0.4
25.4
9.3 - 14.7
Total
$435.9

$188.5

$50.4
 

We own 80 percent of the 536-MW585 MW Boswell Energy Center Unit 4 (Boswell Unit 4).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 Wisconsin Public Power, Inc.,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 statementConsolidated Statement of income. Our 80 percent share ofIncome. We are a participant in the cost of Boswell Unit 4, which is includedCapX2020 initiative to ensure reliable electric transmission and distribution in property, plantthe region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and equipment at December 31, 2009, was $331 million ($328 million at December 31, 2008). The corresponding accumulated depreciation balance was $178 million at December 31, 2009 ($173 million at December 31, 2008).investor-owned utilities. We are currently participating in three CapX2020 projects with varying ownership percentages.


Note 5.Regulatory Matters
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.

20082010 Minnesota Rate Case.In May 2008, Minnesota Power filedPower’s current retail rates are based on a 2011 MPUC retail rate increase request with the MPUC seeking additional revenues of approximately $40 million annually; the request also sought an 11.15order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. As a result of a May 2009 Order and an August 2009 Reconsideration Order, the MPUC granted Minnesota Power a revenue increase of approximately $20 million, including a return on equity of 10.74 percent and a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.

ALLETE 2009 Form 10-K
69


Note 5.Regulatory Matters (Continued)

Interim rates, subject to refund, were in effect from August 1, 2008 through October 31, 2009. During 2009, Minnesota Power recorded a $21.7 million liability for refunds of interim rates, including interest, required to be made as a result of the May 2009 Order and the August 2009 Reconsideration Order. In 2009, $21.4 million was refunded, with a remaining $0.3 million balance to be refunded in early 2010; $7.6 million of the refunds required to be made were related to interim rates charged in 2008.

With the May 2009 Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel began with the implementation of final rates on November 1, 2009. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

2010 Rate Case. Minnesota Power previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of 11.50 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue.ratio.

Minnesota law allows the collection of interim rates while the MPUC processes the rate filing. On December 30, 2009, the MPUC issued an Order (the Order) authorizing $48.5 million of Minnesota Power’s November 2, 2009, interim rate increase request of $73.0 million. The MPUC cited exigent circumstances in reducing Minnesota Power’s interim rate request. Because the scope and depth of this reduction in interim rates was unprecedented, and because Minnesota law does not allowIn February 2011, Minnesota Power to formally challenge the MPUC’s action until a final decision in the case is rendered, on January 6, 2010, Minnesota Power sent a letter to the MPUC expressing its concerns about the Order and requested that the MPUC reconsider its decision on its own motion. Minnesota Power described its belief that the MPUC’s decision violates the law by prejudging the merits of the rate request prior to an evidentiary hearing and results in the confiscation of utility property. Further, the Company is concerned that the decision will have negative consequences on the environmental policy directions of the State of Minnesota by denying recovery for statutory mandates during the pendency of the rate proceeding. The MPUC has not acted in response to Minnesota Power’s letter.

The rate case process requires public hearings and an evidentiary hearing before an administrative law judge, both of which are scheduled for the second quarter of 2010. A final decision on the rate request is expected in the fourth quarter. We cannot predict the final level of rates that may be approved by the MPUC, and we cannot predict whether a legal challenge toappealed the MPUC’s interim rate decision will be forthcoming or successful.in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). On February 14, 2012, the Court granted the petition for review and oral arguments were held before the Court on October 9, 2012. A decision is expected in early 2013; however, we cannot predict the outcome at this time.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. In 2008, Minnesota Power entered into newPower’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these customers which transitioned customers to formula-based rates, allowing rates to be adjusted annually based on changes in cost. In February 2009, the FERC approved our municipal contracts which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are calculated using a cost-based formula methodology that is set at the beginning of the year based on expectedeach July 1, using estimated costs and providea 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. Wholesale rate increases totaling approximately $6 millioncosts incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and $10 million annually were implemented on February 1, 2009 and January 1, 2010, respectively,December 31, 2011, this customer submitted a cancellation notice with approximately $6 milliontermination effective on December 31, 2013. The 17 MW of additional revenues under the true-up provision accruedaverage monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in 2009, which will be billed in 2010.2014.

20092012 Wisconsin Rate Increase.Case.During 2012, SWL&P’s currentretail rates were based on a 2010 PSCW retail rate order, which was effective January 1, 2011. SWL&P’s 2013 retail rates are based on a December 20082012 PSCW retail rate order, that became effective January 1, 2009,2013, and allows for an 11.1a 10.9 percent return on common equity. The new rates reflected a 3.5reflect an average overall increase of 2.4 percent average increase infor retail utility rates for SWL&P customers (a 13.413.8 percent increase in water rates, a 4.71.2 percent increase in electric rates, and a 0.62.0 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3$1.7 million in additional revenue.

ALLETE 2012 Form 10-K
78


NOTE 5. REGULATORY MATTERS (Continued)

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

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

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

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

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

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


ALLETE 20092012 Form 10-K
79

70


Note 5.Regulatory MattersNOTE 5. REGULATORY MATTERS (Continued)

Deferred Regulatory Assets and Liabilities  
As of December 31
       2009
       2008
Millions  
Deferred Regulatory Assets  
Future Benefit Obligations Under  
Defined Benefit Pension and Other Postretirement Plans (a)
235.8216.5
Boswell Unit 3 Environmental Rider (b)
20.93.8
Deferred Fuel (c)
20.813.1
Income Taxes15.712.2
Asset Retirement Obligation6.35.1
Deferred MISO Costs2.43.9
Premium on Reacquired Debt2.02.2
Other4.85.6
Total Deferred Regulatory Assets$308.7$262.4
   
Deferred Regulatory Liabilities  
Income Taxes$25.9$28.7
Plant Removal Obligations16.915.9
Accrued MISO Refund4.7
Other4.30.7
Total Deferred Regulatory Liabilities$47.1$50.0

Regulatory Assets and Liabilities  
As of December 3120122011
Millions  
Current Regulatory Assets (a)
  
Deferred Fuel
$22.5

$17.5
   Total Current Regulatory Assets22.5
17.5
Non-Current Regulatory Assets  
Future Benefit Obligations Under  
Defined Benefit Pension and Other Postretirement Plans260.7
292.8
Income Taxes36.0
28.6
Asset Retirement Obligation12.1
9.8
Cost Recovery Riders (b)
18.5
0.7
PPACA Income Tax Deferral5.0
5.0
Conservation Improvement Program4.3
4.6
Other3.7
4.4
Total Non-Current Regulatory Assets340.3
345.9
   
Total Regulatory Assets
$362.8

$363.4
   
Non-Current Regulatory Liabilities  
Income Taxes
$19.5

$21.9
Plant Removal Obligations18.1
15.0
Wholesale and Retail Contra AFUDC15.5
1.5
Other7.0
5.1
Total Non-Current Regulatory Liabilities
$60.1

$43.5
(a)See Note 16. Pension and Other Postretirement Benefit Plans.
(b)MPUC-approved current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to base rates.
(c)As of December 31, 2009, $5 million of this balance relates to deferred fuel costs incurred under the former base cost of fuel calculation. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

Current and Non-Current Deferred Regulatory Assets and Liabilities  
As of December 31
       2009
       2008
Millions  
Total Current Deferred Regulatory Assets (a)
$15.5$13.1
Total Non-Current Deferred Regulatory Assets293.2249.3
Total Deferred Regulatory Assets308.7262.4
Total Current Deferred Regulatory Liabilities
Total Non-Current Deferred Regulatory Liabilities47.150.0
Total Deferred Regulatory Liabilities$47.1$50.0

(a)Current deferred regulatory assets are included in prepayments and other on the consolidated balance sheet.our Consolidated Balance Sheet.
(b)The increase in cost recovery rider regulatory assets in 2012 is primarily due to revenues related to our Bison Wind Energy Center.


Note 6.Investment in
NOTE 6. INVESTMENT IN ATC

Investment in ATC. Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATC provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of establishing the independent operationFERC-approved and ownership of, and investment in, transmission facilities.are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, 2009,2012, our equity investment balance in ATC was $88.4$107.3 million ($76.9 ($98.9 million at December 31, 2008)2011). On January 29, 2010,30, 2013, we invested an additional $1.2$0.4 million in ATC. In total, we expect to invest approximately $2$2.0 million throughout 2010.2013.

ALLETE’s Interest in ATC  
Year Ended December 31
       2009
       2008
Millions  
Equity Investment Beginning Balance$76.9$65.7
Cash Investments7.87.4
Equity in ATC Earnings17.515.3
Distributed ATC Earnings(13.8)(11.5)
Equity Investment Ending Balance$88.4$76.9
ALLETE’s Interest in ATC  
Year Ended December 3120122011
Millions  
Equity Investment Beginning Balance
$98.9

$93.3
Cash Investments4.7
2.0
Equity in ATC Earnings19.4
18.4
Distributed ATC Earnings(15.7)(14.8)
Equity Investment Ending Balance
$107.3

$98.9


ALLETE 20092012 Form 10-K
80

71


Note 6.Investment inNOTE 6. INVESTMENT IN ATC (Continued)

ATC Summarized Financial Data   
Year Ended December 31   
Income Statement Data
       2009
       2008
       2007
Millions   
Revenue$521.5$466.6$408.0
Operating Expense230.3209.0198.2
Other Expense77.869.655.7
Net Income$213.4$188.0$154.1
ALLETE’s Equity in Net Income$17.5$15.3$12.6
ATC Summarized Financial Data  
Balance Sheet Data  
As of December 3120122011
Millions  
Current Assets
$63.1

$58.7
Non-Current Assets3,274.7
3,053.7
Total Assets
$3,337.8

$3,112.4
Current Liabilities
$251.5

$298.5
Long-Term Debt1,550.0
1,400.0
Other Non-Current Liabilities95.8
82.6
Members’ Equity1,440.5
1,331.3
Total Liabilities and Members’ Equity
$3,337.8

$3,112.4

Income Statement Data   
Year Ended December 31201220112010
Millions   
Revenue
$603.2

$567.2

$556.7
Operating Expense281.0
261.6
251.1
Other Expense84.8
81.7
85.9
Net Income
$237.4

$223.9

$219.7
 
ALLETE’s Equity in Net Income

$19.4

$18.4

$17.9


Balance Sheet Data   
Millions   
Current Assets$51.1$50.8$48.3
Non-Current Assets2,767.32,480.02,189.0
Total Assets2,818.42,530.82,237.3
    
Current Liabilities285.5252.0317.1
Long-Term Debt1,259.61,109.4899.1
Other Non-Current Liabilities76.9120.2108.5
Members’ Equity1,196.41,049.2912.6
Total Liabilities and Members’ Equity$2,818.4$2,530.8$2,237.3


Note 7.Investments
NOTE 7. INVESTMENTS

Investments. At December 31, 2009,2012, our long-term investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits, ARS,and other assets consisting primarily of cash equivalents and land held-for-sale in Minnesota.

Investments  
As of December 31
          2009
          2008
Millions  
ALLETE Properties$93.1$84.9
Available-for-sale Securities29.532.6
Other7.919.4
Total Investments$130.5$136.9
Investments   
As of December 312012 2011
Millions   
ALLETE Properties
$91.1
 
$91.3
Available-for-sale Securities26.8
 24.7
Other25.6
 16.3
Total Investments
$143.5
 
$132.3


ALLETE 2012 Form 10-K
81


NOTE 7. INVESTMENTS (Continued)



ALLETE Properties    
As of December 31
          2009
          2008
2012 2011
Millions    
Land Held-for-Sale Beginning Balance$71.2$62.6
Additions during period: Capitalized Improvements5.610.5
Deductions during period: Cost of Real Estate Sold(1.9)(1.9)
Land Held-for-Sale Ending Balance74.971.2
Long-Term Finance Receivables12.913.6
Land Inventory Beginning Balance
$86.0
 
$86.0
Deeds to Collateralized Property0.5
 1.8
Land Impairment
 (1.7)
Cost of Sales(0.2) (0.3)
Capitalized Improvements and Other0.2
 0.2
Land Inventory Ending Balance86.5
 86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)1.4
 2.0
Other5.30.13.2
 3.3
Total Real Estate Assets$93.1$84.9
$91.1
 
$91.3

Land Inventory. Land Held-for-Sale. Land held-for-saleinventory is accounted for as held for use and is recorded at cost, unless the lower of cost orcarrying 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 determined by the evaluation of individual land parcels.value. Land values are reviewed for impairment on a quarterly basis. In 2012, impairment analysis’ of estimated future undiscounted cash flows was conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. Consequently, there was no impairments were impairment recorded for the year ended December 31, 2009 (none in 2008)2012. For the year ended

ALLETE 2009 Form 10-K
72


Note 7.Investments (Continued)
December 31, 2011, a 1.7 million impairment charge was recorded.

Long-Term Finance Receivables.Receivables. As of December 31, 2012, long-term finance receivables were $1.4 million net of allowance ($2.0 million net of allowance as of December 31, 2011). The decrease is primarily the result of the transfer of properties back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term finance receivables. Long-term finance receivables which are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accountsaccounts. As of $0.4 million at December 31, 2009 ($0.1 million at December 31, 2008). The2012, we had allowance for doubtful accounts includes $0.3of $0.6 million ($0.6 million as of impairments that were recorded for other receivables during the year ended December 31, 2009. The majority are receivables having maturities up to four years. Finance receivables totaling $7.8 million at December 31, 2009, were due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June 2009. The estimated fair value of the collateral relating to these receivables was greater than the $7.8 million amount due at December 31, 2009 and no impairment was recorded on these receivables. Due to the lack of recent market activity, we estimated fair value based primarily on recent property tax assessed values. This valuation technique constitutes a Level 3 non-recurring fair value measurement.2011).

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

Available-for-Sale Investments. We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities. Our auction rate securities of $6.7 million were redeemed at carrying value on January 5, 2011.
Available-For-Sale Securities
Millions Gross Unrealized 
As of December 31CostGain(Loss)Fair Value
2012$27.4$0.5$(1.1)$26.8
2011$27.3$0.1$(2.7)$24.7
2010$27.4$0.2$(2.4)$25.2

Available-For-Sale Securities
Millions Gross Unrealized 
As of December 31
 Cost
Gain(Loss)Fair Value
     
2009$33.1$0.1$(3.7)$29.5
2008$40.5$(7.9)$32.6
2007$45.3$8.4$(0.1)$53.6
 NetGross Realized
Net Unrealized
Gain (Loss) in Other
Year Ended December 31ProceedsGain(Loss)Comprehensive Income
2012$1.5$1.2
2011$7.8$(0.3)
2010$0.6$0.8



   Net Unrealized
 NetGross RealizedGain (Loss) in Other
Year Ended December 31ProceedsGain(Loss)Comprehensive Income
     
2009$6.7$4.5
2008$17.5$6.5$(0.1)$(9.7)
2007$81.4$1.4
ALLETE 2012 Form 10-K
82


NOTE 8. DERIVATIVES

Auction Rate Securities. Included in Available-for-Sale Securities as of December 31, 2009, is an auction rate municipal bond of $6.7 million ($15.2 million at December 31, 2008) with a stated maturity date of March 1, 2024. The ARS consists of guaranteed student loans insured or reinsured by the federal government. ARS were historically auctioned every 35 days to set new rates and provided a liquidating event in which investors could either buy or sell securities. Beginning in 2008, the auctions have been unable to sustain themselves due to the overall lack of market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified our ARS as long-term investments and have the ability to hold these securities to maturity, until called by the issuer, or until liquidity returns to this market.

The Company used a discounted cash flow model to determine the estimated fair value of its investment in the ARS as of December 31, 2009. The assumptions used in preparing the discounted cash flow model include the following: the effective interest rate, amount of cash flows, and expected holding periods of the ARS. These inputs reflect the Company’s judgments about assumptions that market participants would use in pricing ARS including assumptions about risk.

Of the remaining ARS outstanding as of December 31, 2009, approximately $0.3 million was called at par value effective March 1, 2010. We anticipate the remainder of our ARS will be redeemed in the second quarter of 2010, as we received a Notice of Contemplated Refunding on January 29, 2010. The investment remains classified as long-term until officially called by the bondholders.


Note 8.Derivatives

During 2009 we entered into financial derivative instruments to manage price risk for certain power marketing contracts. Outstanding derivative contracts at December 31, 2009, consist of cash flow hedges for an energy sale that includes pricing based on daily natural gas prices, and Financial Transmission Rights (FTRs) purchased to manage congestion risk for forward power sales contracts. These derivative instruments are recorded on our consolidated balance sheet at fair value. During 2009, we purchased $2.4 million of FTRs and expensed $1.7 million through our consolidated statement of income. As of December 31, 2009, approximately $0.7 million remains in other assets on our consolidated balance sheet. These derivative instruments settle monthly throughout the first five months of 2010.

ALLETE 2009 Form 10-K
73


Note 8.Derivatives (Continued)

Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria is met. Favorable changes in fair value of $0.3 million and $0.1 million were recorded in operating revenue in the first and second quarters of 2009, respectively; and a $0.4 million decrease was recorded in the third quarter of 2009 when2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the corresponding energyinterest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 8 percent of the Company’s outstanding long-term debt as of December 31, 2012. (See Note 10. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap contract ended.

are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting with respect to that derivative. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in value of the Swap designated as the hedging instrument will be deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the year ended December 31, 2012.The mark-to-market fluctuationsfluctuation on the cash flow hedge werewas recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. As of December 31, 2012, the fair value of the swap was a $0.7 million liability (a $0.4 million liability as of December 31, 2011) and is included in other non-current liabilities on the Consolidated Balance Sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the consolidated balance sheet; a $0.1 million increase in fair value was recorded in the first quarterConsolidated Statement of 2009, and a decrease of $0.1 million was recorded in the second quarter of 2009. There were no mark-to-market changes in the third or fourth quarters of 2009.Income.


Note 9.Fair Value
NOTE 9. FAIR VALUE

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

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

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

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

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 20092012 and December 31, 2008.2011. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, andwhich may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the tables below.


ALLETE 2012 Form 10-K
83


NOTE 9. FAIR VALUE (Continued)

 At Fair Value as of December 31, 2009
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities$17.8$17.8
Corporate Debt Securities$6.46.4
Derivatives$0.70.7
Debt Securities Issued by States of the United States (ARS)6.76.7
Money Market Funds1.41.4
Total Fair Value of Assets$19.2$6.4$7.4$33.0
     
Liabilities:    
Deferred Compensation$14.6$14.6
Total Fair Value of Liabilities$14.6$14.6
     
Total Net Fair Value of Assets (Liabilities)$19.2$(8.2)$7.4$18.4


ALLETE 2009 Form 10-K
74


Note 9.Fair Value (Continued)
 Fair Value as of December 31, 2012
Recurring Fair Value MeasuresLevel 1 Level 2 Level 3 Total
Millions       
Assets:       
Investments       
Available-for-sale Securities – Equity Securities
$18.0
 
 
 
$18.0
Available-for-sale Securities – Corporate Debt Securities
 
$8.8
 
 8.8
Cash Equivalents20.7
 
 
 20.7
Total Fair Value of Assets
$38.7
 
$8.8
 
 
$47.5
        
Liabilities:       
Deferred Compensation
 
$14.0
 
 
$14.0
Derivatives – Interest Rate Swap
 0.7
 
 0.7
Total Fair Value of Liabilities
 
$14.7
 
 
$14.7
Total Net Fair Value of Assets (Liabilities)
$38.7
 $(5.9) 
 
$32.8

  Debt Securities
  Issued by the States
Recurring Fair Value Measures of the United States
Activity in Level 3Derivatives(ARS)
Millions  
Balance as of December 31, 2008$15.2
Purchases, sales, issuances and settlements, net (a)
$0.7(8.5)     
Level 3 transfers in
Balance as of December 31, 2009$0.7$6.7
There was no activity in Level 3 during the year ended December 31, 2012.

(a)ARS called during 2009 at par value.
 Fair Value as of December 31, 2011
Recurring Fair Value MeasuresLevel 1 Level 2 Level 3 Total
Millions       
Assets:       
Investments       
Available-for-sale Securities – Equity Securities
$17.6
 
 
 
$17.6
Available-for-sale Securities – Corporate Debt Securities
 
$8.2
 
 8.2
Cash Equivalents11.4
 
 
 11.4
Total Fair Value of Assets
$29.0
 
$8.2
 
 
$37.2
        
Liabilities:       
Deferred Compensation
 
$12.8
 
 
$12.8
Derivatives – Interest Rate Swap
 
$0.4
 
 
$0.4
Total Fair Value of Liabilities
 
$13.2
 
 
$13.2
Total Net Fair Value of Assets (Liabilities)
$29.0
 $(5.0) 
 
$24.0


 At Fair Value as of December 31, 2008
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities$13.5$13.5
Corporate Debt Securities$3.33.3
Debt Securities Issued by States of the United States (ARS)$15.215.2
Money Market Funds10.610.6
Total Fair Value of Assets$24.1$3.3$15.2$42.6
     
Liabilities:    
Deferred Compensation$13.5$13.5
Total Fair Value of Liabilities$13.5$13.5
     
Total Net Fair Value of Assets (Liabilities)$24.1$(10.2)$15.2$29.1


Debt Securities
Issued by the States
Recurring Fair Value Measuresof the United States

Activity in Level 3
Debt Securities
Issued by States
of the United
States (ARS)
Millions 
Balance as of December 31, 20072010
$6.7
Purchases, sales, issuances and settlements, net Redeemed During the Period (a)
$(10.0)
Level 3 transfers in(6.725.2)
Balance as of December 31, 20082011
$15.2
(a)The ARS were redeemed at carrying value on January 5, 2011.

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


ALLETE 2012 Form 10-K
84


NOTE 9. FAIR VALUE (Continued)

(a)2008 includes a $5.2 million transfer of ARS to our Voluntary Employee Benefit Association trust used to fund postretirement health and life benefits.

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

Financial InstrumentsCarrying AmountFair ValueCarrying AmountFair Value
Millions   
Long-Term Debt, Including Current Portion   
December 31, 2009$701.0$734.8
December 31, 2008$598.7$561.6
December 31, 2012
$1,018.1

$1,143.7
December 31, 2011
$863.3

$966.4


Note 10.Short-Term and Long-Term Debt
NOTE 10. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt.Total short-term debt outstanding as of December 31, 2009,2012, was $5.2$84.5 million ($10.4 ($6.5 million at December 31, 2008)2011) and consisted of long-term debt due within one year. (See ALLETE consolidated balance sheet.)

ALLETE 2009 Form 10-K
75


Note 10.Short-Term and Long-Term Debt (Continued)

year and notes payable. As of December 31, 2009,2012, short-term debt increased from December 31, 2011, primarily due to $60.0 million of long-term debt maturing in April 2013.

As of December 31, 2012, we had bank lines of credit aggregating $157.0$406.4 million ($160.5 ($256.4 million at December 31, 2008)2011), the majority of which expire$150.0 million expires in January 2012.2014, and $250.0 million expires in June 2015. These bank lines of credit make financingare available throughto provide short-term bank loans and provide creditliquidity support for ALLETE’s commercial paper. At December 31, 2009, $69.2paper program and to issue up to $50.0 million ($7.3 million at December 31, 2008) was drawn in letters of credit. We had no outstanding draws on our lines of credit leaving a $87.8 million balance available for use ($153.2 million at as of December 31, 2008). In December 2009, we drew $65.02012 ($1.1 million on our $150.0 million syndicated revolving credit facility to temporarily fund the purchase of the 250 kV DC transmission line. In December 2009, we agreed to sell $80.0 million of First Mortgage Bonds in February 2010 (see Long-Term Debt, below). We intend to use proceeds from these bonds to repay the amount drawn on the line, resulting in $65.0 million of our line of credit being classified as long-term at December 31, 2009.2011).

On November 12, 2009, BNI Coal replacedFebruary 1, 2012, ALLETE entered into a $6.0$150.0 million Promissory Note credit agreement (Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and Supplement (Line of Credit) with CoBANK, ACB with a $3.0 million Line of Creditseveral other lenders that are parties thereto. The Agreement is unsecured and a $3.0 million term loan with CoBANK, ACB. The Line of Credit has a variable interest rate withmaturity date of January 31, 2014, which may be extended for one year, subject to bank approvals. Advances under the option to fix the rate based on LIBOR plus a certain spread. The term of the Line of Credit is 24 months. The Line of Credit is beingAgreement may be used for general corporate purposes. Aspurposes, to provide liquidity support for ALLETE’s commercial paper program and to issue up to $10.0 million in letters of December 31, 2009, $1.9 million was drawn on the Line of Credit. The $3.0 million term loan has a fixed interest rate of 5.19 percent and is payable in 28 equal quarterly installments commencing January 20, 2010, and ending on October 20, 2016.credit.

Long-Term Debt. Total long-term debt outstanding as of December 31, 2012, was $933.6 million ($857.9 million at December 31, 2011). The aggregate amount of long-term debt maturing during 20102013 is $5.2$84.5 million ($13.9 ($94.8 million in 2011; $3.32014; $17.4 million in 2012; $73.92015; $21.7 million in 2013; $19.62016; $51.2 million in 2014;2017; and $520.1$748.5 million thereafter). Substantially all of our electric plant is subject to the lien of the mortgagesmortgage collateralizing variousoutstanding 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.

In January 2009,On July 2, 2012, we issued $42.0$160.0 million in principal amount of unregistered First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019, and carry a coupon rate of 8.17 percent. We used the proceeds from the sale of the Bonds to fund utility capital investments and for general corporate purposes.

In December 2009, we agreed to sell $80.0 million in principal amount ofCompany’s First Mortgage Bonds (Bonds) in the private placement market in threetwo series as follows:

Issue Date
(on or about)
Maturity DatePrincipal AmountCouponInterest Rate
February 17, 2010July 2, 2012AprilJuly 15, 20212026$1575 Million4.85%3.20%
February 17, 2010July 2, 2012AprilJuly 15, 20252042$3085 Million5.10%
February 17, 2010April 15, 2040$35 Million6.00%4.08%

We expect to use the proceeds from the February 2010 sale of Bonds to pay down the syndicated revolving credit facility, to fund utility capital investments or for general corporate purposes.

For the January 2009 and the February 2010 bond issuances (the Bonds), we have the option to prepay all or a portion of the 3.20 percent Bonds at our discretion at any time prior to January 15, 2026, subject to a make-whole provision.provision, and at any time on or after January 15, 2026, at par, including, in each case, accrued and unpaid interest. We also have the option to prepay all or a portion of the 4.08 percent Bonds at our discretion at any time prior to January 15, 2042, subject to a make-whole provision, and at any time on or after January 15, 2042, at par, including, in each case, accrued and unpaid interest. The Bonds are subject to the additional terms and conditions of our utility mortgage. In July 2012, we used a portion of the proceeds from the sale of the Bonds to redeem $6.0 million of our 6.50 percent Industrial Development Revenue Bonds and to repay $14.0 million in outstanding borrowings on our $150.0 million line of credit. The remaining proceeds were used to fund utility capital expenditures and for general corporate purposes. The Bonds were sold or will be sold in reliance on an exemption from registration under Section 4(2)4(a)(2) of the Securities Act of 1933, as amended, to certain institutional accredited investors.


ALLETE 20092012 Form 10-K
85

76


Note 10.Short-Term and Long-Term DebtNOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt  
As of December 3120092008
Millions  
First Mortgage Bonds  
4.86% Series Due 2013$60.0$60.0
6.94% Series Due 201418.018.0
7.70% Series Due 201620.020.0
8.17% Series Due 201942.0
5.28% Series Due 202035.035.0
4.95% Pollution Control Series F Due 2022111.0111.0
6.02% Series Due 202375.075.0
5.99% Series Due 202760.060.0
5.69% Series Due 203650.050.0
SWL&P First Mortgage Bonds  
7.25% Series Due 201310.010.0
Senior Unsecured Notes 5.99% Due 201750.050.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2009 – 202028.328.3
Industrial Development Revenue Bonds 6.5% Due 20256.06.0
Industrial Development Variable Rate Demand Refunding  
Revenue Bonds Series 2006 Due 202527.827.8
Line of Credit Facility (a)
65.0
Other Long-Term Debt, 2.0% – 8.0% Due 2009 – 203742.947.6
Total Long-Term Debt701.0598.7
Less: Due Within One Year5.210.4
Net Long-Term Debt$695.8$588.3

 (a)The $80 million First Mortgage Bonds due in 2021, 2025 and 2040 to be issued on or about February 17, 2010, will replace the balance due on the Line of Credit Facility as of December 31, 2009.
Long-Term Debt  
As of December 3120122011
Millions  
First Mortgage Bonds  
4.86% Series Due 2013
$60.0

$60.0
6.94% Series Due 201418.0
18.0
7.70% Series Due 201620.0
20.0
8.17% Series Due 201942.0
42.0
5.28% Series Due 202035.0
35.0
4.85% Series Due 202115.0
15.0
4.95% Pollution Control Series F Due 2022111.0
111.0
6.02% Series Due 202375.0
75.0
4.90% Series Due 202530.0
30.0
5.10% Series Due 202530.0
30.0
3.20% Series Due 202675.0

5.99% Series Due 202760.0
60.0
5.69% Series Due 203650.0
50.0
6.00% Series Due 204035.0
35.0
5.82% Series Due 204045.0
45.0
4.08% Series Due 204285.0

SWL&P First Mortgage Bonds 7.25% Series Due 201310.0
10.0
Senior Unsecured Notes 5.99% Due 201750.0
50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013 – 202027.5
28.2
Industrial Development Revenue Bonds 6.5% Due 2025
6.0
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 202527.8
27.8
Unsecured Term Loan Variable Rate Due 201475.0
75.0
Other Long-Term Debt, 1.0% – 8.0% Due 2013 – 203741.8
40.3
Total Long-Term Debt1,018.1
863.3
Less: Due Within One Year84.5
5.4
Net Long-Term Debt
$933.6

$857.9

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive covenant requires ALLETE to maintain a ratio of its Funded DebtIndebtedness to Total CapitalCapitalization (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, 2009,2012, our ratio was approximately 0.410.46 to 1.00.1.00. 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. None of ALLETE’s long-term debt arrangements or credit facilities contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. As of December 31, 2009,2012, ALLETE was in compliance with its financial covenants.


Note 11.Commitments, Guarantees and Contingencies
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES

Off-Balance Sheet Arrangements

Power Purchase Agreements.Our long-term power purchase agreements (PPA)PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPA,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 following factors: we have no equity investment in these facilities and do not incur actual or expected losses related to the loss of facility value, andfact that we do not have significantboth control over activities that are most significant to the operations of each of these facilities.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 fixed capacity and energy payments.


ALLETE 2012 Form 10-K
86


NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)

Square Butte Power Purchase Agreement.PPA. Minnesota Power has a power purchase agreementPPA with Square Butte that extends through 2026 (Agreement). It provides a long-term supply of energy to customers in our electric service territory and enables Minnesota Power to meet power pool reserve requirements. Square Butte, a North Dakota cooperative corporation, owns a 455-MW455 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.

ALLETE 2009 Form 10-K
77


Note 11.                      Commitments, Guarantees and Contingencies (Continued)

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the contract.contract, subject to the provisions of the Minnkota Power sales agreement described below. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s fixed costs consist primarily of debt service. At service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2009,2012, Square Butte had total debt outstanding of $351.0 million.$416.9 million. Annual debt service for Square Butte is expected to be approximately $34$44 million in each of the next five years, 20102013 through 2014. Variable operating costs2017, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the pricecost of coal purchased from BNI Coal, our subsidiary, under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during 20092012 was $53.9$67.1 million ($56.7 ($61.2 million in 2008; $57.32011; $55.2 million in 2007)2010). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement in 2009, the 55 percent output entitlement in 2008 and the 60 percent output entitlement in 2007.entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $11.0$11.1 million in 2009 ($11.62012 ($11.1 million in 2008; $11.02011; $10.2 million in 2007)2010). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement.In conjunction with the DC line purchase in December 2009, Minnesota Power entered into a contingent new Power Sales Agreementpower sales agreement with Minnkota Power. Under the new Power Sales Agreement,power sales agreement, Minnesota Power will be able to sell a portion of ourits output from Square Butte to Minnkota Power, resulting in Minnkota’sMinnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025.2025.

No power will be sold under thisthe 2009 agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late 2013.2013. This new AC transmission line will allow Minnkota Power to transmit theirits entitlement from Square Butte directly to theirits customers, and allowwhich in turn will enable Minnesota Power the ability to transmit additional capacitywind generation on the recently acquiredexisting DC line to transmit new wind generation.transmission line.

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

Oliver Wind I and II PPAs. In 2006 and 2007, Minnesota Power Purchase Agreements. We haveentered into two long-term wind power purchase agreementsPPAs with an affiliate of NextEra Energy, Inc. to purchase the output from two wind facilities, Oliver Wind I (50 MWs)(50 MW) and Oliver Wind II (48 MWs),(48 MW)—wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities.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 Purchase Agreement. We also havehas a power purchase agreementlong-term PPA with Manitoba Hydro that began in May 2009 and expires in April 2015.2015. Under thethis agreement with Manitoba Hydro, Minnesota Power will purchase is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

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


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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)

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

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

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

On July 7, 2009,Our Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity. Bison 1 is an 82 MW wind facility in North Dakota, which was completed in two phases. The first phase was completed in 2010, and the second phase was completed in January 2012. The project also included construction of a 22-mile, 230 kV transmission line. Bison 1 had a total project cost of $174.9 million through December 31, 2012, including additional costs related to land restoration and completion of remaining associated upgrades to the 250 kV DC transmission line.

The 105 MW Bison 2 and 105 MW Bison 3 wind facilities in North Dakota were completed in December 2012. Total project costs for Bison 2 and Bison 3 were $148.6 million and $149.8 million, respectively, through December 31, 2012. In September 2011 and November 2011, the MPUC approved our petitionMinnesota Power’s petitions seeking current cost recovery offor investments and expenditures related to Bison I2 and Bison 3, respectively.

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated transmission upgrades.with Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will help fulfill the 2025 renewable energy supply requirement for our retail load. Bison I, located near Center, North Dakota, will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 MWs and will be phased into service in late 2010 and 2011.1. We anticipate filing a cost recovery petition with the MPUC in the first quarter 2010half of 2013 to establishupdate customer billing rates for the approved cost recovery.Bison 1 and to include investments and expenditures associated with Bison 2 and Bison 3.

On September 29, 2009,Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the NDPSC authorized site constructionpurchase of a significant portion of our coal requirements with expiration dates through 2014. We also have coal transportation agreements in place for Bison I. On October 2, 2009,the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements is $51.4 million for 2013 and $0.8 million for 2014. Our minimum annual payment obligation will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power filed a route permit application withPower’s generation are recoverable from Minnesota Power’s utility customers through the NDPSC for a 22 mile, 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. An order is expected in the first quarter 2010.fuel adjustment clause.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8$2.8 million annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at a fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0$3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is $8.8$11.5 million in 2010, $8.92013, $11.7 million in 2011, $9.02014, $11.4 million in 2012, $8.52015, $9.3 million in 2013, $8.22016, $8.5 million in 20142017 and $45.7$35.0 million thereafter. Total rent and lease expense was $9.3$11.5 million in 2009 ($8.52012 ($9.4 million in 2008; $8.42011; $9.4 million in 2007)2010).

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


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NoteNOTE 11. Commitments, Guarantees and ContingenciesCOMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)

Transmission Investments.Coal, Rail and Shipping Contracts. We have two primary coal supply agreements with expiration dates through Decemberan approved cost recovery rider in place for certain transmission investments and expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. We also have rail and shipping agreementsThe billing factor allows us to charge our retail customers on a current basis for the transportationcosts of allconstructing certain transmission facilities plus a return on the capital invested. In June 2011, we filed an updated billing factor that includes additional transmission expenditures, which we expect to be approved in the first quarter of our coal, with expiration dates2013.

CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through January2020. Studies show that the region’s transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

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

Based on projected costs of the three transmission lines and shippingthe allocation agreements contain optionsamong participating utilities, Minnesota Power plans to extendinvest between $100 million and $110 million in the agreements,CapX2020 initiative through 2015. A total of $48.2 million was spent through December 31, 2012, of which options$37.3 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($27.8 million as of December 31, 2011 of which $20.4 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $7.4 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may exercise unilaterally. The term extensions are for an additional two year term and an additional four year term. Our minimum annual payment obligations under these coal, rail and shipping agreements are currently $35.7 million in 2010 and $7.6 million in 2011, with no specific commitments beyond 2011. Our minimum annual payment obligations will increase when annual nominations are made for coal deliveries in future years.elect to participate on a project-by-project basis.


Environmental Matters.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 the Congress and the EPA. Most notably, clean energy technologies and the regulation of GHGs have taken a lead in these discussions. Minnesota Power’s fossil fueledfuel facilities will likely to be subject to regulation under these climate change policies.proposals. Our intention is to reduce our exposure to possible future carbon and GHG legislationthese 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. These accrualsAccruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomebecomes available. Accruals for environmental liabilities are included in the consolidated balance sheetConsolidated 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.Clean Air Act. The electric utility industry is heavily regulated both at the federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2and system-wide average NOX limits.state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of theseMinnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses or electrostatic precipitators. Minnesota Power’s generatingand low NOX technologies. Under currently applicable environmental regulations, these facilities are currently in compliancesubstantially compliant with applicable emission requirements.


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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

New Source Review. Review (NSR)On. In August 8, 2008, Minnesota Power received a Notice of Violation (NOV) from the United States EPA asserting violations of the New Source Review (NSR)NSR requirements of the Clean Air Act at Boswell Units 1-41, 2, 3 and 4 and Laskin Unit 2. The NOV also asserts that the Boswell Unit 4 Title V permit was violated, and that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements.requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits.

Resolution of the NOVs could result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predictestimate the outcomeexpenditures, or range of these discussions. Since 2006, Minnesota Power has significantly reduced, and continues to reduce, emissions at Boswell and Laskin. The resolution could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements.expenditures that may be required upon resolution. Any costs of installing additional pollution control technologyequipment would likely be eligible for recovery in rates over time subject to MPUC and FERCregulatory approval in a rate proceeding.

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

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

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

EPA Clean Air Interstate Rule. In March 2005, the EPA announced the Clean Air Interstate Rule (CAIR) that sought to reduce and permanently cap emissions of SO2, NOX, and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit (Court) vacated the CAIR and remanded the rulemaking to the EPA for reconsideration while also granting our petition that the EPA reconsider including Minnesota as a CAIR state. In September 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested that the CAIR be remanded without a court order. In December 2008, the Court granted the request that the CAIR be remanded without a court order, effectively reinstating a January 1, 2009 compliance date for the CAIR, including Minnesota. However, in the May 12, 2009 Federal Register the EPA issued a proposed rule that would amend the CAIR to stay its effectiveness with respect to Minnesota until completion of the EPA’s determination of whether Minnesota should be included as a CAIR state. The formal administrative stay of CAIR for Minnesota was published in the November 3, 2009, Federal Register with an effective date of December 3, 2009.

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Note 11.Commitments, Guarantees and Contingencies (Continued)
Environmental Matters (Continued)

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

Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007, the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was never filed due to the Court’s review of CAIR as more fully described above under “EPA Clean Air Interstate Rule.” Subsequently, theThe MPCA requested that companies with BART eligibleBART-eligible units complete and submit a BART emissions control retrofit study, which was done oncompleted for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirementrequirements for that unit. OnIn December 15, 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA.


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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

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

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register on February 16, 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that they have approved Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas addressing the MATS requirements.

EPA National Emission Standards for Hazardous Air Pollutants.Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2005,2011, a final rule was published in the Federal Register for industrial boiler maximum achievable control technology (Industrial Boiler MACT). The rule was stayed by the EPA also announcedin May 2011, to allow the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped electric utility mercury emissionsEPA time to consider additional comments received. The EPA re-proposed the rule in the continental United States through a cap-and-trade program. In February 2008,December 2011. On January 9, 2012, the United States District Court of Appeals for the District of Columbia Circuit vacated the CAMR and remanded the rulemaking toruled that the EPA for reconsideration. In October 2008,stay of the EPA petitionedIndustrial Boiler MACT was unlawful, effectively reinstating the Supreme CourtMarch 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released on December 21, 2012. Major sources have three years to reviewachieve compliance with the Court’s decisionfinal rule. Minnesota Power is in the CAMR case. In January 2009,process of assessing the EPA withdrew its petition, pavingimpact of this rule on our affected units including the way for possible regulation of mercuryHibbard Renewable Energy Center and other hazardous air pollutant emissions through Section 112 of the Clean Air Act, setting Maximum Achievable Control Technology standards for the utility sector. In December 2009, Minnesota Power and other utilities received an Information Collection Request from the EPA, requiring that emissions data be provided and stack testing be performed in order to develop an improved database with which to base future regulations. Cost estimatesRapids Energy Center. Costs for complying with potential future mercury and other hazardous air pollutant regulations under the Clean Air Actfinal rule cannot be estimated at this time.

Minnesota Mercury EmissionEmissions Reduction Act.Act This legislation requires. Under the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power is required to fileimplement a mercury emissionemissions reduction plansproject for Boswell Units 3 andUnit 4 with a goal of 90 percent reduction in mercury emissions. The Boswell Unit 3 emission reduction plan wasby December 31, 2018. On August 31, 2012, Minnesota Power filed with the MPCA in October 2006. Mercury control equipment has been installed and was placed into service in November 2009. (See Item 1. Business – Regulated Operations – Minnesota Public Utilities Commission – Emission Reduction Plans.) Aits mercury emissions reduction plan for Boswell Unit 4 is required by July 1, 2011, with implementation no later than December 31, 2014.the MPUC and the MPCA. The legislation calls forplan proposes that Minnesota Power install pollution controls to address both the Minnesota mercury emissions reduction requirements and the MATS rule, which also regulates mercury emissions. Minnesota Power's request of an evaluationadditional year extending the date of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’s customers. Cost estimatescompliance for the Boswell Unit 4 emissionretrofit to April 1, 2016, was approved by the MPCA. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are not available at this time.included in the estimated capital expenditures required for compliance with the MATS rule discussed above.

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

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to reducerevise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA was scheduled to decide upon the 2008 eight-hour ozone standard in July 2011, but has since announced that it is deferring revision of this standard until 2013.


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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM2.5) standard; the annual PM2.5 standard and the 24-hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM2.5 standards on June 14, 2012.

On December 14, 2012, the EPA confirmed in a final rule that the current annual PM2.5 standard, which has been in place since 1997, will be lowered, while retaining the current 24-hour PM2.5 standard. To implement the new lower annual PM2.5 standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects stating rulesand permits must comply with the new lower standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling. To bridge the transition to addressthe lower standard, the EPA is finalizing a grandfathering provision to ensure that projects and pending permits already underway are not unduly delayed.

Under the final rule, states will be responsible for additional PM2.5 monitoring, which will likely be accomplished by relocation or repurposing of existing monitors. States are expected to propose attainment designations by December 2013, based on already available monitoring data. The EPA believes that most U.S. counties currently already meet the new standard and plans to finalize designations of attainment by December 2014. For those counties that the EPA does not designate as having already met the requirements of the new standard, specific dates for required attainment will depend on technology availability, state permitting goals, potential legal challenges and other factors.

SO2 and NO2 NAAQS. During 2010, the EPA finalized new one-hour NAAQS for SO2 and NO2. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO2 NAAQS also require the EPA to evaluate modeling data to determine attainment. The EPA has notified states that their SIPs for attainment of these new, more stringent standardsthe standard will be required to be submitted to the EPA for approval by June 2013 but will not be required to include the evaluation of modeling data until December 2013.2017.

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

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

Expand our renewable energy supply;
Provide energy conservation initiatives for our customers and engage in other demand side efforts;
Support research of technologies to reduce carbon emissions from generation facilities and carbon sequestration efforts; and
Evaluating and developing less carbon intense future generating assets such as efficient and flexible natural gas generating facilities.

EPA Greenhouse Gas Reporting RuleRegulation of GHG Emissions.. On September 22, 2009, In May 2010, the EPA issued the final rule mandating that certain GHG emission sources, including electric generating units, are required to report emission levels. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule was effective January 1, 2010, and all GHG emissions must be reported on an annual basis by March 31 of the following year. Currently, we have the equipment and data tools necessary to report our 2010 emissions to comply with this rule.

Title V Greenhouse Gas Tailoring Rule. On October 27, 2009, the EPA issued the proposed Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring rule. This proposed regulation addresses the six primary greenhouse gases and newRule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds for when permits will be required to address GHG emissions for new facilities, andat existing facilities whichthat undergo major modifications. The rule would require large industrialmodifications and at other facilities including power plants, to obtain construction and operating permits that demonstrate Best Available Control Technologies (BACT) are being used atcharacterized as major sources under the facility to minimize GHG emissions. The EPA is expected to propose BACT standards for GHG emissions from stationary sources.

Clean Air Act’s Title V program. For our existing facilities, the proposed rule does not require amending our existing Title V operating permits to include BACT for GHGs.GHG requirements. However, modifying or installing units with GHG emissions that trigger the PSD permitting requirements could require amendingare likely to be added to our existing Title V operating permits to incorporate BACT to control GHG emissions.by the MPCA as these permits are renewed or amended.


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Note 11.Commitments, Guarantees and ContingenciesNOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

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

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

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

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

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

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

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

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


ALLETE 2012 Form 10-K
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NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

EPA Endangerment Findings. On December 15, 2009, the EPA published its findings that the emissions of six GHG, including CO2, methane, and nitrous oxide, endanger human health or welfare. This finding may result in regulations that establish motor vehicle GHG emissions standards in 2010. There is also a possibility that the endangerment finding will enable expansion of the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. with the United States District Court Circuit Court of Appeals on December 23, 2009.

Coal Ash Management Facilities.Facilities. Minnesota Power generates coal ash at all five of its steamcoal-fired electric stations.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. Minnesota Power continues to monitor state and federal legislative andIn June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory activities that may affect its ash management practices. The USEPA is expected to propose new regulationsschemes for coal ash. Comments on the proposed rule were due in February 2010, pertaining to the management of coal ash by electric utilities.November 2010. It is unknown how potential coal ash managementestimated that the final rule changes will affect Minnesota Power’s facilities. On March 9, 2009,be published in 2013. We are unable to predict the EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received ancompliance costs we might incur; however, the costs could be material. We would seek recovery of any additional EPA information request pertaining to Boswell. Minnesota Power responded to both these information requests. On August 19, 2009, Dam Safety officials from the Minnesota DNR visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findingscosts through cost recovery riders or concerns from the DNR staff during the inspections.in a general rate case.

Other Matters

BNI Coal.Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site within the City As of Superior, Wisconsin and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. At December 31, 2009 we have a $0.5 million liability for this site, and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.2012

BNI Coal. As of December 31, 2009,, BNI Coal had surety bonds outstanding of $18.4$29.8 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, an additional guaranteeassurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a Letterletter of Creditcredit with CoBANK ACB for an additional $10.0$2.6 million of which $6.7 million is needed to meet the requirementsprovide for BNI’sBNI Coal’s total reclamation liability, which is currently estimated at $25.1 million.$32.4 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties.As of December 31, 2009,2012, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of $19.1credit to governmental entities totaling $10.2 million primarily related to performancedevelopment and maintenance obligations to governmental entities to construct improvements in the company’sfor various projects. The estimated cost of the remaining development work to be completed on these improvements is estimated to be approximately $10.2$7.4 million and, of which $0.6 million is the contractual obligation of land purchasers. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4$26.4 million of tax-exempt, 6 percent Capital Improvement Revenue Bonds, Series 2005;capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued $31.8$31.8 million of tax-exempt, 5.7 percent Special Assessment Bonds, Series 2006.special assessment bonds. The Capital Improvement Revenue Bondscapital improvement revenue bonds and the Special Assessment Bondsspecial assessment bonds are payable through property tax assessments on the land owners over 31 years (by May 1, 2036 and 2037, respectively). and secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The bonds are payable from and secured by the revenue derived from assessments imposed, levied and collected by each district. The assessments were billed to the landowners beginning in November 2006 for Town Center and November 2007 for Palm Coast Park. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At December 31, 2009,2012, we owned 6973 percent of the assessable land in the Town Center District (69(73 percent at December 31, 2008)2011) and 8693 percent of the assessable land in the Palm Coast Park District (86(93 percent at December 31, 2008)2011). At these ownership levels, our annual assessments are $1.4approximately $1.4 million for Town Center and $1.9$2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. Under currentIn accordance with accounting rules,guidance, these bonds are not reflected as debt on our consolidated balance sheet.Consolidated Balance Sheet.

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

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



ALLETE 20092012 Form 10-K
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Note 12.Common Stock and Earnings Per Share
NOTE 12. COMMON STOCK AND EARNINGS PER SHARE

Summary of Common StockSharesEquity
 ThousandsMillions
Balance as of December 31, 200630,436$438.7
2007   Employee Stock Purchase Plan170.7
Invest Direct33115.1
Options and Stock Awards436.7
Balance as of December 31, 200730,827$461.2
2008   Employee Stock Purchase Plan170.6
Invest Direct1616.9
Options and Stock Awards244.6
Equity Issuance Program1,55660.8
Balance as of December 31, 200832,585$534.1
2009   Employee Stock Purchase Plan240.7
Invest Direct45613.6
Options and Stock Awards81.1
Equity Issuance Program1,68551.9
Contributions to Pension46312.0
Balance as of December 31, 200935,221$613.4
Summary of Common StockSharesEquity
 ThousandsMillions
Balance as of December 31, 200935,221

$613.4
Employee Stock Purchase Program19
0.6
Invest Direct346
11.7
Options and Stock Awards51
4.4
Equity Issuance Program180
6.0
Balance as of December 31, 201035,817

$636.1
Employee Stock Purchase Program20
0.8
Invest Direct437
17.2
Options and Stock Awards109
6.7
Equity Issuance Program400
16.0
Purchase of Non-Controlling Interest222
8.8
Contributions to Pension508
20.0
Balance as of December 31, 201137,513

$705.6
Employee Stock Purchase Program20
0.8
Invest Direct474
19.2
Options and Stock Awards95
6.0
Equity Issuance Program1,275
53.1
Balance as of December 31, 201239,377

$784.7

Equity Issuance Program. We entered into a Distribution Agreementdistribution agreement with KCCI, Inc., originating in February 2008, and subsequentlyas amended in February 2009,most recently on August 3, 2012, with respect to the issuance and sale of up to an aggregate of 6.69.6 million shares of our common stock, without par value.value, of which 4.5 million remain available for issuance. For the year ended December 31, 2012, 1.3 million shares of common stock were issued under this agreement resulting in net proceeds of $53.1 million. During 2011, 0.4 million shares of common stock were issued for net proceeds of $16.0 million. The shares issued in 2012 and 2011 were, and the remaining shares may be, offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-147965. During 2009, 1.7 million shares of common stock were issued under this agreement resulting in net proceeds of $51.9 million. In 2008, 1.6 million shares were issued for net proceeds of $60.8 million. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.)333-170289.

Contributions to Pension. In March 2009, we contributed 0.5 shares of ALLETE common stock, with an aggregate value of $12.0 million, to our pension plan. On May 19, 2009, we registered the 0.5 shares of ALLETE common stock with the SEC pursuant to Registration Statement No. 333-147965. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.)

Authorized Common Stock. On May 12, 2009, shareholders approved an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from 43.3 million to 80.0 million.

Shareholder Rights Plan. On July 25, 1996, ALLETE adopted a shareholder rights plan, which was amended and restated on July 12, 2006 (collectively, the “Rights Plan”). The amendment to the Rights Plan, among other things, extended the final expiration date of the Rights Plan to July 11, 2009. The Rights Plan expired according to its terms on July 11, 2009. As a result, ALLETE’s preferred share purchase rights issued in accordance with the Rights Plan are no longer outstanding.

Earnings Per Share. The difference between basic and diluted earnings per share, arises, if any, arises from outstanding stock options, non-vested restricted stock, and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. In 2012, in accordance with accounting standards for earnings per share, for 2009, 0.60.2 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices, andprices; therefore, their effect would behave been anti-dilutive (0.6(0.3 million shares were excluded in 2011 and 0.5 million in 2010).

Purchase of Non-Controlling Interest. In 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased at book value for 2008 and $8.8 million by issuing 0.2 million unregistered shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss is recognized in 2007).net income or comprehensive income.

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


ALLETE 20092012 Form 10-K
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82


Note 12.Common Stock and Earnings Per ShareNOTE 12. COMMON STOCK AND EARNINGS PER SHARE (Continued)

Reconciliation of Basic and Diluted   
Earnings Per Share Dilutive 
Year Ended December 31BasicSecuritiesDiluted
Millions Except Per Share Amounts   
    
2009   
Net Income Attributable to ALLETE$61.0$61.0
Common Shares32.232.2
Per Share of Common Stock$1.89$1.89
    
2008   
Net Income Attributable to ALLETE$82.5$82.5
Common Shares29.20.129.3
Per Share of Common Stock$2.82$2.82
    
2007   
Net Income Attributable to ALLETE$87.6$87.6
Common Shares28.30.128.4
Per Share of Common Stock$3.09$3.08
Reconciliation of Basic and Diluted   
Earnings Per Share Dilutive
 
Year Ended December 31BasicSecurities
Diluted
Millions Except Per Share Amounts   
2012   
Net Income Attributable to ALLETE
$97.1



$97.1
Average Common Shares37.6

37.6
Earnings Per Share
$2.59



$2.58
2011   
Net Income Attributable to ALLETE
$93.8



$93.8
Average Common Shares35.3
0.1
35.4
Earnings Per Share
$2.66



$2.65
2010   
Net Income Attributable to ALLETE
$75.3



$75.3
Average Common Shares34.2
0.1
34.3
Earnings Per Share
$2.20



$2.19


Note 13.Other Income (Expense)
NOTE 13. OTHER INCOME (EXPENSE)

Year Ended December 31200920082007
Millions   
Loss on Emerging Technology Investments$(4.6)$(0.7)$(1.3)
AFUDC - Equity5.83.33.8
Investments and Other Income (a)
0.613.013.0
Total Other Income$1.8$15.6$15.5

(a)In 2008, Investment and Other Income included a gain from the sale of certain available-for-sale securities. The gain was triggered when securities were sold to reallocate investments to meet defined investment allocations based upon an approved investment strategy. In 2007, Investment and Other Income primarily included earnings on excess cash and Minnesota land sales.
Year Ended December 31201220112010
Millions   
AFUDC – Equity
$5.1

$2.5

$4.2
Investment and Other Income0.9
1.9
0.4
Total Other Income
$6.0

$4.4

$4.6



ALLETE 2012 Form 10-K
96


NoteNOTE 14. Income Tax ExpenseINCOME TAX EXPENSE

Income Tax Expense   
Year Ended December 31200920082007
Millions   
Current Tax Expense (Benefit)   
Federal (a)
$(42.6)$6.2$26.5
State(1.8)(1.6)7.2
Total Current Tax Expense (Benefit)(44.4)4.633.7
Deferred Tax Expense   
Federal66.029.310.7
State10.313.44.7
Change in Valuation Allowance(0.1)(2.9)(0.3)
Investment Tax Credit Amortization(1.0)(1.0)(1.1)
Total Deferred Tax Expense75.238.814.0
Total Income Tax Expense$30.8$43.4$47.7

Income Tax Expense   
Year Ended December 31201220112010
Millions   
Current Tax Expense (Benefit)   
Federal (a)

$1.4$(23.0)
State (a)
$0.5(1.6)1.3
Total Current Tax Expense (Benefit)0.5
(0.2)(21.7)
Deferred Tax Expense   
Federal (b)
38.1
27.3
61.4
State (b)
(1.7)9.5
5.3
Change in Valuation Allowance (c)
2.0
(0.1)0.2
Investment Tax Credit Amortization(0.9)(0.9)(0.9)
Total Deferred Tax Expense37.5
35.8
66.0
Total Income Tax Expense
$38.0

$35.6

$44.3
(a)DueFor the years ended December 31, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation provisionsprovision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, a federal current tax benefit was recorded as a result of tax planning initiatives and the bonus depreciation provision in the American Recovery and ReinvestmentSmall Business Jobs Act of 2009, we are in a net operating loss position for 2009.2010. The loss will be2010 federal NOL was partially utilized by carrying it back against prior years’ taxableincome with the remainder carried forward to offset future years’ income.
(b)
For the year ended December 31, 2012, the state deferred tax benefit of $1.7 million is due to state renewable tax credits earned which will be carried forward to offset future state income tax expense. The year ended December 31, 2011, included an income tax benefit for the reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and a benefit of $2.9 million related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. Included in the year ended December 31, 2010, was a charge of $4.0 million as a result of the PPACA. (See Note 5. Regulatory Matters.)
(c)For the year ending December 31, 2012, the change in the valuation allowance is due to state renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

Reconciliation of Taxes from Federal Statutory   
Rate to Total Income Tax Expense   
Year Ended December 31201220112010
Millions   
Income Before Non-Controlling Interest and Income Taxes
$135.1

$129.2

$119.1
Statutory Federal Income Tax Rate35%35%35%
Income Taxes Computed at 35 percent Statutory Federal Rate
$47.3

$45.2

$41.7
Increase (Decrease) in Tax Due to:   
State Income Taxes – Net of Federal Income Tax Benefit1.2
6.0
4.5
Impact of the PPACA

4.0
Deferred Accounting for Retail Portion of the PPACA
(2.9)
2010 Rate Case Stipulation Agreement - Deferred Tax Reversal
(6.2)
Regulatory Differences for Utility Plant(2.2)(1.2)(2.0)
Production Tax Credits(7.6)(4.3)(1.6)
Other(0.7)(1.0)(2.3)
Total Income Tax Expense
$38.0

$35.6

$44.3



ALLETE 20092012 Form 10-K
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Note 14.Income Tax ExpenseNOTE 14. INCOME TAX EXPENSE (Continued)

Reconciliation of Taxes from Federal Statutory   
Rate to Total Income Tax Expense   
Year Ended December 31200920082007
Millions   
Income Before Non-Controlling Interest and Income Taxes$91.5$126.4$137.2
Statutory Federal Income Tax Rate35%35%35%
Income Taxes Computed at 35 percent Statutory Federal Rate$32.0$44.2$48.0
Increase (Decrease) in Tax Due to:   
Amortization of Deferred Investment Tax Credits(1.0)(1.0)(1.1)
State Income Taxes – Net of Federal Income Tax Benefit5.44.87.4
Depletion(0.9)(0.8)(0.9)
Regulatory Differences for Utility Plant(2.5)(1.6)(2.2)
Production Tax Credit(1.2)(0.4)
Positive Resolution of Audit Issues(1.6)
Other(1.0)(1.8)(1.9)
Total Income Tax Expense$30.8$43.4$47.7

The effective tax rate on income from continuing operations before non-controlling interest was 33.728.1 percent for 2009; (34.32012 (27.6 percent for 2008; 34.82011; 37.2 percent for 2007)2010). The 20092012 effective tax rate was primarily impacted by deductionsrenewable tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above), investment tax credits, wind production tax credits and depletion.. The 20082011 effective tax rate was primarily impacted by deductionsthe deduction for AFUDC-Equity, (included in Regulatory Differences for Utility Plant, above), investment tax credits, wind production tax credits, depletion, recognition of a benefit on the reversal of a previously uncertaindeferred tax position ($1.7 million included in Other, above) andliability related to a benefit for the reversalrevenue receivable that Minnesota Power agreed to forgo as part of a state incomestipulation and settlement agreement in its 2010 rate case, renewable tax valuation allowance ($2.9 million includedcredits, and the MPUC’s approval of our request to defer the retail portion of the tax charge taken in State Income Taxes, above).2010 as a result of the PPACA. The 2010 effective tax rate was primarily impacted by the PPACA eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, the deduction for AFUDC-Equity, and renewable tax credits.

Deferred Tax Assets and Liabilities  
As of December 3120092008
Millions  
Deferred Tax Assets  
Employee Benefits and Compensation (a)
$118.2$125.2
Property Related46.536.4
Investment Tax Credits10.010.7
Other14.416.3
Gross Deferred Tax Assets189.1188.6
Deferred Tax Asset Valuation Allowance(0.3)(0.4)
Total Deferred Tax Assets$188.8$188.2
Deferred Tax Liabilities  
Property Related$294.1$235.6
Regulatory Asset for Benefit Obligations96.587.7
Unamortized Investment Tax Credits14.115.1
Partnership Basis Differences14.63.7
Other28.216.8
Total Deferred Tax Liabilities$447.5$358.9
Net Deferred Income Taxes$258.7$170.7
   
Recorded as:  
Net Current Deferred Tax Liabilities (b)
$5.6$1.1
Net Long-Term Deferred Tax Liabilities253.1169.6
Net Deferred Income Taxes$258.7$170.7

Deferred Tax Assets and Liabilities  
As of December 3120122011
Millions  
Deferred Tax Assets  
Employee Benefits and Compensation
$120.2

$132.7
Property Related59.8
56.4
NOL Carryforwards90.8
61.7
Tax Credit Carryforwards28.3
12.2
Other24.6
20.4
Gross Deferred Tax Assets323.7
283.4
Deferred Tax Asset Valuation Allowance(2.4)(0.4)
Total Deferred Tax Assets
$321.3

$283.0
Deferred Tax Liabilities  
Property Related
$577.1

$482.7
Regulatory Asset for Benefit Obligations104.3
117.9
Unamortized Investment Tax Credits11.9
12.8
Partnership Basis Differences28.6
24.4
Other30.1
24.0
Total Deferred Tax Liabilities
$752.0

$661.8
Net Deferred Income Taxes
$430.7

$378.8
Recorded as:  
Net Current Deferred Tax Liabilities (a)

$6.9

$5.2
Net Long-Term Deferred Tax Liabilities423.8
373.6
Net Deferred Income Taxes
$430.7

$378.8
(a)Includes Unfunded Employee Benefits
(b)(a)Included in Other Current Liabilities.

NOL and Tax Credit Carryforwards  
Year Ended December 3120122011
Millions  
Federal NOL carryforwards (a)

$244.1

$162.0
Federal tax credit carryforwards$16.0$8.4
State NOL carryforwards (a) (b)
$90.6$73.1
State tax credit carryforwards (c)
$10.3$3.8
(a)Pretax amounts
(b)
Net of $0.4 million valuation allowance.
(c)
Net of $2.0 million valuation allowance.


ALLETE 2012 Form 10-K
98


NOTE 14. INCOME TAX EXPENSE (Continued)

As of December 31, 2009In 2012, we had agenerated federal net operating loss of $85.7 millionand various state NOLs and tax credit carryforwards primarily due to the bonus depreciation provisions inof the American RecoveryTax Relief, Unemployment Insurance Reauthorization, and ReinvestmentJob Creation Act of 2009. In 2010, this2010. The 2012 federal net operating lossNOL will be fully utilized by carrying it back against priorforward to offset future years’ taxable income. We also have various state net operating lossThe federal NOL and tax credit carryforward periods expire between 2019 and 2032; included in the federal NOL carryforward are charitable contribution carryforwards totaling $23.8 million available to reduce future taxable income.which expire between 2014 and 2016. We expect to fully utilize the federal NOL, charitable contributions, and federal tax benefitcredit carryforwards; therefore no valuation allowance has been recognized as of these losses prior to their expirations in 2024 through 2029.

ALLETE 2009 Form 10-K
84


Note 14.Income Tax Expense (Continued)

Gross Unrecognized Income Tax Benefits200920082007
Millions   
Balance at January 1$8.0$5.3$10.4
Additions for Tax Positions Related to the Current Year0.50.70.8
Reductions for Tax Positions Related to the Current Year
Additions for Tax Positions Related to Prior Years1.04.5
Reduction for Tax Positions Related to Prior Years(2.5)(2.4)
Settlements(3.5)
Balance as of December 31$9.5$8.0$5.3
December 31, 2012.

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

Gross Unrecognized Income Tax Benefits201220112010
Millions   
Balance at January 1
$11.4

$12.3

$9.5
Reductions for Tax Positions Related to the Current Year

(0.2)
Additions for Tax Positions Related to Prior Years

4.4
Reductions for Tax Positions Related to Prior Years(8.7)(0.9)
Reductions for Settlements

(0.3)
Reductions for Expired Statute of Limitations

(1.1)
Balance as of December 31
$2.7

$11.4

$12.3

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

The gross amount of unrecognized tax benefits as of December 31, 2009,2012, includes $1.5$0.5 million of net unrecognized tax benefits that, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $8.7 million in 2012 was due to the removal of our uncertain tax position for our tax accounting method change for deductible repairs. During 2012, the IRS issued a directive from its Large Business and International Division to its local examination teams that led to the removal of the repairs uncertain tax position in 2012.

As of December 31, 2009,2012, we had $0.9$0.5 million ($0.6 ($1.1 million for 2008)2011 and $0.7 million for 2010) of accrued interest related to unrecognized tax benefits included in the consolidated balance sheet.our Consolidated Balance Sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in the consolidated statementour Consolidated Statement of income.Income. In 2009,2012, we recognized $0.4a $0.6 million decrease in interest expense (interest expense of $0.4 million for 2011 and a reduction of interest expense ($0.4of $0.2 million for 2008 and $0.1 million for 2007)2010). There were no penalties recognized for 2009, 2008in 2012, 2011 or 2007.2010.

WeALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE is currently under examination by the United States and various state jurisdictions.IRS for the tax years 2005 through 2009. ALLETE is no longer subject to federal or state examination for years before 2005 or state examinations for years before 2004.2005.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $3.6$2.5 million due to statute expirations and anticipated audit settlements. This amount is primarily due to timing issues.temporary tax positions.



Note 15.Other Comprehensive Income (Loss)
ALLETE 2012 Form 10-K
99


Other Comprehensive Income (Loss)   
Year Ended December 31200920082007
Millions   
Net Income$60.7$83.0$89.5
Other Comprehensive Income   
    Unrealized Gain on Securities
   Net of income taxes of $1.7, $(3.7), and $0.3
2.8(6.0)1.1
    Reclassification Adjustment for Losses Included in Income
      Net of income taxes of $–, $(2.7), and $–
(3.7)
    Defined Benefit Pension and Other Postretirement Plans
   Net of income taxes of $4.1, $(13.3), and $2.3
6.2(18.8)3.2
Total Other Comprehensive Income (Loss)9.0(28.5)4.3
Total Comprehensive Income$69.7$54.5$93.8
Less: Non-Controlling Interest in Subsidiaries(0.3)0.51.9
Comprehensive Income Attributable to ALLETE$70.0$54.0$91.9


Accumulated Other Comprehensive Income (Loss)  
As of December 3120092008
Millions  
Unrealized Gain (Loss) on Securities$(1.8)$(4.6)
Defined Benefit Pension and Other Postretirement Plans(22.2)(28.4)
Total Accumulated Other Comprehensive Loss$(24.0)$(33.0)


Note 16.                Pension and Other Postretirement Benefit PlansNOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. In 2009,2012, we made a total contributions of $32.9$7.3 million ($10.9 ($33.8 million in 2008) in contributions to ALLETE’s defined benefit pension plans2011, of which $12.0$20.0 million was contributed in shares of ALLETE common stock.stock). We also have a defined contribution pension plansplan covering substantially all employees. The 20092012 plan year employer contributions, which are made through ourthe employee stock ownership plan portion of the RSOP, totaled $9.1$7.7 million ($7.1 ($7.3 million for the 20082011 plan year.) (See Note 12. Common Stock and Earnings Per Share and Note 17.16. Employee Stock and Incentive Plans)

ALLETE 2009 Form 10-K
85


Note 16.Pension and Other Postretirement Benefit Plans (Continued)
.

In 2006, amendments were made to the non-union defined benefit pension plan and the Retirement Savings and stock Ownership Plan (RSOP). The non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and closedto close the plan to new participants. In conjunction with the change,those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.

We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to age 55 with 10 years of participation in the plan. The postretirement health plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and an irrevocable grantor trusts.trust. In 20092012, $1.5 million was contributed to the VEBAs. In 2011, we contributed $10.9 million to the VEBAs. There were no contributions made a net contribution of $0.3 million to the grantor trust in 2012and $9.3 million to the VEBAs. In 2008 $3.7 million was contributed to the VEBAs.2011.

Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the pension plans. Estimated defined benefit pension contributions for years 2010 through 2014 are expected to be up to $25 million per year, andContributions are based on estimates and assumptions thatwhich are subject to change. Funding forWe do not expect to make any contributions to the other postretirementdefined benefit plans is impacted by utility regulatory requirements. Estimatedpension plan in 2013. In January 2013, we contributed $4.8 million to the defined benefit postretirement health and life plan, of which $2.0 million was contributed to an irrevocable grantor trust and $2.8 million was contributed to the VEBAs. We do not expect to make any additional contributions for years 2010 through 2014 are approximately $11 million per year,to the defined benefit postretirement health and are based on estimates and assumptions that are subject to change.life plan in 2013.

Accounting for Defined Benefit Pensiondefined benefit pension and Postretirement Benefit Planspostretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their consolidated balance sheetConsolidated 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 that are not recognized as components of net periodic benefit cost.

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


During the year ended December 31, 2008, we were required to change our measurement date from September 30 to December 31. On January 1, 2008,
ALLETE recorded three months of pension expense as a reduction to retained earnings in the amount of $1.6 million, net of tax, to reflect the impact of this measurement date change. Also on January 1, 2008, we recorded $0.8 million relating to three months of amortization for transition obligations, prior service costs, and prior gains and losses within accumulated other comprehensive income.2012 Form 10-K
100


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

Pension Obligation and Funded Status
Year Ended December 3120092008
Millions  
Accumulated Benefit Obligation$435.9$406.6
   
Change in Benefit Obligation  
Obligation, Beginning of Year$440.4$421.9
Service Cost5.77.3
Interest Cost26.231.8
Actuarial Loss (Gain)14.63.2
Benefits Paid(25.5)(29.9)
Participant Contributions3.96.1
Obligation, End of Year$465.3$440.4
Change in Plan Assets  
Fair Value, Beginning of Year$273.7$405.6
Actual Return on Plan Assets41.6(120.2)
Employer Contribution37.818.2
Benefits Paid(25.5)(29.9)
Fair Value, End of Year$327.6$273.7
Funded Status, End of Year$(137.7)$(166.7)
   
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:  
Current Liabilities$(0.9)$(0.9)
Noncurrent Liabilities$(136.8)$(165.8)

ALLETE 2009 Form 10-K
86


Note 16.Pension and Other Postretirement Benefit Plans (Continued)
Pension Obligation and Funded Status
Year Ended December 3120122011
Millions  
Accumulated Benefit Obligation
$598.7

$550.6
Change in Benefit Obligation 
 
Obligation, Beginning of Year
$597.5

$525.6
Service Cost9.1
7.6
Interest Cost26.4
27.4
Actuarial Loss38.5
54.6
Benefits Paid(30.9)(28.6)
Participant Contributions11.5
10.9
Obligation, End of Year
$652.1

$597.5
Change in Plan Assets 
 
Fair Value, Beginning of Year
$432.4

$382.0
Actual Return on Plan Assets38.7
33.2
Employer Contribution19.9
45.8
Benefits Paid(30.9)(28.6)
Fair Value, End of Year
$460.1

$432.4
Funded Status, End of Year$(192.0)$(165.1)
   
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of: 
 
Current Liabilities$(1.1)$(1.1)
Non-Current Liabilities$(190.9)$(164.0)

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

Unrecognized Pension Costs
Year Ended December 312009 2008
Millions  
Net Loss$196.5$193.2
Prior Service Cost1.82.4
Transition Obligation
Total Unrecognized Pension Costs$198.3$195.6
Unrecognized Pension Costs
Year Ended December 3120122011
Millions  
Net Loss
$286.8

$269.0
Prior Service Cost0.7
1.1
Total Unrecognized Pension Costs
$287.5

$270.1


Components of Net Periodic Pension Expense
Year Ended December 31200920082007
Millions   
Service Cost$5.7$5.8$5.3
Interest Cost26.225.423.4
Expected Return on Plan Assets(33.8)(32.5)(30.6)
Amortization of Loss3.41.64.9
Amortization of Prior Service Costs0.60.60.6
Net Pension Expense$2.1$0.9$3.6


Other Changes in Pension Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income and Regulatory Assets
Year Ended December 3120092008
Millions  
Net Loss (Gain)$6.8$164.0
Amortization of Prior Service Costs(0.6)(0.6)
Amortization of Loss (Gain)(3.4)(1.6)
Total Recognized in Other Comprehensive Income and Regulatory Assets$2.8$161.8


Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 3120092008
Millions            
Projected Benefit Obligation$465.3$440.4
Accumulated Benefit Obligation$435.9$406.6
Fair Value of Plan Assets$327.6$273.7
Components of Net Periodic Pension Expense
Year Ended December 31201220112010
Millions   
Service Cost
$9.1

$7.6

$6.2
Interest Cost26.4
27.4
26.2
Expected Return on Plan Assets(35.4)(34.6)(33.7)
Amortization of Loss17.5
12.1
6.6
Amortization of Prior Service Cost0.3
0.3
0.5
Net Pension Expense
$17.9

$12.8

$5.8


ALLETE 20092012 Form 10-K
101

87


Note 16.Pension and Other Postretirement Benefit PlansNOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Postretirement Health and Life Obligation and Funded Status
Year Ended December 3120092008
Millions  
Change in Benefit Obligation  
Obligation, Beginning of Year$166.9$153.7
Service Cost4.15.0
Interest Cost10.011.7
Actuarial Loss18.44.0
Participant Contributions1.72.0
Plan Amendments(1.3)
Benefits Paid(7.7)(9.5)
Obligation, End of Year$192.1$166.9
Change in Plan Assets  
Fair Value, Beginning of Year$78.6$90.9
Actual Return on Plan Assets13.9(25.2)
Employer Contribution9.920.3
Participant Contributions1.61.9
Benefits Paid(7.6)(9.3)
Fair Value, End of Year$96.4$78.6
Funded Status, End of Year$(95.7)$(88.3)
   
 
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
  
Current Liabilities$(0.8)$(0.7)
Noncurrent Liabilities$(94.8)$(87.6)
Other Changes in Pension Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income and Regulatory Assets
Year Ended December 3120122011
Millions  
Net Loss
$35.2

$56.1
Amortization of Prior Service Cost(0.3)(0.3)
Amortization of Loss(17.5)(12.2)
Total Recognized in Other Comprehensive Income and Regulatory Assets
$17.4

$43.6

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 3120122011
Millions  
Projected Benefit Obligation
$652.1

$597.5
Accumulated Benefit Obligation
$598.7

$550.6
Fair Value of Plan Assets
$460.1

$432.4

Postretirement Health and Life Obligation and Funded Status
Year Ended December 3120122011
Millions  
Change in Benefit Obligation  
Obligation, Beginning of Year
$210.6

$204.1
Service Cost4.2
3.8
Interest Cost9.4
10.8
Actuarial Gain(43.2)(2.9)
Participant Contributions2.6
2.5
Plan Amendments(5.3)
Benefits Paid(9.5)(7.7)
Obligation, End of Year
$168.8

$210.6
Change in Plan Assets  
Fair Value, Beginning of Year
$121.0

$114.7
Actual Return on Plan Assets14.3

Employer Contribution2.3
11.4
Participant Contributions2.5
2.5
Benefits Paid(9.1)(7.6)
Fair Value, End of Year
$131.0

$121.0
Funded Status, End of Year$(37.8)$(89.6)
   
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:  
Current Liabilities$(0.8)$(0.9)
Non-Current Liabilities$(37.0)$(88.7)

According to the accounting guidancestandards for Retirement Benefitsretirement 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 $18.2$22.1 million in irrevocable grantor trusts is included in Other Investments on our consolidated balance sheetConsolidated Balance Sheet at December 31, 2009 ($14.12012 ($20.3 million at December 31, 2008)2011).


ALLETE 2012 Form 10-K
102


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

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

Unrecognized Postretirement Health and Life Costs
Year Ended December 3120092008
Millions  
Net Loss$69.6$59.2
Prior Service Cost(1.3)
Transition Obligation6.99.4
Total Unrecognized Postretirement Health and Life Costs$75.2$68.6
Unrecognized Postretirement Health and Life Costs
Year Ended December 3120122011
Millions  
Net Loss
$23.5

$78.5
Prior Service Credit(13.1)(9.5)
Transition Obligation
0.1
Total Unrecognized Postretirement Health and Life Costs
$10.4

$69.1

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31201220112010
Millions   
Service Cost
$4.2

$3.8

$4.8
Interest Cost9.4
10.8
10.9
Expected Return on Plan Assets(9.9)(9.7)(9.5)
Amortization of Prior Service Credit(1.7)(1.7)(0.1)
Amortization of Loss7.5
8.5
4.8
Amortization of Transition Obligation0.1
0.1
2.5
Net Postretirement Health and Life Expense
$9.6

$11.8

$13.4

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31200920082007
Millions   
Service Cost$4.1$4.0$4.2
Interest Cost10.09.47.8
Expected Return on Plan Assets(8.3)(7.2)(6.5)
Amortization of Loss2.51.41.0
Amortization of Transition Obligation2.52.52.4
Net Postretirement Health and Life Expense$10.8$10.1$8.9
Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 3120122011
Millions  
Net (Gain) Loss$(47.5)
$6.9
Prior Service Credit Arising During the Period(5.3)
Amortization of Prior Service Credit1.7
1.7
Amortization of Transition Obligation(0.1)(0.1)
Amortization of Loss(7.5)(8.5)
Total Recognized in Other Comprehensive Income and Regulatory Assets$(58.7)

Estimated Future Benefit Payments
  Postretirement
 PensionHealth and Life
Millions  
2013
$31.2

$7.6
2014
$32.1

$8.2
2015
$33.2

$8.9
2016
$34.4

$9.4
2017
$35.5

$9.7
Years 2018 – 2022
$189.4

$52.0


ALLETE 20092012 Form 10-K
103

88


Note 16.                      Pension and Other Postretirement Benefit PlansNOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 3120092008
Millions  
Net Loss (Gain)$12.9$38.3
Prior Service Cost (Credit) Arising During the Period(1.3)
Amortization of Transition Obligation(2.5)(2.5)
Amortization of Loss (Gain)(2.5)(1.4)
Total Recognized in Other Comprehensive Income and Regulatory Assets$6.6$34.4


Estimated Future Benefit Payments
  Postretirement
 PensionHealth and Life
Millions  
2010$26.4$7.5
2011$26.9$8.4
2012$27.8$9.2
2013$28.8$10.0
2014$29.9$10.9
Years 2015 – 2019$165.0$65.5


The pension and postretirement health and life costs recorded in otherregulatory long-term assets and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2010,2013, are as follows:

  Postretirement
 PensionHealth and Life
Millions  
Net Loss$6.6$4.8
Prior Service Costs$0.5$(0.1)
Transition Obligations$2.5
Total Pension and Postretirement Health and Life Costs$7.1$7.2
 Pension
Postretirement
Health and Life
Millions  
Net Loss
$21.4

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


Weighted-Average Assumptions Used to Determine Benefit Obligation
Year Ended December 3120092008
As of December 3120122011
Discount Rate5.81%6.12% 
Pension4.10%4.54%
Postretirement Health and Life4.13%4.56%
Rate of Compensation Increase4.3 – 4.6%4.3 – 4.6%4.3 - 4.6%
Health Care Trend Rates    
Trend Rate8.5%9%9.25%10%
Ultimate Trend Rate5%5%5%
Year Ultimate Trend Rate Effective2017201220192018


Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31200920082007
Discount Rate6.12%6.25%5.75%
Expected Long-Term Return on Plan Assets   
Pension8.5%9.0%9.0%
Postretirement Health and Life6.8 – 8.5%7.2 – 9.0%5.0 – 9.0%
Rate of Compensation Increase4.3 – 4.6%4.3 – 4.6%4.3 – 4.6%


ALLETE 2009 Form 10-K
89


Note 16.Pension and Other Postretirement Benefit Plans (Continued)
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31201220112010
Discount Rate4.54 - 4.56%5.36 - 5.40%5.81%
Expected Long-Term Return on Plan Assets   
Pension8.25%8.5%8.5%
Postretirement Health and Life6.6 - 8.25%6.8 - 8.5%6.8 - 8.5%
Rate of Compensation Increase4.3 - 4.6%4.3 - 4.6%4.3 - 4.6%

In establishing the expected long-term rate of return on plan assets, we take into accountdetermine the actual long-term historical performance of our plan assets, the actual long-term historical performanceeach asset class, adjust these for the type of securities we are invested in,current economic conditions, and apply the historical performance utilizing the target allocation of our plan assets, to forecast anthe expected long-term return.  Our expected rate of return is then selected after considering the results of each of those factors, in addition to considering the impact of current economic conditions, if applicable, on long-term historical returns.return.

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


Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
One PercentOne PercentOne Percent
IncreaseDecreaseIncreaseDecrease
Millions   
Effect on Total of Postretirement Health and Life Service and Interest Cost$2.1$(1.8)
$2.0
$(1.6)
Effect on Postretirement Health and Life Obligation$23.6$(20.9)
$18.2
$(15.1)

ALLETE 2012 Form 10-K
104


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


Actual Plan Asset Allocations
Pension
Postretirement
Health and Life (a)
Pension
Postretirement
Health and Life (a)
200920082009 20082012201120122011
Equity Securities53%46%54%47%54%52%56%51%
Debt Securities28%32%38%40%28%27%35%39%
Private Equity13%16%9%10%
Real Estate5%6%5%5%

Private Equity14%16%8%9%
Cash4%
100%100%100%100%100%100%100%100%

(a)Includes VEBAs and irrevocable grantor trusts.

Pension plan equity securities included $9.9 million, or 3.0 percent,There were no shares of ALLETE common stock included in pension plan equity securities at December 31, 2009 (none at December 31, 2008)2012 ($20.0 million, approximately 0.5 million shares, in 2011).

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

Plan Asset Target Allocations
  Postretirement
 Pension
Health and Life (a)
Equity Securities50%48%
Debt Securities30%34%
Real Estate10%9%
Private Equity10%9%
 100%100%

Plan Asset Target Allocations
  Postretirement
 Pension
Health and Life (a)
Equity Securities52%48%
Debt Securities30%34%
Real Estate9%9%
Private Equity9%9%
 100%100%
(a)      
(a)Includes VEBAs and irrevocable grantor trusts.

Fair Value

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

ALLETE 2009 Form 10-K
90


Note 16.Pension and Other Postretirement Benefit Plans (Continued)

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, such as commodity options priced using observable forward pricesinputs. This category includes various bonds and volatilities.non-public funds whose underlying investments may be level 1 or level 2 securities.


ALLETE 2012 Form 10-K
105


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

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

This category includes private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.

Pension Fair Value

 At Fair Value as of December 31, 2009
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities    
     U.S. Large-cap (a)
$23.2$27.5$5.2$55.9
     U.S. Mid-cap Growth (a)
8.910.62.021.5
     U.S. Small-cap (a)
8.610.11.920.6
     International66.466.4
     ALLETE9.99.9
Debt Securities:    
     Mutual Funds32.032.0
     Fixed Income59.359.3
Other Types of Investments:    
     Private Equity Funds44.744.7
Real Estate17.317.3
Total Fair Value of Assets$82.6$173.9$71.1$327.6

 Fair Value as of December 31, 2012
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities:    
U.S. Large-cap (a)

$43.0

$36.0


$79.0
U.S. Mid-cap Growth (a)
18.3
15.3

33.6
U.S. Small-cap (a)
18.3
15.3

33.6
International50.5
45.9

96.4
Debt Securities: 
 
 
 
Mutual Funds72.5


72.5
Fixed Income10.4
50.8

61.2
Other Types of Investments: 
 
 
 
Private Equity Funds


$58.9
58.9
Real Estate

24.9
24.9
Total Fair Value of Assets
$213.0

$163.3

$83.8

$460.1
(a)   The underlying investments classified under U.S. Equity Securities represent Money Market Funds
(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 U.S. Government Bonds (Level 1), Hedge Funds (Level 2), and Auction Rate Securities (Level 3), which are combined with futures, which settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

 Recurring Fair Value Measures
  
Activity in Level 3Private Equity FundsReal Estate
Millions  
Balance as of December 31, 2011
$69.0

$21.7
Actual Return on Plan Assets(9.7)3.4
Purchases, sales, and settlements, net(0.4)(0.2)
Balance as of December 31, 2012
$58.9

$24.9

ALLETE 2012 Form 10-K
106


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

 Fair Value as of December 31, 2011
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities:    
U.S. Large-cap (a)

$32.1

$37.3


$69.4
U.S. Mid-cap Growth (a)
13.5
15.8

29.3
U.S. Small-cap (a)
13.1
15.2

28.3
International
75.1

75.1
ALLETE21.3


21.3
Debt Securities: 
 
 
 
Mutual Funds72.8


72.8
Fixed Income
45.5

45.5
Other Types of Investments: 
 
 
 
Private Equity Funds


$69.0
69.0
Real Estate

21.7
21.7
Total Fair Value of Assets
$152.8

$188.9

$90.7

$432.4
(a)
The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

Recurring Fair Value Measures   
Activity in Level 3Equity Securities (ARS)Private Equity FundsReal Estate
Millions   
Balance as of December 31, 2010
$6.7

$50.7

$20.1
Actual Return on Plan Assets
30.9
3.5
Purchases, sales, and settlements, net(6.7)(12.6)(1.9)
Balance as of December 31, 2011

$69.0

$21.7


Recurring Fair Value MeasuresEquity Securities  
Activity in Level 3(Auction Rate Securities)Private Equity FundsReal Estate
Millions   
Balance as of December 31, 2008$10.2$43.2$17.0
Actual Return on Plan Assets0.1(8.7)(8.6)
Purchases, sales, and settlements, net(1.1)10.28.9
Balance as of December 31, 2009$9.1$44.7$17.3


ALLETE 20092012 Form 10-K
107

91


Note 16.                      Pension and Other Postretirement Benefit PlansNOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)

Postretirement Health and Life Fair Value

 At Fair Value as of December 31, 2009
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities    
     U.S. Large-cap$13.4$13.4
     U.S. Mid-cap Growth9.09.0
     U.S. Small-cap6.36.3
     International21.421.4
Debt Securities:    
     Mutual Funds5.55.5
     Fixed Income$31.431.4
Other Types of Investments:    
     Private Equity Funds$9.49.4
Total Fair Value of Assets$55.6$31.4$9.4$96.4
 Fair Value as of December 31, 2012
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities:    
U.S. Large-cap (a)

$16.7



$16.7
U.S. Mid-cap Growth (a)
13.2


13.2
U.S. Small-cap (a)
13.3


13.3
International30.3


30.3
Debt Securities: 
 
 
 
Mutual Funds25.5


25.5
Fixed Income0.2

$18.3

18.5
Other Types of Investments: 
 
 
 
Private Equity Funds


$13.5
13.5
Total Fair Value of Assets
$99.2

$18.3

$13.5

$131.0
(a)
The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).


Recurring Fair Value Measures 
Activity in Level 3Private Equity Funds
Millions 
Balance as of December 31, 20082011
$7.914.0
Actual Return on Plan Assets(1.1)0.2
Purchases, sales, and settlements, net2.6(0.7)
Balance as of December 31, 20092012
$9.413.5

 Fair Value as of December 31, 2011
Recurring Fair Value MeasuresLevel 1Level 2Level 3Total
Millions    
Assets:    
Equity Securities:    
U.S. Large-cap (a)

$15.9



$15.9
U.S. Mid-cap Growth (a)
11.5


11.5
U.S. Small-cap (a)
11.2


11.2
International25.1


25.1
Debt Securities: 
 
 
 
Mutual Funds24.1


24.1
Fixed Income0.3

$18.9

19.2
Other Types of Investments: 
 
 
 
Private Equity Funds


$14.0
14.0
Total Fair Value of Assets
$88.1

$18.9

$14.0

$121.0
(a)
The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).



ALLETE 2012 Form 10-K
108


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

Recurring Fair Value Measures
Activity in Level 3Private Equity Funds
Millions
Balance as of December 31, 2010
$12.4
Actual Return on Plan Assets1.1
Purchases, sales, and settlements, net0.5
Balance as of December 31, 2011
$14.0

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) providesprovide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health benefits that includebenefit, including a prescription drug benefits,benefit, which qualifyqualifies us for thea federal subsidy under the Act. The expected reimbursement for Medicare health subsidies reduced our after-tax postretirement medical expensefederal subsidy is reflected in the premiums charged to us by $2.0 million for 2009 ($1.2 million for 2008; $2.3 million in 2007). In 2005 we enrolled with the Centers for Medicare and Medicaid Services’ (CMS) and began recovering the subsidy in 2007. We received a reimbursement of $0.6 million in 2009 and $0.3 million in 2007.insurance company.


Note 17.Employee Stock and Incentive Plans
NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor a leveraged employee stock ownership plan (ESOP)ESOP within the RSOP. AsEligible employees may contribute to the RSOP plan as of their date of hire, all employees of ALLETE, SWL&P and Minnesota Power Affiliate Resources are eligible to contribute to the plan. hire. In 1990, the ESOP issued a $75$75.0 million note (term not to exceed 25 years at 10.25 percent) to ususe 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 itsthe 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 $6.5$7.7 million in 2009 ($10.12012 ($7.4 million in 2008; $9.22011; $7.1 million in 2007)2010).

ALLETE 2009 Form 10-K
92


Note 17.Employee Stock and Incentive Plans (Continued)

According to the accounting guidancestandards 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 as outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.

Year Ended December 31200920082007
Millions   
ESOP Shares   
Allocated2.22.01.8
Unallocated1.51.92.2
Total3.73.94.0
Fair Value of Unallocated Shares$49.0$61.3$87.1

Year Ended December 31201220112010
Millions   
ESOP Shares   
Allocated2.2
2.2
2.2
Unallocated0.7
1.0
1.3
Total2.9
3.2
3.5
Fair Value of Unallocated Shares
$28.7

$42.0

$48.4

Stock-Based Compensation.Stock Incentive Plan.Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, stock appreciation rights and other awards. There are 1.41.2 million shares of common stock reserved for issuance under the Executive Plan, with 0.6 million of these shares available for issuance as of December 31, 2009.2012.

We had a Director Long-Term Stock Incentive Plan (Director Plan) which expired on January 1, 2006. No grants have been made since 2003 under the Director Plan. Approximately 3,879The 1,293 remaining options outstanding at December 31, 2011, were exercised during 2012. There were no options outstanding under the Director Plan at December 31, 2009.2012.


ALLETE 2012 Form 10-K
109


NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

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

Non-Qualified Stock Options. TheThese 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 cancelledcanceled 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.

In 2009, no stock Stock options werehave not been granted under our Executive Long-Term Incentive Compensation Plan. The following assumptions were used in determining the fair value of stock options granted during 2008 and 2007, respectively, under the Black-Scholes option-pricing model:

 20082007
Risk-Free Interest Rate2.8%4.8%
Expected Life 5 Years 5 Years
Expected Volatility20%20%
Dividend Growth Rate4.4%5.0%
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 performance targetsmarket goals over a three-year performance period. PerformanceMarket 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-ratapro rata portion of the award will be earned at the conclusion of the performance period based on the performancemarket 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-ratapro 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-yearthree-year performance period based on our estimate of the number of shares which will be earned by the award recipients.

ALLETE 2009 Form 10-K
93

Note 17.Employee Stock and Incentive Plans (Continued)

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 athe three-year period, at which time the restrictions will be removed.period. In the case of qualified retirement, death or disability, a pro-ratapro rata portion of the award will be earned at the conclusion of the vesting period.earned. In the case of termination of employment for any other reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro-ratapro rata portion of the award will be paid.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.

RSOPRetirement Savings & Stock Ownership Plan (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 statementConsolidated Statement of incomeIncome for the periods presented.

Share-Based Compensation Expense
Year Ended December 31200920082007
Millions   
Stock Options$0.3$0.7$0.8
Performance Shares1.51.11.0
Restricted Stock Units0.3
Total Share-Based Compensation Expense$2.1$1.8$1.8
Income Tax Benefit$0.8$0.7$0.7
Share-Based Compensation Expense
Year Ended December 31201220112010
Millions   
Stock Options


$0.1
Performance Shares
$1.4

$1.1
1.5
Restricted Stock Units0.7
0.5
0.6
Total Share-Based Compensation Expense
$2.1

$1.6

$2.2
Income Tax Benefit
$0.9

$0.7

$0.9

ALLETE 2012 Form 10-K
110


NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized stock-based compensation costs at December 31, 2009, 2008,2012, 2011, or 2007.2010.

As of December 31, 2009,2012, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our statementsConsolidated Statements of incomeIncome was $1.8$1.3 million and $0.5$0.6 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years for performance share awards and 2.01.7 years respectively. for restricted stock units.

Non-Qualified Stock Options.The following table presents information regarding our outstanding stock options as of December 31, 2009.2012.

    Weighted-Average
  Weighted-AverageAggregateRemaining
 Number ofExerciseIntrinsicContractual
 OptionsPriceValueTerm
   Millions 
Outstanding as of December 31, 2008672,419$39.99$(5.2)6.9 years
Granted (a)
  
Exercised4,508$18.85  
Forfeited21,676$42.62  
Outstanding as of December 31, 2009646,235$40.05$(4.8)5.9 years
Exercisable as of December 31, 2009512,743$37.34$(3.7)5.4 years
 201220112010
 
Number of
Options
Weighted-Average
Exercise
Price
Number of
Options
Weighted-Average
Exercise
Price
Number of
Options
Weighted-Average
Exercise
Price
Outstanding as of January 1,460,234

$41.68
560,887

$40.69
646,235

$40.05
Granted (a)






Exercised49,075

$35.84
80,798

$34.25
40,769

$27.76
Forfeited15,481

$44.86
19,855

$43.96
44,579

$43.16
Outstanding as of December 31,395,678

$42.28
460,234

$41.68
560,887

$40.69
Exercisable as of December 31,395,678

$41.71
460,234

$41.59
523,491

$39.76
(a)
Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

(a)       RestrictedCash received from non-qualified stock units were issuedoptions exercised was less than $0.1 million in 2009, instead of stock options.

The weighted-average grant-date fair value of options was $6.18 for 2009 ($6.18 for 2008; $6.92 for 2007)2012. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.1$0.3 million during 2009 ($0.22012 ($0.5 million in 2008; $0.42011; $0.3 million in 2007)2010).


ALLETE 2009 Form 10-K
94


Note 17.Employee Stock and Incentive Plans (Continued)

As of December 31, 2009, options outstanding consisted of 0.1 million with exercise prices ranging from $18.85 to $29.79, 0.4 million with exercise prices ranging from $37.76 to $41.35 and 0.2 million with exercise prices ranging from $44.15 to $48.65. The options with exercise prices ranging from $18.85 to $29.79 have an average remaining contractual life of 2.1 years; all were exercisable as of December 31, 2009, at a weighted average price of $27.34. The options with exercise prices ranging from $37.76 to $41.35 have an average remaining contractual life of 6.3 years; 0.2 million were exercisable as of December 31, 2009, at a weighted average price of $39.47. The options with exercise prices ranging from $44.15 to $48.65 have an average remaining contractual life of 6.5 years; less than 0.2 million were exercisable as of December 31, 2009, at a weighted average price of $46.36.
 Range of Exercise Price
As of December 31, 2012$23.79 to $26.91$37.76 to $41.35$44.15 to $48.65
Options Outstanding and Exercisable:   
Number Outstanding and Exercisable1,340
236,052
158,286
Weighted Average Remaining Contractual Life (Years)0.1
3.5
3.6
Weighted Average Exercise Price
$23.79

$39.64

$46.38

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2009.2012.

  Weighted-Average
 Number ofGrant Date
 SharesFair Value
Non-vested as of December 31, 200879,238$47.94
Granted69,800$35.06
Unearned Grant Award(24,615)$41.97
Forfeited(2,598)$38.78
Non-vested as of December 31, 2009121,825$41.96
 201220112010
 
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Non-vested as of January 1,128,333

$36.54
122,489

$38.15
121,825

$41.96
Granted (a)
38,764

$44.70
39,312

$41.00
49,302

$35.44
Awarded(41,009)
$34.25
(32,368)
$48.10


Unearned Grant Award(17,575)
$34.25


(22,909)
$54.50
Forfeited(614)
$34.49
(1,100)
$34.35
(25,729)
$36.45
Non-vested as of December 31,107,899

$40.73
128,333

$36.54
122,489

$38.15
(a)    Shares granted includes accrued dividends.


ALLETE 2012 Form 10-K
111


NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Less than 0.1 millionThere were 33,525 and 41,332 performance share wereshares granted in February 2009January 2012 and 2013, for the three-year performance periodperiods ending in 2011.2014 and 2015, respectively. The ultimate issuance is contingent upon the attainment of certain future performancemarket goals of ALLETE during the performance periods. The grant date fair value of the performance share awardsshares granted was $2.2 million.$1.5 million and $2.2 million, respectively.

NoThere were 41,009 and 18,605 performance shares were awarded in February 20102012 and 2013, for the three-yearthree-year performance periodperiods ending in 2009, as performance targets were not met. However, in accordance with2011 and 2012, respectively. The grant date fair value of the accounting guidance for stock compensation, no compensation expense previously recognized in connection with those grants will be reversed.shares awarded was $1.4 million and $0.7 million, respectively.

Restricted Stock Units. The following table presents information regarding our non-vestedavailable restricted stock units as of December 31, 2009.2012.

  Weighted-Average
 Number ofGrant Date
 SharesFair Value
Non-vested as of December 31, 2008
Granted30,465$29.41
Forfeited(1,482)$29.41
Non-vested as of December 31, 200928,983$29.41
 201220112010
 
Number of
Shares
Weighted- Average
Grant Date
Fair Value
Number of
Shares
Weighted- Average
Grant Date
Fair Value
Number of
Shares
Weighted- Average
Grant Date
Fair Value
Available as of January 1,63,464

$32.57
43,803

$30.61
28,983

$29.41
Granted (a)
18,162

$40.83
20,136

$36.74
26,589

$31.83
Awarded(24,707)
$29.43
(215)
$30.30
(3,091)
$29.75
Forfeited(504)
$31.80
(260)
$29.41
(8,678)
$30.62
Available as of December 31,56,415

$36.61
63,464

$32.57
43,803

$30.61
(a)    Shares granted includes accrued dividends.

Less than 0.1 millionThere were 16,355 and 19,193 restricted stock units were granted in February 2009January 2012 and 2013, for the vesting periodperiods ending in 2011.2014 and 2015, respectively. The grant date fair value of the restricted stock unit awardsunits granted was $0.9 million.$0.7 million and $0.8 million, respectively.

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

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



ALLETE 2009 Form 10-K
95


Note 18.Quarterly Financial Data (Unaudited)
NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

Quarter EndedMar. 31Jun. 30Sept. 30Dec. 31
Millions Except Earnings Per Share    
2009    
Operating Revenue$199.6$164.7$178.8$216.0
Operating Income$31.1$15.7$25.4$33.8
Net Income Attributable to ALLETE$16.9$9.4$16.0$18.7
Earnings Per Share of Common Stock    
Basic$0.55$0.29$0.49$0.56
Diluted$0.55$0.29$0.49$0.56
2008    
Operating Revenue$213.4$189.8$201.7$196.1
Operating Income$31.3$17.5$33.2$39.8
Net Income Attributable to ALLETE$23.6$10.7$24.7$23.5
Earnings Per Share of Common Stock    
Basic$0.82$0.37$0.85$0.78
Diluted$0.82$0.37$0.85$0.78
Quarter EndedMar. 31Jun. 30Sept. 30Dec. 31
Millions Except Earnings Per Share    
2012    
Operating Revenue
$240.0

$216.4

$248.8

$256.0
Operating Income
$38.4

$23.3

$45.6

$47.9
Net Income Attributable to ALLETE
$24.4

$14.4

$29.4

$28.9
Earnings Per Share of Common Stock    
Basic
$0.66

$0.39

$0.78

$0.76
Diluted
$0.66

$0.39

$0.78

$0.75
2011    
Operating Revenue
$242.2

$219.9

$226.9

$239.2
Operating Income
$50.8

$26.1

$38.9

$34.2
Net Income Attributable to ALLETE
$37.2

$17.0

$20.5

$19.1
Earnings Per Share of Common Stock    
Basic
$1.07

$0.49

$0.57

$0.53
Diluted
$1.07

$0.48

$0.57

$0.53


ALLETE 20092012 Form 10-K
112

96


Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves


 Balance at Beginning of PeriodAdditions
Deductions from
Reserves
(a)
Balance at End of
Period
 Charged to IncomeOther Charges
Millions     
Reserve Deducted from Related Assets     
Reserve For Uncollectible Accounts     
2010 Trade Accounts Receivable
$0.9

$1.1


$1.1

$0.9
Finance Receivables – Long-Term
$0.4

$0.8


$0.4

$0.8
2011 Trade Accounts Receivable
$0.9

$1.3


$1.3

$0.9
Finance Receivables – Long-Term
$0.8

$0.1


$0.3

$0.6
2012 Trade Accounts Receivable
$0.9

$1.0


$0.9

$1.0
Finance Receivables – Long-Term
$0.6




$0.6
Deferred Asset Valuation Allowance     
2010 Deferred Tax Assets
$0.3
$0.2


$0.5
2011 Deferred Tax Assets
$0.5
$(0.1)


$0.4
2012 Deferred Tax Assets
$0.4

$2.0



$2.4
 Balance atAdditionsDeductionsBalance at
 BeginningChargedOtherfromEnd of
Year Ended December 31of Yearto IncomeChanges
Reserves (a)
Period
Millions     
Reserve Deducted from Related Assets     
Reserve For Uncollectible Accounts     
2007  Trade Accounts Receivable$1.1$1.0$1.1$1.0
Finance Receivables – Long-Term0.20.2
2008  Trade Accounts Receivable1.01.01.30.7
Finance Receivables – Long-Term0.20.10.1
2009  Trade Accounts Receivable0.71.31.10.9
Finance Receivables – Long-Term0.10.30.4
Deferred Asset Valuation Allowance     
2007  Deferred Tax Assets3.6(0.3)3.3
2008  Deferred Tax Assets3.3(2.9)0.4
2009  Deferred Tax Assets0.4(0.1)0.3

(a)Includes uncollectible accounts written off.






ALLETE 20092012 Form 10-K
113
97