United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)

R Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2008

£ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ______________ to ______________

Commission File No. 1-3548

ALLETE, Inc.

(Exact name of registrant as specified in its charter)

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

30 West Superior Street, Duluth, Minnesota 55802-2093

 (Address of principal executive offices, including zip code)

(218) 279-5000

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Stock Exchange on Which Registered
Common Stock, without par value	New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes R                      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 R

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 R                      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. R

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 R 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 R

The aggregate market value of voting stock held by nonaffiliates on June 30, 2008, was $1,293,602,666.

As of February 1, 2009, there were 32,624,876 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference

Portions of the Proxy Statement for the 2009 Annual Meeting of Shareholders are incorporated by reference in Part III.

Index

Definitions			3
Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995			5
Part I
Item 1.	Business		6
	Regulated Operations		6
		Electric Sales / Customers	6
		Power Supply	9
		Transmission and Distribution	11
		Investment in ATC	11
		Properties	11
		Regulatory Matters	12
		Regional Organizations	13
		Minnesota Legislation	14
		Competition	14
		Franchises	14
	Investments and Other		15
		BNI Coal	15
		ALLETE Properties	15
		Non-Rate Base Generation	16
		Other	16
	Environmental Matters		16
	Employees		18
	Availability of Information		18
	Executive Officers of the Registrant		19
Item 1A.	Risk Factors		20
Item 1B.	Unresolved Staff Comments		23
Item 2.	Properties		23
Item 3.	Legal Proceedings		23
Item 4.	Submission of Matters to a Vote of Security Holders		23
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
Item 6.	Selected Financial Data		24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
	Overview		25
	2008 Compared to 2007		25
	2007 Compared to 2006		27
	Critical Accounting Estimates		29
	Outlook		31
	Liquidity and Capital Resources		37
	Capital Requirements		40
	Environmental and Other Matters		40
	Market Risk		40
	New Accounting Standards		41
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		41
Item 8.	Financial Statements and Supplementary Data		41
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		41
Item 9A.	Controls and Procedures		42
Item 9B.	Other Information		42
Part III
Item 10.	Directors, Executive Officers and Corporate Governance		43
Item 11.	Executive Compensation		43
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		43
Item 13.	Certain Relationships and Related Transactions, and Director Independence		43
Item 14.	Principal Accounting Fees and Services		43
Part IV
Item 15.	Exhibits and Financial Statement Schedules		44
Signatures			48
Consolidated Financial Statements			50

ALLETE 2008 Form 10-K

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 Acronym	Term
AICPA	American Institute of Certified Public Accountants
ALLETE	ALLETE, Inc.
ALLETE Properties	ALLETE Properties, LLC and its subsidiaries
AFUDC	Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods
AREA	Arrowhead Regional Emission Abatement
ATC	American Transmission Company LLC
BNI Coal	BNI Coal, Ltd.
Boswell	Boswell Energy Center
Company	ALLETE, Inc. and its subsidiaries
DRI	Development of Regional Impact
EITF	Emerging Issues Task Force
EPA	Environmental Protection Agency
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Form 8-K	ALLETE Current Report on Form 8-K
Form 10-K	ALLETE Annual Report on Form 10-K
Form 10-Q	ALLETE Quarterly Report on Form 10-Q
FSP	Financial Accounting Standards Board Staff Position
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gas
Heating Degree Days	Measure of the extent to which the average daily temperature is below 65 degrees Fahrenheit, increasing demand for heating
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
kV	Kilovolt(s)
Laskin	Laskin Energy Center
Manitoba Hydro	Manitoba Hydro-Electric Board
MBtu	Million British thermal units
Mesabi Nugget	Mesabi Nugget Delaware, LLC
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission
MW / MWh	Megawatt(s) / Megawatt-hour(s)
NextEra Energy	NextEra Energy Resources, LLC
Non-residential	Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NOX	Nitrogen Oxide
Note ___	Note ___ to the consolidated financial statements in this Form 10-K
NPDES	National Pollutant Discharge Elimination System
NYSE	New York Stock Exchange
OES	Minnesota Office of Energy Security

ALLETE 2008 Form 10-K

3

Definitions (Continued)

Abbreviation or Acronym	Term
Oliver Wind I	Oliver Wind I Energy Center
Oliver Wind II	Oliver Wind II Energy Center
Palm Coast Park	Palm Coast Park development project in Florida
Palm Coast Park District	Palm Coast Park Community Development District
PolyMet Mining	PolyMet Mining Corp.
PSCW	Public Service Commission of Wisconsin
PUHCA 2005	Public Utility Holding Company Act of 2005
Rainy River Energy	Rainy River Energy Corporation - Wisconsin
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards No.
SO2	Sulfur Dioxide
Square Butte	Square Butte Electric Cooperative
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc.
SWL&P	Superior Water, Light and Power Company
Taconite Harbor	Taconite Harbor Energy Center
Taconite Ridge	Taconite Ridge Energy Center
Town Center	Town Center at Palm Coast development project in Florida
Town Center District	Town Center at Palm Coast Community Development District
WDNR	Wisconsin Department of Natural Resources

ALLETE 2008 Form 10-K

4

Safe Harbor Statement

Under the Private Securities Litigation Reform Act of 1995

Statements in this report that are not statements of historical facts may be 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 is 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 results,” “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 filing cautionary statements identifying important factors that could cause our actual results to differ materially from those projected, or expectations suggested, 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:

· our ability to successfully implement our strategic objectives;

· our ability to manage expansion and integrate acquisitions;

· prevailing governmental policies, regulatory actions, and legislation including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, 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;

· 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 managementof 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.

Additional disclosures regarding factors that could cause our results and performance to differ from results or performance anticipated by this report are discussed in Item 1A under the heading “Risk Factors” beginning on page 20 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 it assess the impact of each of these factors on the 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 of the factors that may affect our business.

ALLETE 2008 Form 10-K

5

Part I

Item 1. Business

In the fourth quarter of 2008, we made changes to our reportable business segments which are now comprised of Regulated Operations and Investments and Other. For additional information about our business segments, see Note 2.

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based 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 142,000 retail customers and wholesale electric service to 16 municipalities. SWL&P provides regulated electric service, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate business. This segment also includes emerging technology investments ($7.4 million at December 31, 2008), a small amount of non-rate base generation, approximately 7,000 acres of land for sale in Minnesota, and earnings on cash and short-term investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2008, unless otherwise indicated. All subsidiaries are wholly owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

Year Ended December 31	2008	2007	2006
Consolidated Operating Revenue – Millions	$801.0	$841.7	$767.1
Percentage of Consolidated Operating Revenue
Regulated Operations	89	86	83
Investments and Other	11	14	17
	100%	100%	100%

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

REGULATED OPERATIONS

Electric Sales / Customers

Regulated Utility Electric Sales Year Ended December 31	2008	%	2007	%	2006	%
Millions of Kilowatt-hours
Retail and Municipals
Residential	1,172	9	1,141	9	1,100	9
Commercial	1,454	12	1,456	11	1,420	11
Industrial	7,192	57	7,054	55	7,206	56
Municipals (FERC rate regulated)	1,002	8	1,009	8	905	7
	10,820	86	10,660	83	10,631	83
Other Power Suppliers	1,800	14	2,157	17	2,153	17
	12,620	100	12,817	100	12,784	100

ALLETE 2008 Form 10-K

6

REGULATED OPERATIONS (Continued)

Industrial Customers. In 2008, our industrial customers represented 57 percent of total regulated utility kilowatt-hour sales. Our industrial customers are primarily in the taconite, paper, pulp, wood products and pipeline industries.

Industrial Customer Electric Sales Year Ended December 31	2008	%	2007	%	2006	%
Millions of Kilowatt-hours
Taconite Producers	4,579	64	4,408	62	4,517	63
Paper, Pulp and Wood Products	1,567	22	1,613	23	1,689	23
Pipelines	582	8	562	8	550	8
Other Industrial	464	6	471	7	450	6
	7,192	100	7,054	100	7,206	100

Approximately 60 percent of the ore consumed by integrated steel facilities in the United States originates from six taconite customers of Minnesota Power, which represent 4,579 kilowatt-hours, or 64 percent, of our total industrial sales in 2008. Taconite, an iron-bearing rock of relatively low iron content, is abundantly available in 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. Strong worldwide steel demand, driven largely by extensive infrastructure development in China, resulted in very robust world iron ore demand and steel pricing for nearly a six-year period which lasted through the summer of 2008. Beginning in the fall of 2008, worldwide steel producers began to dramatically cut steel production in response to reduced demand driven largely by the world credit situation. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook.)

In addition to serving the taconite industry, Minnesota Power also serves a number of customers in the paper, pulp and wood products industry, which represent 1,567 kilowatt-hours, or 22 percent, of our total industrial sales in 2008. In total, we serve four major paper and pulp mills directly and one paper mill indirectly by providing wholesale service to the retail provider of the mill. Minnesota Power also serves three wood product manufacturers.

Minnesota Power’s paper and pulp customers ran at, or very near, full capacity for the majority of 2008 despite the fact that the industry continued to face high fiber, chemical, and energy costs as well as competition from exports in certain grades of paper products. Minnesota Power’s customers benefited from the temporary or permanent idling of plants both in North America at mills other than those served by Minnesota Power and the idling of plants in Europe, as well as continued (but declining) strength of the Canadian dollar and the Euro which has reduced imports both from Canada and Europe.

The pipeline industry is the third key industrial segment served by Minnesota Power with services provided to two crude oil pipelines and one refinery, which represent 582 kilowatt-hours, or 8 percent, of our total industrial sales in 2008. These customers have a common reliance on the importation of Canadian crude oil. After near capacity operations in 2006, 2007, and 2008, 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 contracts with 12 Large Power Customers, 11 of which require 10 MWs or more of generating capacity and one that requires at least 8 MWs of generating capacity. These customers consist of six taconite producing facilities (two of which are owned by one company and are served under a single contract), four paper and pulp mills, two pipeline companies and one manufacturer.

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 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. Four of the Large Power Customers have interruptible service which provides a discounted demand rate 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 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 Regulatory Matters – Electric Rates)

ALLETE 2008 Form 10-K

7

REGULATED OPERATIONS (Continued)

Large Power Customers (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. The customers receive estimated bills based on Minnesota Power’s prediction of the customer’s energy usage, forecasted energy prices and fuel clause adjustment estimates. Minnesota Power’s five taconite-producing Large Power Customers have generally predictable energy usage on a week-to-week basis, which makes the variance between the estimated usage and actual usage small.

Contract Status for Minnesota Power Large Power Customers

As of February 1, 2009

Customer	Industry	Location	Ownership	Earliest   Termination Date
Hibbing Taconite Co. (a)	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)	Taconite	Virginia, MN	ArcelorMittal USA Inc.	February 28, 2013
United States Steel Corporation (USS – Minnesota Ore) (c)	Taconite	Mt. Iron, MN and Keewatin, MN	United States Steel Corporation	October 31, 2013
United Taconite LLC (a)	Taconite	Eveleth, MN	Cliffs Natural Resources Inc.	December 31, 2015
UPM, Blandin Paper Mill (b)	Paper	Grand Rapids, MN	UPM-Kymmene Corporation	February 28, 2013
Boise White Paper, LLC (d)	Paper	International Falls, MN	Boise Paper Holdings, LLC	December 31, 2013
Sappi Cloquet LLC (b)	Paper and Pulp	Cloquet, MN	Sappi Limited	February 28, 2013
NewPage Corporation – Duluth Mills	Paper and Pulp	Duluth, MN	NewPage Corporation	August 31, 2013
USG Interiors, Inc. (e)	Manufacturer	Cloquet, MN	USG Corporation	December 31, 2009
Enbridge Energy Company, Limited Partnership (e)	Pipeline	Deer River, MN Floodwood, MN	Enbridge Energy Company, Limited Partnership	June 30, 2009
Minnesota Pipeline Company (e)	Pipeline	Staples, MN Little Falls, MN Park Rapids, MN	60% Koch Pipeline Co. L.P. 40% Marathon Ashland Petroleum LLC	April 7, 2009

(a) Contract extensions at Hibbing Taconite Co. and United Taconite LLC are pending final approval from the MPUC.

(b) 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, 2013.

(c) United States Steel Corporation includes the Minntac Plant in Mountain Iron, MN and the Keewatin Taconite Plant in Keewatin, MN.

(d) A contract amendment has been filed with the MPUC which provides for an extension of the agreement through December 31, 2013.

(e) Contracts with USG Interiors, Inc., Minnesota Pipeline Company, and Enbridge Energy Company are all in cancellation periods effective on or before December 31, 2009; new contracts are expected to be agreed upon prior to expiration.

In March 2008, Minnesota Power signed a new contract with Northshore Mining Company to meet additional load requirements. The contract was approved by the MPUC and runs through at least June 30, 2011.

In September 2008, Cliffs Natural Resources Inc. (Cliffs) and Minnesota Power signed new contracts for service to Hibbing Taconite Co. and United Taconite LLC. These electric service agreements, which are pending final MPUC approval, extend the existing contract terms out to at least December 31, 2015.

ALLETE 2008 Form 10-K

8

REGULATED OPERATIONS (Continued)

Residential and Commercial Customers. In 2008, our residential and commercial customers represented 21 percent of total regulated utility kilowatt-hour sales. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 142,000 residential and commercial customers. SWL&P provides regulated electric service, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers.

Municipal Customers. In 2008, our municipal customers represented 8 percent of total regulated utility kilowatt-hour sales. Our municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. The FERC has jurisdiction over our wholesale electric service, tariff rates, and operations. In 2008 Minnesota Power entered into new contracts with all of our municipal customers with the exception of one small customer whose contract is now in the cancellation period. The new contracts transition each customer to formula based rates, which means rates can be adjusted annually based on changes in costs. The new agreement with the private utility in Wisconsin is subject to PSCW approval. In November 2008, we filed a request with the FERC to implement the formula based rate provision in the new contracts. We anticipate final resolution and implementation of new rates in the first quarter of 2009.

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 coal, 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 SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” and are not required to be recorded at fair value.

For 2009, we have sold up to 225 MWs per month to Other Power Suppliers to mitigate the demand reduction expected from our taconite customers; these contracts expire at various times during 2009.

Power Supply

In order to meet our customer’s 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 MWs of hydro generation from nine hydro stations in Minnesota and 25 MWs of wind generation. Purchased power is made up of long term power purchase agreements and market purchases. The following table reflects the Company’s generating capabilities and total electrical requirements as of December 31, 2008. Minnesota Power had an annual net peak load of 1,582 MWs on January 18, 2008.

ALLETE 2008 Form 10-K

9

REGULATED OPERATIONS (Continued)

Power Supply (Continued)

Regulated Utility Power Supply	Unit No.	Year Installed	Net Winter  Capability	For the Year Ended December 31, 2008 Electric Requirements
			MW	MWh	%
Coal-Fired
Boswell Energy Center	1	1958	69
in Cohasset, MN	2	1960	69
	3	1973	350
	4	1980	429
			917	6,365,305	48.5%
Laskin Energy Center	1	1953	55
in Hoyt Lakes, MN	2	1953	55
			110	659,439	5.0
Taconite Harbor Energy Center	1	1957	73
in Taconite Harbor, MN	2	1957	73
	3	1967	74
			220	1,473,239	11.2
Total Coal			1,247	8,497,983	64.7
Steam – Purchased
Hibbard Energy Center in Duluth, MN	3 & 4	1949, 1951	45	61,635	0.5
Hydro
Group consisting of nine stations in MN	Various		112	487,930	3.7
Wind
Taconite Ridge (a)	1	2008	4	18,587	0.2
Total Company Generation			1,408	9,066,135	69.1
Long Term Purchased Power
Square Butte burns lignite coal near Center, ND				1,943,949	14.8
Wind – Oliver County, ND				366,945	2.8
Hydro – Manitoba Hydro				390,680	3.0
Total Long Term Purchased Power				2,701,574	20.6
Other Purchased Power(b)				1,357,023	10.3
Total Purchased Power				4,058,597	30.9
Total			1,408	13,124,732	100.0%

(a) The nameplate capacity of Taconite Ridge is 25 MWs. The capacity reflected in the table is actual accredited capacity of the facility. Accredited capacity is the amount of net generating capability associated with the facility for which capacity credit may be obtained using limited historical data. As more data is collected, actual accredited capacity may increase.

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

Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin coal region located in Montana and Wyoming. Coal consumption in 2008 for electric generation at Minnesota Power’s coal-fired generating stations was approximately 5.2 million tons. As of December 31, 2008, Minnesota Power had a coal inventory of about 631,000 tons. Minnesota Power’s primary coal supply agreements have expiration dates that are staggered from the end of 2009 through 2011. Under these agreements, Minnesota Power has the tonnage flexibility to procure 70 percent to 100 percent of its total coal requirements. In 2009, 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 Power continues to explore 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 Burlington Northern Santa Fe Railway Company (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 agreements with an affiliate of the Canadian National Railway and with Midwest Energy Resources Company to transport coal from BNSF interconnection points to certain Minnesota Power facilities.

ALLETE 2008 Form 10-K

10

REGULATED OPERATIONS (Continued)

Fuel (Continued)

On January 24, 2008, we received a letter from BNSF alleging that the Company defaulted on a material obligation under the Company’s Coal Transportation Agreement (CTA). In the notice, BNSF claimed the Company underpaid approximately $1.6 million for coal transportation services in 2006 and that failure to pay such amount plus interest may result in BNSF’s termination of the CTA. We believe we do not owe the amount claimed. On April 1, 2008, to ensure that BNSF did not attempt to terminate the CTA, we paid under protest the full amount claimed by BNSF and filed a demand for arbitration of the issue. On April 22, 2008, BNSF filed a counterclaim in the arbitration disputing our position that we are entitled to a refund from BNSF of $1.5 million plus interest for amounts that we overpaid for 2007 deliveries. The arbitration is proceeding in connection with the claim regarding 2006 payments and the counterclaim regarding 2007 payments, and we are unable to predict the outcome at this time. The delivered costs of fuel for the Company’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Coal Delivered to Minnesota Power Year Ended December 31	2008	2007	2006
Average Price per Ton	$22.73	$21.78	$20.19
Average Price per MBtu	$1.25	$1.20	$1.10

Long Term Purchased Power. Minnesota Power has contracts to purchase capacity and energy from various entities. The largest contract is with Square Butte. Under an agreement with Square Butte, expiring 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 8. Commitments, Guarantees, and Contingencies.) The Square Butte generating unit operated by Minnkota Power burns North Dakota lignite coal supplied by BNI Coal in accordance with the terms of a contract that extends through 2026. Square Butte’s cost of lignite burned in 2008 was approximately $0.93 per MBtu. The lignite that has been dedicated to Square Butte by BNI Coal is located on lands essentially all of which are under private control and presently leased by BNI Coal. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit.

We have two wind power purchase agreements with an affiliate of NextEra Energy 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 and the output from Oliver Wind II, a 48-MW facility in November 2007. Each agreement is for 25 years and provides for the purchase of all output from the facilities.

We currently have a 50 MW power purchase agreement with Manitoba Hydro that expires in April 2009. We have entered into an additional 50 MW power purchase agreement with Manitoba Hydro that begins May 2009 and runs through April 2015.

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 230 kV (605 miles), 161 kV (43 miles), 138 kV (126 miles), 115 kV (1,224 miles) and less than 115 kV (6,215 miles). We own and operate 165 substations with a total capacity of 10,179 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

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 operation and ownership of, and investment in, transmission facilities. We account for our investment in ATC under the equity method of accounting, pursuant to EITF 03-16, “Accounting for Investments in Limited Liability Companies.” As of December 31, 2008, our equity investment balance in ATC was $76.9 million ($65.7 million at December 31, 2007).

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 in our real properties subject only to the lien of the mortgages. Most of our electric lines are located on land not owned in fee, but are covered by 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.)

ALLETE 2008 Form 10-K

11

REGULATED OPERATIONS (Continued)

Regulatory Matters

We are subject to the jurisdiction of various regulatory authorities. The MPUC has regulatory authority over Minnesota Power’s service area in Minnesota, retail rates, retail services, 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 PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas, water, issuances of securities, and other matters. The MPUC, FERC, and PSCW had regulatory authority over 62 percent, 10 percent, and 9 percent, respectively, of our 2008 consolidated operating revenue.

Electric Rates. Minnesota Power designs its electric service rates based on cost of service studies under which allocations are made to the various classes of customers. 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 and renewable expenditures.

Information published by the Edison Electric Institute (Typical Bills and Average Rates Report – Winter 2008 and Rankings – July 1, 2008) ranked Minnesota Power as having the ninth lowest average retail rates out of 175 investor-owned utilities in the United States. According to this report, we had the lowest rates in Minnesota and 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. On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC seeking an average rate increase of 8.5 percent for retail customers. The rate filing seeks a return on equity of 11.15 percent, and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. On an annualized basis, the requested rate increase would generate approximately $40 million in additional revenue. Interim rates were effective on August 1, 2008, and resulted in an increase for retail customers of approximately $36 million, or 7.5 percent, on an annualized basis, subject to refund pending the final rate order. Incremental revenue in 2008 from the interim retail rate increase was approximately $13 million. The transition to a new base cost of fuel coincident with interim rates resulted in the non-recovery through the fuel adjustment clause of approximately $19 million of fuel and purchased power costs incurred in 2008. We have entered into a stipulation and settlement agreement that would allow recovery of the $19 million in 2009 and which addresses specific concerns identified by interveners in the rate case; the stipulation and settlement agreement is subject to MPUC approval. The final rate order is expected in the second quarter of 2009. We cannot predict the final level of rates that may be approved by the MPUC. Prior to the May 2008 retail rate request Minnesota Power’s rates were based on a 1994 MPUC retail rate order that allowed for an 11.6 percent return on equity.

Integrated Resource Plan.In October 2007, Minnesota Power filed its Integrated Resource Plan (IRP), a comprehensive estimate of future capacity needs within the Minnesota Power service territory. In October 2008, the MPUC issued an order approving our request to re-file the IRP by October 1, 2009 in order to incorporate the North Dakota wind project and otherwise update our load forecasting and modeling in the IRP. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Outlook for additional information on the North Dakota wind project.)

Minnesota Power plans to meet expected loads through approximately 2020 by adding a significant amount of renewable generation and some supporting peaking generation. We plan to add 300 to 500 megawatts of carbon-minimizing renewable energy to our generation mix. Besides the additional generation from renewable sources, Minnesota Power anticipates future supply will come from a combination of sources, including:

· “As-needed” peaking and intermediate generation facilities;

· Expiration of wholesale contracts presently in place;

· Short-term market purchases;

· Improved efficiency of existing generation and power delivery assets; and

· Expanded conservation and demand-side management initiatives.

We do not anticipate the need for new base load system generation within the Minnesota Power service territory through approximately 2020, and we project a one percent average annual growth in electric usage from our existing customers over that time frame.

ALLETE 2008 Form 10-K

12

REGULATED OPERATIONS (Continued)

Regulatory Matters (Continued)

AREA and Boswell Unit 3 Emission Reduction Plans. In May 2006, the MPUC authorized current cost recovery of expenditures to reduce emissions of SO2, NOX, and mercury emissions at Taconite Harbor and Laskin under the AREA Plan. The AREA Plan has significantly reduced emissions from Taconite Harbor and Laskin, while maintaining a reliable and reasonably-priced energy supply to meet the needs of our customers. Environmental retrofits at Laskin and Taconite Harbor Units 1 and 2 are complete and in service. The environmental regulatory requirements for Taconite Harbor Unit 3 are pending finalization of the Minnesota Regional Haze implementation plan by the MPCA. We are expecting to retrofit Taconite Harbor Unit 3 by 2013 and are evaluating compliance requirements and cost recovery options for this final unit.

We are making emission reduction investments at our Boswell Unit 3 generating unit. The investments in pollution control equipment will reduce particulates, SO2, NOX, and mercury emissions to meet future federal and state requirements. The MPUC has authorized a cash return on construction work in progress during the construction phase in lieu of AFUDC-Equity and allows for a return on investment and current cost recovery of incremental operations and maintenance expenses once the new equipment is installed and the unit is placed back in service in late 2009. We began cost recovery on January 1, 2008. In September 2008, we filed a petition with the MPUC to approve the Boswell Unit 3 rate adjustment for 2009. If approved, new rates would allow cost recovery relating to additional investments planned for 2009.

Boswell NOXReduction Plan. In September 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for NOX emission reductions from Boswell Units 1, 2, and 4. If approved by the MPUC, the Boswell NOX Reduction Plan is expected to significantly reduce NOXemissions from these units. In conjunction with the NOX reduction Plan, we plan to install an efficiency upgrade to the existing turbine/generator at Boswell Unit 4 adding approximately 60 MWs of total output with no additional emissions. A second filing requesting cost recovery for the plan will be submitted to the MPUC in the first quarter of 2009.

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 amounts included in retail base rates. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, as well as a carrying charge on the deferred account balance. Minnesota’s Next Generation Energy Act of 2007 introduced, in addition to minimum spending requirements, an energy-saving goal of 1.5 percent of gross annual retail electric energy sales by 2010. In May 2007, an abbreviated filing was submitted and subsequently approved by the MPUC, allowing the continuation of Minnesota Power’s 2006-2007 CIP biennial and related goals for one additional year, through 2008. 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. Minnesota Power’s CIP investment goal was $3.7 million for 2008 ($3.2 million for 2007 and 2006), with actual spending of $4.8 million in 2008 ($3.9 million in 2007; $3.8 million in 2006).

Federal Energy Regulatory Commission. The FERC has jurisdiction over our wholesale electric services and operations. Minnesota Power’s hydroelectric facilities, which are located in Minnesota, are also licensed by the FERC.

On February 8, 2008, the FERC approved Minnesota Power’s wholesale tariff rate increase effective March 1, 2008. Minnesota Power’s wholesale customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. The FERC authorized an average 10.0 percent increase for wholesale municipal customers, and an overall return on equity of 11.25 percent. Incremental revenue in 2008 from the FERC authorized wholesale rate increase was approximately $6 million.

Public Service Commission of Wisconsin. 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 common 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.

Regional Organizations

Midwest Independent Transmission System Operator, Inc. Minnesota Power and SWL&P are members of MISO, a regional transmission organization. Minnesota Power and SWL&P retain ownership of their respective transmission assets and control area functions, but their transmission network is under the regional operational control of MISO, and they 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, encompassing all or parts of 15 states and one Canadian province, and over 100,000 MWs of generating capacity.

In January 2009, MISO launched the new Ancillary Services Market (ASM) aimed at establishing a market for energy and operating reserves. In May 2008, in preparation of the new market, Minnesota Power and the other investor-owned utilities in Minnesota prepared a joint filing seeking MPUC approval for the authority to account for costs and revenues that have been instituted by the ASM market. The MPUC held a discussion-only hearing on the joint filing in December 2008, and has indicated it will likely bring the matter back before the MPUC in the first quarter of 2009.

ALLETE 2008 Form 10-K

13

REGULATED OPERATIONS (Continued)

Regional Organizations (Continued)

Mid-Continent Area Power Pool (MAPP). Minnesota Power also participates in MAPP, a power pool operating in parts of eight states in the Upper Midwest and in two Canadian provinces. MAPP functions include a regional transmission committee and a generation reserve sharing pool.

Minnesota Legislation

Renewable Energy. In February 2007, Minnesota enacted a law requiring Minnesota Power to generate or procure 25 percent of our energy from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016, and 20 percent by 2020. The law allows the MPUC to modify or delay a standard obligation if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developing and making renewable supply additions as part of its generation planning strategy prior to the enactment of this law and this activity continues.

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. Minnesota is also participating in the Midwestern Greenhouse Gas Reduction Accord, a regional effort to develop a multi-state approach to GHG emission reductions.

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.

Competition

In August 2005, the Energy Policy Act of 2005 (EPAct 2005) was signed into law, which and 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. We cannot predict the timing or substance of any future legislation or regulation.

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. The remaining cities 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.

ALLETE 2008 Form 10-K

14

INVESTMENTS 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 business. This segment also includes emerging technology investments ($7.4 million at December 31, 2008), a small amount of non-rate base generation, approximately 7,000 acres of land for sale in Minnesota, and earnings on cash and short-term 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 coal supply agreements extending through 2026. (See Item 1. Business – Fuel and Note 8. 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 acre of land is approximately $35,000, however, depending on conditions, it could be significantly higher. Reclamation costs are included in the cost of coal passed through to customers. With lignite reserves of an estimated 600 million tons, BNI Coal has ample capacity to expand production.

ALLETE Properties

ALLETE Properties is our real estate business that has operated in Florida since 1991. Our current strategy is to complete and maintain key entitlements and infrastructure improvements which enhance values without requiring significant additional investment, and position the current property portfolio for a maximization of value and cash flow when market conditions improve.

Our two major development projects include Town Center and Palm Coast Park. A third proposed development project, Ormond Crossings, is in the permitting and planning stage. Development activities involve mainly zoning, permitting, platting, and master infrastructure construction. Development costs are financed through a combination of community development district bonds, bank loans, and internally-generated funds.

TownCenter. 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 2006. At build-out, Town Center is expected to include approximately 3,200 residential units and 3.8 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.

PalmCoastPark. Palm Coast Park, which is located in the city of Palm Coast, is a 4,700-acre mixed-use development. Major infrastructure construction 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, 3.2 million square feet of various types of non-residential space and certain public facilities. Market conditions will determine how quickly Palm Coast Park builds out.

Ormond Crossings. Ormond Crossings is an approximately 6,000-acre mixed-use development that is located in both the city of Ormond Beach in Volusia County and unincorporated Flagler County. Planning, engineering design, and permitting of the master infrastructure are ongoing. We estimate the first two phases of Ormond Crossings will include 2,500–3,200 residential units and 2.5–3.5 million square feet of various types of non-residential space. Ormond Crossings will also include approximately 2,000 acres of a regionally significant wetlands mitigation bank that was permitted by the St. Johns River Water Management District in 2008 and is expected to be permitted by the U.S. Army Corps of Engineers in 2009. Wetland mitigation credits will be used at Ormond Crossings and will be available-for-sale to other developers. Market conditions will determine when and if Ormond Crossings will be built out. We do not expect any significant activity in 2009.

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

Seller Financing. ALLETE Properties sometimes provides seller financing. At December 31, 2008, outstanding finance receivables were $13.6 million, with maturities up to 4 years. 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 2008 Form 10-K

15

INVESTMENTS AND OTHER (Continued)

Non-Rate Base Generation

Non-Rate base generationconsists of approximately 50 MWs of generation. In 2008, we sold 0.2 million MWh of non-rate base generation (0.2 million in 2007 and 2006).

Non-Rate Base Power Supply	Unit No.	Year Installed	Year Acquired	Net Capability
				MW
Steam
Wood-Fired (a)
Cloquet Energy Center	5	2001	2001	23
in Cloquet, MN
Rapids Energy Center (b)	6 & 7	1969, 1980	2000	29
in Grand Rapids, MN
Hydro
Conventional Run-of-River
Rapids Energy Center (b)	4 & 5	1917	2000	1
in Grand Rapids, MN

(a) Supplemented by coal.

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

Other

MinnesotaLand. We have about 7,000 acres of land available-for-sale in Minnesota. We acquired the land in 2001 when we purchased Taconite Harbor.

Emerging Technology Investments. The majority of our emerging technology investments are minority investments in venture capital funds. We account for our investment in venture capital funds under the equity method of accounting. The total carrying value of our emerging technology portfolio was $7.4 million at December 31, 2008. (See Note 6. Investments.) Our remaining commitment of $0.7 million at December 31, 2008 may be invested in 2009. We do not have plans to make any additional investments beyond this commitment.

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. 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 future stricter environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Requirements.)

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 expense unless recoverable in rates from customers.

Air. Clean Air Act.The federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2 and system wide averaging NOXlimits. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of these facilities are equipped with pollution control equipment such as scrubbers, bag houses, or electrostatic precipitators. Minnesota Power’s generating facilities are currently in compliance with permitted emission requirements.

ALLETE 2008 Form 10-K

16

Environmental Matters (Continued)

Air (Continued)

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

The EPA has been conducting a nationwide enforcement initiative since 1999 relating to NSR requirements. In 2000, 2001, and 2002 Minnesota Power received requests from the EPA pursuant to Section 114(a) of the Clean Air Act seeking information regarding capital expenditures with respect to Boswell and Laskin. Minnesota Power responded to these requests; however, we had no further communications from the EPA regarding the information provided until receipt of the NOV.

We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome 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. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding. We are unable to predict the ultimate financial impact 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 is 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 acourt 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, Minnesota Power has received written assurance from the EPA that it intends to publish a rule amending 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. Minnesota Power anticipates the EPA will act regarding this Minnesota administrative stay of the CAIR before CAIR compliance reporting would be required in 2010. If the CAIR ultimately goes into effect in Minnesota, we expect we will haveto supplement ongoing emission control retrofits by providing for CAIR related emission allowance purchases, supplemental emission reductions or a combination of both.

MinnesotaRegional Haze. The regional haze rule requires states to submit state implementation plans (SIPs) to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the regional haze rule, certain large stationary sources of visibility-impairing emissions that were put in place between 1962 and 1977 are required to install emission controls, known as best available retrofit technology (BART). We have certain steam units (Boswell Unit 3 and Taconite Harbor Unit 3) that 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, the MPCA has requested that companies with BART eligible units complete and submit a BART emissions control retrofit study, which we did as to Taconite Harbor Unit 3 in November 2008. The retrofit work currently underway on Boswell Unit 3 meets the BART requirement for that unit. It is uncertain what controls will ultimately be required by the MPCA at Taconite Harbor Unit 3 in connection with the regional haze rule.

EPA Clean Air Mercury Rule. In March 2005, the EPA also announced the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped emissions of electric utility mercury emissions in the continental United States. In February 2008, the Court overturned the CAMR and remanded the rulemaking to the EPA for reconsideration. In October 2008, the Department of Justice, on behalf of the EPA, petitioned the Supreme Court to review the Court’s decision in the CAMR case. It is uncertain how the Supreme Court will respond. Cost estimates for complying with CAMR or future mercury regulations under the Clean Air Act are therefore premature at this time.

Minnesota Mercury Emission Law. This legislation requires Minnesota Power to file mercury emission reduction plans for Boswell Units 3 and 4. The Boswell Unit 3 emission reduction plan was filed with the MPCA in October 2006. Minnesota Power is required to install mercury emission reduction technology and equipment by December 31, 2010. (See Item 1. Business – Regulated Operations – Minnesota Public Utilities Commission – AREA and Boswell Unit 3 Emission Reduction Plans.) The next step will be to file a mercury emissions reduction plan for Boswell Unit 4 by July 1, 2011, with implementation no later than December 31, 2014.

ALLETE 2008 Form 10-K

17

Environmental Matters (Continued)

Water. The Federal 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. We are in material compliance with these permits.

Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid wastes 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 replaced its PCB capacitor banks by 2005. PCB-contaminated oil in substation equipment was replaced by June 2007. We are in material compliance with these rules.

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site within the City 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. We have accrued a $0.5 million liability for this site at December 31, 2008, and have recorded a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.

Employees

At December 31, 2008, ALLETE had 1,529 employees, of which 1,449 were full-time.

Minnesota Power and SWL&P have an aggregate 635 employees who are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. The labor agreement with IBEW Local 31 expired on January 31, 2009. Both parties have agreed to extend the current agreement until a new agreement is signed. Negotiations are proceeding as anticipated and we remain optimistic of achieving a ratified agreement.

BNI Coal has 94 employees who are members of the IBEW Local 1593. BNI Coal and IBEW Local 1593 have a labor agreement which expires on March 31, 2011.

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, available free of charge on ALLETE’s Website www.allete.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC.

ALLETE 2008 Form 10-K

18

Executive Officers of the Registrant

As of February 13, 2009, these are the executive officers of ALLETE.

Executive Officers	Initial Effective Date
Donald J. Shippar, Age 59
Chairman, President and Chief Executive Officer	January 1, 2006
President and Chief Executive Officer	January 21, 2004
Executive Vice President – ALLETE and President – Minnesota Power	May 13, 2003
President and Chief Operating Officer – Minnesota Power	January 1, 2002
Robert J. Adams, Age 46
Vice President – Business Development and Chief Risk Officer	May 13, 2008
Vice President – Utility Business Development	February 1, 2004
Deborah A. Amberg, Age 43
Senior Vice President, General Counsel and Secretary	January 1, 2006
Vice President, General Counsel and Secretary	March 8, 2004
Steven Q. DeVinck, Age 49
Controller	July 12, 2006
Mark A. Schober, Age 53
Senior Vice President and Chief Financial Officer	July 1, 2006
Senior Vice President and Controller	February 1, 2004
Vice President and Controller	April 18, 2001
Donald W. Stellmaker, Age 51
Treasurer	July 24, 2004
Claudia Scott Welty, Age 56
Senior Vice President and Chief Administrative Officer	February 1, 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.

Ms. Amberg was a Senior Attorney.

Mr. DeVinck was Director of Nonutility Business Development, and Assistant Controller.

Mr. Stellmaker was Director of Financial Planning.

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

The present term of office of the executive officers listed above extends to the first meeting of our Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May 12, 2009.

ALLETE 2008 Form 10-K

19

Item 1A.                      Risk Factors

Readers are cautioned that forward-looking statements, including those contained in this Form 10-K, 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. 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 below are realized.

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

Our 12 Large Power Customers accounted for approximately 36 percent of our 2008 consolidated operating revenue (one of these customers accounted for 12.5 percent of consolidated revenue). 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. An economic downturn or failure to compete effectively in the global economy could have a material adverse effect on their operations and, consequently, could negatively impact our results of operations if we are unable to remarket this energy at similar prices.

Our operations are subject to extensive governmental regulations that may have a negative impact on our business and results of operations.

We are subject to prevailing governmental policies and regulatory actions, including those of the United States Congress, state legislatures, the FERC, the MPUC and the PSCW. These governmental regulations relate to allowed rates of return, financings, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and capital investments, and present or prospective wholesale and retail competition (including but not limited to transmission costs). These governmental regulations significantly influence our operating environment and may affect our ability to recover costs from our customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for 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 assure 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 federal and state regulatory authorities. In future rate cases, if Minnesota Power and SWL&P do not receive an adequate amount of rate relief, rates are reduced, increased rates are not approved on a timely basis or costs are otherwise unable to be recovered through rates, 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 operations results from future regulatory activities of any of these agencies.

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

Proposals for voluntary initiatives and mandatory controls are being discussed within Minnesota, among a group of midwestern states that includes Minnesota, in the United States Congress and worldwide to reduce GHGs such as carbon dioxide, a by-product of burning fossil fuels. We currently use coal as the primary fuel in 94 percent of the energy produced by our generating facilities.

We cannot be certain 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 laws or regulations are implemented, they could have a material effect on our results of operations, particularly if implementation costs are not fully recoverable from customers.

We are participating in research and study initiatives to mitigate the potential impact of carbon emissions regulation to our business. There is no assurance that our current reduction efforts will mitigate the impact of any new regulations.

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 emission allowance pricing or regulatory recovery of these costs. We are pursuing a current cost recovery mechanism with the MPUC.

ALLETE 2008 Form 10-K

20

Risk Factors (Continued)

Our operations pose certain environmental risks which 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 and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions. 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 officials and private individuals 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 existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not 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 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. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

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 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, 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 its 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.

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 non-rate base operations at this time.

ALLETE 2008 Form 10-K

21

Risk Factors (Continued)

We are dependent on good labor relations.

We believe our relations to be good with our 1,529 employees. Failure to successfully renegotiate labor agreements could adversely affect the services we provide and our results of operations. 729 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.Both parties have agreed to extend the current agreement until a new agreement is signed. Negotiations are proceeding as anticipated and we remain optimistic of achieving a ratified agreement.The labor agreement with Local 1593 at BNI Coal expires on March31,2011.

A downturn in economic conditions could adversely affect our real estate business.

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

Our real estate business 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 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 return rates. 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.

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 amount and at the times needed, our ability to execute our business plans, make capital expenditures or pursue acquisitions 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 financial markets. Such disruptions could include a severe prolonged economic downturn, the bankruptcy of non-affiliated industry leaders in the same line of business or financial services sector, deterioration in capital market conditions, volatility in commodity prices or events such as those currently being experienced in the United States and abroad.

ALLETE 2008 Form 10-K

22

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Properties are included in the discussion of our businesses in Item 1 and are incorporated by reference herein.

Item 3. Legal Proceedings

Material legal and regulatory proceedings are included in the discussion of our businesses in Item 1 and are incorporated by reference herein.

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

No matters were submitted to a vote of security holders during the fourth quarter of 2008.

Part II

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

Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends without interruption on our common stock since 1948. A quarterly dividend of $0.44 per share on our common stock will be paid on March 1, 2009, to the holders of record on February 16, 2009.

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

	2008			2007
	Price Range		Dividends	Price Range		Dividends
Quarter	High	Low	Declared	High	Low	Declared
First	$39.86	$33.76	$0.43	$49.69	$44.93	$0.41
Second	46.11	38.82	0.43	51.30	45.39	0.41
Third	49.00	38.05	0.43	50.05	38.60	0.41
Fourth	44.63	28.28	0.43	46.48	38.17	0.41
Annual Total			$1.72			$1.64
Dividend Payout Ratio			61%			53%

At February 1, 2009, there were approximately 29,000 common stock shareholders of record.

Common Stock Repurchases. We did not repurchase any ALLETE common stock during the fourth quarter of 2008.

ALLETE 2008 Form 10-K

23

Item 6.                      Selected Financial Data

	2008	2007	2006		2005		2004
Operating Revenue	$801.0	$841.7	$767.1		$737.4		$704.1
Operating Expenses	679.2	710.0	628.8		692.3	(g)	603.2
Income from Continuing Operations Before Change in Accounting Principle	82.5	87.6	77.3		17.6	(g)	38.5
Income (Loss) from Discontinued Operations – Net of Tax	–	–	(0.9)		(4.3)	(g)	73.7
Change in Accounting Principle – Net of Tax	–	–	–		–		(7.8)	(h)
Net Income	82.5	87.6	76.4		13.3		104.4
Common Stock Dividends	50.4	44.3	40.7		34.4		79.7
Earnings Retained in (Distributed from) Business	$32.1	$43.3	$35.7		$(21.1)		$24.7
Shares Outstanding – Millions
Year-End	32.6	30.8	30.4		30.1		29.7
Average (a)
Basic	29.2	28.3	27.8		27.3		28.3
Diluted	29.3	28.4	27.9		27.4		28.4
Diluted Earnings (Loss) Per Share (b)
Continuing Operations	$2.82	$3.08	$2.77		$0.64	(g)	$1.35	(i)
Discontinued Operations (c)	–	–	(0.03)		(0.16)		2.59
Change in Accounting Principle	–	–	–		–		(0.27)
	$2.82	$3.08	$2.74		$0.48		$3.67
Total Assets	$2,134.8	$1,644.2	$1,533.4	(f)	$1,398.8		$1,431.4
Long-Term Debt	588.3	410.9	359.8		387.8		389.4
Return on Common Equity	10.7%	12.4%	12.1%		2.2%	(g)	8.3%
Common Equity Ratio	58.0%	63.7%	63.1%		60.7%		61.7%
Dividends Declared per Common Share	$1.72	$1.64	$1.45		$1.245		$2.8425
Dividend Payout Ratio	61%	53%	53%		259%	(g)	77%
Book Value Per Share at Year-End	$25.37	$24.11	$21.90		$20.03		$21.23
Capital Expenditures by Segment (d)
Regulated Operations	$317.0	$220.6	$107.5		$46.5		$41.7
Investments and Other (e)	5.9	3.3	1.9		12.1		16.1
Discontinued Operations	–	–	–		4.5		21.4
Total Capital Expenditures	$322.9	$223.9	$109.4		$63.1		$79.2

(a) Excludes unallocated ESOP shares.

(b) Common share and per share amounts have also been adjusted for all periods to reflect our September 20, 2004, one-for-three common stock reverse split.

(c) Operating results of our Water Services businesses and our telecommunications business are included in discontinued operations, and accordingly, amounts have been restated for all periods presented. (See Note 12. Discontinued Operations.)

(d) In the fourth quarter of 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.)

(e) Excludes capitalized improvements on our development projects, which are included in inventory.

(f) Included $86.1 million of assets reflecting the adoption of SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

(g) Impacted by a $50.4 million, or $1.84 per share, charge related to the assignment of the Kendall County power purchase agreement, a $2.5 million, or $0.09 per share, deferred tax benefit due to comprehensive state tax planning initiatives, and a $3.7 million, or $0.13 per share, current tax benefit due to a positive resolution of income tax audit issues.

(h) Reflected the cumulative effect on prior years (to December 2003) of changing to the equity method of accounting for investments in limited liability companies included in our emerging technology portfolio.

(i) Included a $10.9 million, or $0.38 per share, after-tax debt prepayment cost incurred as part of ALLETE’s financial restructuring in preparation for the spin-off of the Automotive Services business and an $11.5 million, or $0.41 per share, gain on the sale of ADESA shares related to the Company’s ESOP.

ALLETE 2008 Form 10-K

24

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” located on page 5 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 142,000 retail customers and wholesale electric service to 16 municipalities. SWL&P provides regulated electric service, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate business. This segment also includes emerging technology investments ($7.4 million at December 31, 2008), a small amount of non-rate base generation, approximately 7,000 acres of land for sale in Minnesota, and earnings on cash and short-term investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2008, unless otherwise indicated. All subsidiaries are wholly owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

2008 Financial Overview

Net income for 2008 was $82.5 million, or $2.82 per diluted share compared to $87.6 million, or $3.08 per diluted share for 2007. Earnings per diluted share decreased approximately $0.08 compared to 2007 as a result of additional shares of common stock outstanding in 2008. (See Note 9. Common Stock and Earnings Per Share.) Net income for 2008 was down $5.1 million from 2007 reflecting:

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 interim rate increase (subject to refund) for retail customers in Minnesota, and 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.

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.

2008 Compared to 2007

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

Regulated Operations

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.

ALLETE 2008 Form 10-K

25

2008 Compared to 2007 (Continued)

Regulated Operations (Continued)

Higher rates resulted from the August 1, 2008 interim rate increase (subject to refund) 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 Sold	2008	2007
Millions
Regulated Utility
Retail and Municipals
Residential	1,172	1,141
Commercial	1,372	1,373
Industrial	7,192	7,054
Municipals	1,002	1,008
Other	82	84
Total Retail and Municipals	10,820	10,660
Other Power Suppliers	1,800	2,157
Total Regulated UtilityKilowatt-hours Sold	12,620	12,817

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 reflecting higher electricity production at the Company’s generation facilities. Megawatt-hour generation at our facilities and Square Butte increased 9 percent over 2007.

Operating and Maintenance Expense increased $10.0 million, or 4 percent, over 2007 primarily due to increased gas purchases, reflecting a colder 2008, and higher salaries and wages.

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. We had been seeking to have the increased depreciation rates become effective with the date of final rates in the current retail rate filing (expected to be in the second quarter of 2009).

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. Investments.)

Investments and Other

Operating revenue decreased $29.1 million, or 25 percent, from 2007 primarily due to a decrease in revenue at ALLETE Properties. Weaker real estate market conditions in Florida led to the decline. Operating revenue in 2008 included a pre-tax gain of $4.5 million on the sale of our retail shopping center in Winter Haven, Florida in May 2008, as well as $3.7 million in previously deferred revenue.

ALLETE 2008 Form 10-K

26

2008 Compared to 2007 (Continued)

Investments and Other (Continued)

ALLETE Properties	2008		2007
Revenue and Sales Activity	Quantity	Amount	Quantity	Amount
Dollars in Millions
Revenue from Land Sales
Non-residential Sq. Ft.	–	–	580,059	$17.0
Residential Units	–	–	736	14.8
Acres (a)	219	$6.3	483	10.6
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		8.3		6.2
		$18.3		$50.5

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

Operating expenses decreased $5.7 million, or 6 percent, from 2007 reflecting a decrease in the cost of real estate sold and decreased selling expenses.

Other income increased $0.6 million, or 5 percent, from 2007 primarily due to a $3.8 million after-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.

Income Taxes – Consolidated

For the year ended December 31, 2008, the effective tax rate on income from continuing operations before minority interest was 34.3 percent (34.8 percent for the year ended December 31, 2007). The effective tax rate in both years deviated from the statutory rate (approximately 40 percent) primarily due to the recognition of various tax benefits as well as deductions for Medicare health subsidies, AFUDC-Equity, investment tax credits, and wind production 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.

2007 Compared to 2006

Regulated Operations

Operating revenue increased $84.6 million, or 13 percent, from 2006 primarily due to increased fuel and purchased power recoveries, increased kilowatt-hour sales to residential, commercial and municipal customers, increased power marketing prices, and rate increases at SWL&P.

Fuel and purchased power recoveries increased due to a $65.9 million increase in purchased power expense. (See Fuel and Purchased Power Expense discussion below.)

Revenue recovered through current cost recovery related to AREA Plan expenditures represented $3.2 million in 2007 ($0.1 million in 2006).

Revenue from sales to Other Power Suppliers increased $3.6 million from 2006 primarily due to a 3.6 percent increase in the price per kilowatt-hour.

New rates at SWL&P, which became effective January 1, 2007, reflect a 2.8 percent increase in electric rates, a 1.4 percent increase in gas rates and an 8.6 percent increase in water rates. These rate increases resulted in a $1.7 million increase in operating revenue.

ALLETE 2008 Form 10-K

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2007 Compared to 2006 (Continued)

Regulated Operations (Continued)

Overall, kilowatt-hour sales were flat in 2007. Combined residential, commercial and municipal kilowatt-hour sales increased 181.0 million, or 5.3 percent, from 2006 while industrial kilowatt-hour sales decreased by 152.0 million, or 2.1 percent. The increase in residential, commercial and municipal kilowatt-hour sales was primarily because of two existing municipal customers converting to full-energy requirements and a 9.2 percent increase in Heating Degree Days. The reduction in industrial kilowatt-hour sales was primarily due to an idle production line and production delays at one of our taconite customers. In September 2007, the affected taconite customer resumed production on the idle line. Minor fluctuations in industrial kilowatt-hour sales generally do not have a large impact on revenue due to a fixed demand component of revenue that is less sensitive to changes in kilowatt-hours sales.

Kilowatt-hours Sold	2007	2006
Millions
Regulated Utility
Retail and Municipals
Residential	1,141	1,100
Commercial	1,373	1,335
Industrial	7,054	7,206
Municipals	1,008	911
Other	84	79
Total Retail and Municipals	10,660	10,631
Other Power Suppliers	2,157	2,153
Total Regulated Utility	12,817	12,784

Revenue from electric sales to taconite customers accounted for 24 percent of consolidated operating revenue in 2007 and 2006. Revenue from electric sales to paper and pulp mills accounted for 9 percent of consolidated operating revenue in each of 2007 and 2006. Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2007 (6 percent in 2006).

Operating expenses increased $76.9 million, or 14 percent, from 2006.

Fuel and Purchased Power Expense increased $65.9 million, or 23 percent, from 2006 primarily due to a $61.4 million increase in purchased power reflecting a 45 percent increase in market purchases and an 11 percent increase in market prices. The increase in purchased power expense reflects lower electricity production at the Company’s generation facilities.

Boswell Unit 4 completed generator repairs and returned to service in May 2007. Substantially all of the costs of the replacement coils were covered under the original manufacturer’s warranty.

Lower Square Butte entitlement and output contributed to higher purchased power expense. (See Note 8. Commitments, Guarantees and Contingencies.) Square Butte generation was lower in the fourth quarter of 2007 reflecting a major scheduled outage.

Replacement purchased power costs are recovered through the fuel adjustment clause in Minnesota.

Operating and Maintenance Expense increased $11.4 million, or 5 percent, from 2006 due to a $9.0 million increase in plant maintenance primarily due to planned and unscheduled outages and salary and wage increases.

Depreciation Expense decreased $0.4 million, or 1 percent, from 2006 primarily due to the life extension of Boswell Unit 3, mostly offset by higher depreciable asset balances.

Interest expense increased $0.8 million, or 4 percent, from 2006 primarily due to higher debt balances reflecting increased construction activity. The increase was partially offset by the capitalization of more AFUDC-Debt.

Other income increased $3.2 million from 2006 primarily due to higher earnings from the capitalization of AFUDC-Equity reflecting increased construction activity.

Equity earnings increased $9.6 million in 2007 resulting from our pro-rata share of ATC’s earnings as discussed in Note 6. Our initial investment in ATC began in May 2006.

ALLETE 2008 Form 10-K

28

2007 Compared to 2006 (Continued)

Investments and Other

Operating revenue decreased $10.0 million, or 8 percent, from 2006 primarily due to a decline in revenue from land sales at ALLETE Properties in 2007, partially offset by higher revenue at BNI Coal realized under a cost-plus coal supply agreement. Revenue from land sales at ALLETE Properties in 2007 was $44.3 million, which included $3.1 million in previously deferred revenue. In 2006, revenue from land sales was $56.1 million which included $9.7 million in previously deferred revenue.

ALLETE Properties	2007		2006
Revenue and Sales Activity	Quantity	Amount	Quantity	Amount
Dollars in Millions
Revenue from Land Sales
Non-residential Sq. Ft.	580,059	$17.0	401,971	$10.8
Residential Units	736	14.8	973	15.9
Acres (a)	483	10.6	732	24.4
Contract Sales Price (b)		42.4		51.1
Revenue Recognized from
Previously Deferred Sales		3.1		9.7
Deferred Revenue		(1.2)		(3.8)
Adjustments (c)		–		(0.9)
Revenue from Land Sales		44.3		56.1
Other Revenue		6.2		6.5
		$50.5		$62.6

(a) Acreage amounts are shown on a gross basis, including wetlands and minority 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) Contributed development dollars, which are credited to cost of real estate sold.

Operating expenses increased $4.3 million, or 5 percent, from 2006 reflecting higher coal production expense at BNI Coal and higher property taxes. The increase in property taxes is primarily due to higher assessed market values on our Minnesota land, while the increase in BNI Coal operating expenses is due to higher fuel costs, tire, and dragline repairs. At ALLETE Properties, higher community development district property tax assessments were partially offset by lower cost of sales.

Interest expense decreased $3.2 million from 2006 primarily due to more interest charged to the regulated utility in 2007 as a result of increased capital expenditures and interest on additional taxes owed on the gain on sale of our Florida Water Services Corporation assets in 2006. This decrease was partially offset by an increase of $0.5 million due to lower interest capitalization as the major infrastructure construction at Town Center was substantially completed at the end of 2006.

Other income increased $0.4 million from 2006 reflecting higher gains on Minnesota land sales and higher lease lot revenue due to leasing newly developed lots, partially offset by lower investment income as a result of lower average balances in 2007 and the release from a loan guarantee for Northwest Airlines, Inc. of $1.0 million.

Minority interest participation decreased due to lower Real Estate earnings.

Income Taxes – Consolidated

For the year ended December 31, 2007, the effective tax rate on income from continuing operations before minority interest was 34.8 percent (36.1 percent for the year ended December 31, 2006). The decrease in the effective rate compared to 2006 was primarily due to a tax benefit realized as a result of a state income tax audit settlement ($1.6 million), higher AFUDC-Equity, and a larger domestic manufacturing deduction taken in 2007 compared to 2006. The effective rate of 34.8 percent for the year ended December 31, 2007, deviated from the statutory rate (approximately 40 percent) due to the state income tax audit settlement, deductions for Medicare health subsidies and domestic manufacturing production, AFUDC-Equity and investment tax credits.

Critical Accounting Estimates

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.

ALLETE 2008 Form 10-K

29

Critical Accounting Estimates (Continued)

Regulatory Accounting. Our regulated utility operations are subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS 71 requires 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 regulatory assets and liabilities in accordance with applicable state and federal regulatory rulings. The recoverability of regulatory assets is periodically assessed by considering factors such as, but not limited to, changes in regulatory rules and rate orders issued by applicable regulatory agencies. The assumptions and judgments used by regulatory authorities may have an impact on the recovery of costs, the rate of return on invested capital,and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material impact on our results of operations. (See Note 5. Regulatory Matters.)

Valuation of Investments. 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, our emerging technology portfolio, and auction rate securities. As part of our emerging technology portfolio, we have several minority investments in venture capital funds and direct investments in privately-held, start-up companies. We account for our investment in venture capital funds under the equity method and account for our direct investments in privately-held companies under the cost method because of our ownership percentage. 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. Any impairment would reduce the carrying value of the investment and be recognized as a loss. In 2008, there were no impairment losses recognized ($0.5 million pretax in 2007 and none in 2006). (See Note 6. Investments.)

Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and postretirement benefit obligations in accordance with the provisions of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” SFAS 87, “Employers’ Accounting for Pensions,” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” These standards require the use of assumptions in determining our obligations and annual cost of our pension and postretirement benefits. An important actuarial assumption for pension and other postretirement benefit plans is the expected long-term rate of return on plan assets. In establishing this assumption, we consider the diversification and allocation of plan assets, the actual long-term historical performance for the type of securities invested in, the actual long-term historical performance of plan assets and the impact of current economic conditions, if any, on long-term historical returns. Our pension asset allocation at December 31, 2008, was approximately 46 percent equity, 32 percent debt, 16 percent private equity, and 6 percent real estate. Equity securities consist of a mix of market capitalization sizes and both domestic and international securities. We currently use an expected long-term rate of return of 8.5 percent in our actuarial determination of our pension and other postretirement expense. We annually review our expected long-term rate of return assumption 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 million, pre-tax.

For plan valuation purposes, we currently use a discount rate of 6.12 percent. The discount rate is determined considering high-quality long-term corporate bond rates at the valuation date. The discount rate is compared to the Citigroup Pension Discount Curve adjusted for ALLETE’s specific cash flows. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows for our pension obligation. (See Note 14. Pension and Other Postretirement Benefit Plans.)

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 FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109”. 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 recorded 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 asset will not be realized.

ALLETE 2008 Form 10-K

30

Outlook

ALLETE is committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. Minnesota Power’s industrial customers are facing weak conditions in the markets for their products, and have and may continue to reduce the amount of energy they use. We will work to sell this released energy in the wholesale markets, and believe that our ability to produce energy at low cost will be a competitive advantage. Our focus will be to maintain the competitively-priced production of energy, while meeting environmental requirements. Minnesota Power will also focus on maintaining competitive retail rates, as we believe this is important to the success of our customers. Information published by the Edison Electric Institute in mid-2008 ranked Minnesota Power as having the ninth lowest retail rates out of 175 investor-owned utilities in the United States.

Our strategy going forward is to focus on growth opportunities within our core business as we expect to continue making significant investments to comply with renewable and environmental requirements, maintain our existing low-cost generation fleet, and strengthen and enhance the regional transmission grid. We will also look for additional transmission and renewable energy opportunities which take advantage of our geographical location between sources of renewable energy and growing energy markets. Earnings from our ATC investment are expected to grow as we anticipate making additional investments to fund our pro-rata share of ATC’s capital expansion program. We expect to invest an additional $5 to $7 million in ATC during 2009.

Regulated Operations. Minnesota Power expects significant rate base growth over the next several years as it continues its program to comply with renewable energy requirements and environmental mandates. In addition, significant investment will be made in our existing low-cost generation fleet to provide for continued future operations. We anticipate our capital investments will be recovered through a combination of current cost recovery riders and anticipated increased base electric rates. We also expect an average annual kilowatt-hour growth of approximately 1 percent from our existing customers, as well as potential long term growth from several new industrial customers planning projects in our service territory.

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

On February 8, 2008, the FERC approved Minnesota Power’s wholesale tariff rate increase effective March 1, 2008. Minnesota Power’s wholesale customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. The FERC authorized an average 10.0 percent increase for wholesale municipal customers, and an overall return on equity of 11.25 percent. Incremental revenue in 2008 from the FERC authorized wholesale rate increase was approximately $6 million.

In 2008, Minnesota Power entered into new contracts with all of our wholesale customers with the exception of one small customer whose contract is now in the cancellation period. The new contracts transition each customer to formula based rates, which means rates can be adjusted annually based on changes in costs. The new agreement with the private utility in Wisconsin is subject to PSCW approval. In November 2008, we filed a request with the FERC to implement the formula based rate provision in the new contracts. We anticipate final resolution and implementation of new rates in the first quarter of 2009.

On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC seeking an average rate increase of 8.5 percent for retail customers. The rate filing seeks a return on equity of 11.15 percent, and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. On an annualized basis, the requested rate increase would generate approximately $40 million in additional revenue. Interim rates were effective on August 1, 2008, and resulted in an increase for retail customers of approximately $36 million, or 7.5 percent, on an annualized basis, subject to refund pending the final rate order. Incremental revenue in 2008 from the interim retail rate increase was approximately $13 million. The transition to a new base cost of fuel coincident with interim rates resulted in the non-recovery through the fuel adjustment clause of approximately $19 million of fuel and purchased power costs incurred in 2008. We have entered into a stipulation and settlement agreement that would allow recovery of the $19 million in 2009 and which addresses specific concerns identified by interveners in the rate case; the stipulation and settlement agreement is subject to MPUC approval. The final rate order is expected in the second quarter of 2009. We cannot predict the final level of rates that may be approved by the MPUC. Prior to the May 2008 retail rate request Minnesota Power’s rates were based on a 1994 MPUC retail rate order that allowed for an 11.6 percent return on equity.

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 common 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.

ALLETE 2008 Form 10-K

31

Outlook (Continued)

Regulated Operations (Continued)

Industrial Customers. Electric power is one of several key inputs in the mining, paper production, and pipeline industries. Approximately 57 percent of our Regulated Utility kilowatt-hour sales were made to our industrial customers in 2008, which include the taconite, paper and pulp, and pipeline industries.

Strong worldwide steel demand, driven largely by extensive infrastructure development in China, resulted in very robust world iron ore demand and steel pricing for nearly a six year period which lasted through the summer of 2008. Between 2004 and 2008 annual taconite production averaged just over 40 million tons per year from taconite mines in Northeastern Minnesota. Beginning in the fall of 2008, worldwide steel makers began to dramatically cut steel production in response to reduced demand driven largely by the world credit situation. During the fourth quarter of 2008, United States raw steel production was running at less than 50 percent of capacity and at levels not seen since the early 1980s. Currently, domestic raw steel production is at 45 percent of capacity reflecting poor demand in automobiles, durable goods, structural, and other steel products. Minnesota taconite producers began to be impacted in late 2008 and reduced production levels are expected in 2009. Consequently, 2009 demand nominations for power from our taconite customers are expected to be lower by at least 25 percent from 2008 levels. We intend to remarket 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. To date in 2009, we have sold power to Other Power Suppliers to mitigate the demand reductions made to date from our taconite customers. These contracts expire at various times during 2009, and have pricing levels similar to the rates charged to our large power customers. We will have additional power to sell in 2009 if our taconite customers continue to reduce their demand; we are unable to predict pricing levels on such sales at this time.

Minnesota Power’s paper and pulp customers ran at, or very near, full capacity for the majority of 2008 despite the fact that the industry continued to face high fiber, chemical, and energy costs as well as competition from exports in certain grades of paper products. Minnesota Power’s customers benefited from the temporary or permanent idling of plants both in North America at mills other than those served by Minnesota Power and the idling of plants in Europe, as well as continued (but declining) strength of the Canadian dollar and the Euro which has reduced imports both from Canada and Europe.

Our pipeline customers continued to operate at or above historic pumping levels during 2008 and forecast operating at record pumping levels in 2009. As Western Canadian oil sands reserves continue to develop and expand, pipeline operators served by the Company are executing expansion plans to transport additional crude oil supply to United States markets. We believe we are strategically positioned to serve these expanding pipeline facilities as Canadian supply continues to grow and displace domestic and imported Gulf Coast production.

Several natural resource-based companies continue to make progress developing new projects in Northeastern Minnesota that have the potential for long-term growth for Minnesota Power. These potential projects are in the ferrous and non-ferrous mining, paper, oil and steel related industries. They include the Polymet Mining Corp. (Polymet), Mesabi Nugget Delaware, LLC (Mesabi Nugget) and Essar Steel Limited Minnesota projects, as well as a proposed expansion at the Keewatin Taconite facility of United States Steel Corporation.

PolyMet.In 2007, the MPUC approved our contract with PolyMet, a new customer planning to start a copper, nickel and precious metals (non-ferrous) mining operation in Northeastern Minnesota. If PolyMet receives all necessary environmental permits and achieves start-up, the contract will run through at least 2018 and supply approximately 70 MWs of capacity. PolyMet continues to make progress towards production. In December 2008, PolyMet received a draft environmental impact statement from the Minnesota Department of Natural Resources.

Mesabi Nugget.In 2007, Minnesota Power entered into a contract with Mesabi Nugget, a joint venture between Steel Dynamics, Inc. and Kobe Steel Ltd. Mesabi Nugget will produce high-quality iron nuggets to supply steel mills owned by Steel Dynamics. Construction of the facility, near Hoyt Lakes, Minnesota, began in 2007 and completion is expected in late 2009. Mesabi Nugget is expected to initially be a 15-MW customer, with the potential for future load growth. The MPUC approved contract runs through at least 2017.

Keewatin Taconite. In February 2008, United States Steel announced its intent to restart a pellet line at its Keewatin Taconite processing facility. This pellet line, which has been idled since 1980, would be restarted and updated as part of a $300 million investment. It is anticipated to bring about 3.6 million tons of additional pellet making capability to Northeastern Minnesota, pending successful approval of environmental permitting.

In March 2008, Minnesota Power signed a new contract with Northshore Mining Company to meet additional load requirements. The contract was approved by the MPUC and runs through at least June 30, 2011.

In September 2008, Cliffs and Minnesota Power signed new contracts for service to Hibbing Taconite Co. and United Taconite LLC. These electric service agreements, which are pending final MPUC approval, extend the existing contract terms out to at least December 31, 2015.

ALLETE 2008 Form 10-K

32

Outlook (Continued)

Regulated Operations (Continued)

Renewable Generation Sources. In February 2007, Minnesota enacted a law requiring Minnesota Power to generate or procure 25 percent of its energy 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, 20 percent by 2020, and 25 percent by 2025. The law allows the MPUC to modify or delay a standard obligation if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developing and making renewable supply additions as part of its generation planning strategy prior to the enactment of this law and this activity continues.Minnesota Power believes it will meet the requirements of this legislation.

The areas in which we operate have strong wind, water and biomass resources, and provide us with opportunities to develop a number of renewable forms of generation. Our electric service area in northeastern Minnesota is situated for delivery of renewable energy that is generated here and in adjoining regions. We intend to secure the most cost competitive and geographically advantageous renewable energy resources available. We believe that the demand for these resources is likely to grow, and the costs of the resources to generate renewable energy will continue to escalate. While we intend to maintain our disciplined approach to developing generation assets, we also believe that by acting sooner rather than later we can deliver lower cost power to our customers and maintain or improve our cost competitiveness among regional utilities. We will continue to work cooperatively with our customers, our regulators and the communities we serve to develop generation options that reflect the needs of our customers as well as the environment. We believe that our location and our proactive leadership in developing renewable generation provide us with a competitive advantage. For more than a century, we have been Minnesota’s leading producer of renewable hydroelectric energy.

We are executing our renewable energy and environmental compliance strategy. Taconite Ridge Wind I, a $50 million, 25-MW wind facility located in northeastern Minnesota became operational in July 2008. In 2006 and 2007, we began long term purchase power agreements for 98 MWs of wind energy constructed in North Dakota (Oliver Wind I and II); 366,945 megawatt-hours were purchased under these agreements in 2008.

On May 13, 2008, we announced plans to develop several hundred megawatts of wind energy in North Dakota and purchase an existing 250 kV DC transmission line to transport this wind energy to our customers while gradually reducing the supply of energy currently delivered to our system on this same transmission line from Square Butte’s coal-fired Milton R. Young Unit 2. The North Dakota wind project is expected to complete the 2025 renewable energy supply requirements for our retail load. In September 2008, we signed an agreement to purchase the transmission line from Square Butte Electric Cooperative for approximately $80 million. The transaction is subject to regulatory approvals and is anticipated to close in 2009.

In January 2008, Minnesota Power and Manitoba Hydro executed a term sheet to purchase surplus energy beginning in 2009 and an anticipated 250-MW capacity purchase to begin in about 2020. Minnesota Power anticipates the initial purchase of surplus energy will be about 100 MWs during high hydro production periods in the spring and fall. 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. In November 2008, we signed an amendment to the term sheet extending the deadline to complete negotiations and sign a definitive agreement from November 30, 2008, to October 31, 2009. Both purchases require MPUC approval.

Integrated Resource Plan.On October 31, 2007, Minnesota Power filed its Integrated Resource Plan (IRP), a comprehensive estimate of future capacity needs within the Minnesota Power service territory. In October 2008, the MPUC issued an order approving our request to re-file the IRP by October 1, 2009 in order to incorporate the North Dakota wind project and otherwise update our load forecasting and modeling in the IRP.

Minnesota Power plans to meet expected loads through 2020 by adding a significant amount of renewable generation and some supporting peaking generation. We plan to add 300 to 500 MWs of carbon-minimizing renewable energy to our generation mix. Besides the additional generation from renewable sources, Minnesota Power anticipates future supply could come from a combination of sources, including:

· “As-needed” peaking and intermediate generation facilities;

· Expiration of wholesale contracts presently in place;

· Short-term market purchases;

· Improved efficiency of existing generation and power delivery assets; and

· Expanded conservation and demand-side management initiatives.

We do not anticipate the need for new base load system generation within the Minnesota Power service territory through approximately 2020, and we project a one percent average annual growth in electric usage from our existing customers over that time frame.

ALLETE 2008 Form 10-K

33

Outlook (Continued)

Regulated Operations (Continued)

Climate Change. Minnesota Power has a long history of environmental stewardship. A key component of our energy strategy is a goal to reduce overall GHG emissions.

We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals on the Federal level to “cap” the amount of GHG emissions have been made. Other proposals consider establishing emissions allowances or taxes as economic incentives to address the GHG emission issue.

In 2007, Minnesota passed legislation establishing non-binding targets for GHG reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors producing those emissions 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. We are proactively taking steps to strategically engage the GHG emission issue and the impact of climate change regulation on our business.

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

· We will consider only carbon minimizing resources to supply power to our customers. We will not consider a new coal resource without a carbon emission solution.

· We are pursuing Minnesota’s Renewable Energy Standard by adding significant renewable resources to our portfolio of generation facilities and power supply agreements.

· We plan to continue improving the efficiency of our coal-based generation facilities.

· We plan to implement demand side conservation efforts.

· We will continue to support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.

· We plan to achieve overall carbon emission reductions while maintaining competitively priced electric service to our customers.

The Company has become a “founding reporter” of The Climate Registry, an organization established to measure and publicly report GHG emissions consistently and accurately across borders and industry sectors. In becoming one of the founding reporters of The Climate Registry, we have voluntarily committed to measure, independently verify and publicly report our GHG emissions annually.

CapX 2020.Minnesota Power is a participant in the CapX 2020 initiative which represents an effort to ensure the electricity reliability of Minnesota and the surrounding region for the future. CapX 2020 includes the state's largest transmission owners, including 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.

The CapX 2020 participants filed a Certificate of Need for three 345 kV lines and associated system interconnections with the MPUC in August 2007. Following a public process, the MPUC is expected to decide on the need for these 345 kV lines by early 2009. If the MPUC issues the required Certificate of Need, the MPUC will then determine routes for the new lines in subsequent proceedings. Portions of the 345 kV lines will also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. A fourth line, a 230 kV line in north central Minnesota, is also among the CapX 2020 projects. A request for a Certificate of Need Permit for this line was filed in March 2008, and a Route Permit application was filed in June 2008. The MPUC decision on need and routing are expected in 2010.

Minnesota Power may invest in two of the 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. Our total investment in these two lines would be approximately $80 million. Upon receipt of the required Certificates of Need, we intend to include these costs in an annual filing with the MPUC for current cost recovery of the expenditures related to our investment in the lines under a Minnesota Power transmission cost recovery tariff rider mechanism authorized by Minnesota legislation. Construction of the lines is targeted to begin in 2010 and last approximately three to four years.

ALLETE 2008 Form 10-K

34

Outlook (Continued)

Regulated Operations (Continued)

AREA and Boswell Unit 3 Emission Reduction Plans. In May 2006, the MPUC authorized current cost recovery of expenditures to reduce emissions of SO2, NOX, and mercury emissions at Taconite Harbor and Laskin under the AREA Plan. The AREA Plan has significantly reduced emissions from Taconite Harbor and Laskin, while maintaining a reliable and reasonably-priced energy supply to meet the needs of our customers. Environmental retrofits at Laskin and Taconite Harbor Units 1 and 2 are complete and in service. The environmental regulatory requirements for Taconite Harbor Unit 3 are pending finalization of the Minnesota Regional Haze implementation plan by the MPCA. We are expecting to retrofit Taconite Harbor Unit 3 by 2013 and are evaluating compliance requirements and cost recovery options for this final unit.

We are making emission reduction investments at our Boswell Unit 3 generating unit. The investments in pollution control equipment will reduce particulates, SO2, NOX, and mercury emissions to meet future federal and state requirements. The MPUC has authorized a cash return on construction work in progress during the construction phase in lieu of AFUDC-Equity and allows for a return on investment and current cost recovery of incremental operations and maintenance expenses once the new equipment is installed and the unit is placed back in service in late 2009. We began cost recovery on January 1, 2008. In September 2008, we filed a petition with the MPUC to approve the Boswell Unit 3 rate adjustment for 2009. If approved, new rates would allow cost recovery relating to additional investments planned for 2009.

Boswell NOX Reduction Plan. In September 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for NOX emission reductions from Boswell Units 1, 2, and 4. If approved by the MPUC, the Boswell NOX Reduction Plan is expected to significantly reduce NOX emissions from these units. In conjunction with the NOXreduction, we plan to install an efficiency improvement to the existing turbine/generator at Boswell Unit 4 adding approximately 60 MWs of total output with no additional emissions. A second filing requesting cost recovery for the plan will be submitted to the MPUC in the first quarter of 2009.

Transmission. In September 2008, we filed a petition with the MPUC seeking total 2009 cost recovery of $2.2 million for ongoing expenditures related to the Badoura and Tower transmission projects and certain MISO related transmission facility charges. The Tower and Badoura projects are being developed to address transmission inadequacies in northeastern Minnesota. Both projects will provide regional transmission benefits through increased voltage support and additional line capacity.

Depreciation. In a November 2008 Order, the MPUC increased depreciation rates for certain assets effective January 1, 2008. Minnesota Power had been seeking to have the increased depreciation rates become effective with the date of final rates in the current retail rate filing (expected to be in the second quarter of 2009). Under this order, depreciation expense increased approximately $3 million in 2008.

Investment in ATC. At December 31, 2008, our equity investment was $76.9 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 $2.7 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 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 30, 2009, we invested an additional $1.9 million into ATC. In total, we expect to invest an additional $5 to $7 million throughout 2009.

Investments and Other

BNI Coal.In 2008, BNI Coal sold approximately 4.5 million tons of coal (4.0 million tons in 2007) and anticipates similar sales in 2009.

ALLETE Properties.ALLETE Properties is our real estate business that has operated in Florida since 1991. Our current strategy is to complete and maintain key entitlements and infrastructure improvements which enhance values without requiring significant additional investment, and position the current property portfolio for a maximization of value and cash flow when market conditions improve.

Our two major development projects include Town Center and Palm Coast Park. A third proposed development project, Ormond Crossings, is in the permitting and planning stage. Development activities involve mainly zoning, permitting, platting, and master infrastructure construction. See Item 1. Business – Investments and Other for additional descriptions of each of our development projects. Development costs are financed through a combination of community development district bonds, bank loans, and internally-generated funds.

ALLETE 2008 Form 10-K

35

Outlook (Continued)

Investments and Other (Continued)

Summary of Development Projects		Total	Residential	Non-residential
Land Available-for-Sale	Ownership	Acres (a)	Units (b)	Sq. Ft. (b, c)
Current Development Projects
Town Center	80%
At December 31, 2007		991	2,289	2,228,200
Property Sold		–	–	–
At December 31, 2008		991	2,289	2,228,200
Palm Coast Park	100%
At December 31, 2007		3,436	3,154	3,116,800
Property Sold		–	–	–
Change in Estimate		–	85	–
At December 31, 2008		3,436	3,239	3,116,800
Total Current Development Projects		4,427	5,528	5,345,000
Proposed Development Project
Ormond Crossings	100%
At December 31, 2008		5,968	(d)	(d)
Total of Development Projects at December 31, 2008		10,395	5,528	5,345,000

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

(b) Estimated and includes minority interest. 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 approved by the City of Ormond Beach includes up to 3,700 residential units and 5 million square feet of non-residential space. We estimate the first two phases of Ormond Crossings will include 2,500-3,200 residential units and 2.5-3.5 million square feet of various types of non-residential space.Density of the residential and non-residential components of the project will be determined based upon market and traffic mitigation cost considerations. Approximately 2,000 acres will be devoted to a regionally significant wetlands mitigation bank.

Other Land Available-for-Sale (a)	Total	Mixed Use	Residential	Non-residential	Agricultural
Acres (b)
At December 31, 2007	1,573	362	248	424	539
Property Sold	(166)	(2)	(134)	(18)	(12)
Contributed Land	(54)	–	–	–	(54)
Change in Estimate	–	(7)	–	(4)	11
At December 31, 2008	1,353	353	114	402	484

(a) Other land includes land located in Palm Coast, Florida not included in development projects, Lehigh Acquisition Corporation and Cape Coral Holdings, Inc.

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

Pending Contracts. At December 31, 2008, total pending land sales under contract were $12.4 million ($55.2 million at December 31, 2007) and are scheduled to close at various times through 2009. However, given current market conditions it may be difficult to complete these closings in 2009. In July 2008, a $28.9 million contract with LDD Palm Coast North LLC, a subsidiary of Lowe Enterprises was terminated, and a $0.6 million contract deposit was forfeited. We are currently reviewing the best options to proceed with this property. We believe this property, along with the remaining property at Palm Coast Park, continues to have long-term value. We continue to have discussions with other buyers under pending contracts. Our objective is to proactively assist our buyers through this current period of weak market conditions, as we believe the long-term prospects for our properties are favorable. Our discussions sometimes result in adjustments to contract terms, and may include extending closing dates, revised pricing or termination. 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 2008 Form 10-K

36

Outlook (Continued)

Investments and Other (Continued)

Emerging Technology. We have the potential to recognize gains or losses on the sale of investments in our emerging technology portfolio. We plan to sell investments in our emerging technology portfolio when publically traded shares are distributed to us. Some restrictions on sales may apply, including, but not limited to, underwriter lock-up periods that typically extend for 180 days following an initial public offering. We have committed to make up to $0.7 million in additional investments in certain emerging technology holdings. We do not have plans to make any additional investments beyond this commitment.

Income Taxes.ALLETE’s aggregate federal and multi-state statutory tax rate is expected to be approximately 40 percent for 2009. 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 production 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 minority 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. We expect our effective tax rate to be approximately 36 percent for 2009.

Liquidity and Capital Resources

Cash Flow Activities

ALLETE is well-positioned to meet the Company’s immediate cash flow needs. With our cash balance of approximately $102 million, $160.5 million in Lines of Credit which includes a committed, syndicated, unsecured revolving line of credit of $150 million, and a debt to capital ratio of 42.2 percent at December 31, 2008, we project sufficient capital availability through the immediate term. If needed, we have the flexibility to reduce our planned capital expenditure program to meet changing capital market conditions.

Operating Activities. Cash from operating activities was $152.1 million for 2008 ($123.1 million for 2007; $142.0 million for 2006). Cash from operating activities was higher in 2008 than 2007 due to an increase in deferred income tax expense and decreased working capital requirements, which was partially offset by lower net income 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 bonus depreciation provisions of the Economic Stimulus Act of 2008, and contributions to defined benefit pension and postretirement health plans increased $15.6 million during 2008.

Cash from operating activities was lower in 2007 than 2006 primarily due to a decrease in cash flow from operating assets and liabilities. Colder weather in December 2007 resulted in an increase in customer receivables of $14.7 million compared to 2006. Cash used for prepayments and other was higher in 2007 than 2006 due to an $11.5 million change in deferred fuel costs. The increase in deferred fuel costs was the result of higher purchased power expenses due to generation outages relating to the AREA Plan environmental retrofits, lower hydro generation, lower Square Butte entitlement and Square Butte’s major scheduled outage. Other current liabilities decreased primarily due to a reduction in accrued taxes of $8.9 million. The decrease in cash from operating activities for 2007 was partially offset by increased earnings from continuing operations of $11.2 million and a decrease in cash used for discontinued operations of $13.5 million.

Investing Activities. Cash used for investing activities was $276.1 million for 2008 ($154.1 million for 2007; $154.2 million for 2006). Cash used for investing activities was higher 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 increased due to construction activity for environmental retrofit projects, AREA Plan projects, Taconite Ridge, and additional investments in ATC.

Cash used for investing activities was insignificantly lower in 2007 than 2006 primarily due to an increase of $81.4 million in net sales of short-term investments compared to $12.4 million in 2006. The net proceeds from the sale of short-term investments were used to fund increased additions to property, plant and equipment. Additions to property, plant and equipment were higher in 2007 than 2006 by $111.7 million primarily due to increased spending on major environmental construction projects. Cash invested in ATC decreased from $51.4 million in 2006 to $8.7 million in 2007.

Financing Activities. Cash from financing activities was $202.7 million for 2008 (cash from financing activities was $9.5 million for 2007; cash used for financing activities was $32.6 million for 2006). The increase in cash from financing activities resulted from the issuance of three series of first mortgage bonds: $60 million in February 2008; $75 million in May 2008; and $38 million in December 2008. In addition, 1.8 million shares of common stock were issued for net proceeds of $71.1 million. Financing activities increased to support our current capital expenditure program.

Cash from financing activities was higher in 2007 than 2006 primarily due to additional long-term debt issued in 2007, which included $60 million of first mortgage bonds, $50.0 million of senior unsecured notes and $12.5 million in collateralized tax exempt bonds at SWL&P. The increase in new long-term debt was offset partially by the retirement of $20.0 million in first mortgage bonds, $2.5 million in variable demand revenue refunding bonds and $6.5 million in SWL&P first mortgage bonds.

ALLETE 2008 Form 10-K

37

Liquidity and Capital Resources (Continued)

Cash Flow Activities (Continued)

Working Capital. Additional working capital, if and when needed, generally is provided by the sale of commercial paper. We have 0.8 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan. Additionally, we have 0.9 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. We have consolidated bank lines of credit aggregating $160.5 million, the majority of which expire in January 2012. In January 2006, we renewed, increased and extended a committed, syndicated, unsecured revolving credit facility (Line) with Bank of America as Agent, and four other banks, for $150 million. No individual bank has more than 25 percent participation in the Line. The Line was subsequently extended for an additional year in December 2006 and currently matures on January 11, 2012. At our request and subject to certain conditions, the Line may be increased to $200 million and extended for two additional 12-month periods. We may prepay amounts outstanding under the Line in whole or in part at our discretion. Additionally, we may irrevocably terminate or reduce the size of the Line prior to maturity. The Line may be used for general corporate purposes, working capital and to provide liquidity in support of our commercial paper program. The amount and timing of future sales of our securities will depend upon market conditions and our specific needs. We may sell securities to meet capital requirements, to provide for the retirement or early redemption of issues of long-term debt, to reduce short-term debt and for other corporate purposes.

Auction Rate Securities. As of December 31, 2008, we held $15.2 million of investments ($23.1 million at December 31, 2007) consisting of three auction rate municipal bonds (auction rate securities) with stated maturity dates ranging between 15 and 28 years. These ARS consist of guaranteed student loans insured or reinsured by the federal government and were historically auctioned every 35 days to set new rates and provide a liquidating event in which investors could either buy or sell securities. The auctions have been unable to sustain themselves during 2008 due to the overall lack of credit market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified the 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. In the meantime, these securities will pay a default rate which is typically above market interest rates.

The Company has used a discounted cash flow model to determine the estimated fair value of its investment in ARS as of December 31, 2008. The assumptions used in preparing the discounted cash flow model include the following: estimated interest rates, estimated discount rates (using yields of comparable traded instruments adjusted for illiquidity and other risk factors), 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. Based upon the results of the discounted cash flow model and the fact that these ARS consist of guaranteed student loans insured or reinsured by the federal government no other than temporary impairment loss has been reported.

Securities. On December 10, 2007, ALLETE filed a registration statement with the SEC, pursuant to Rule 415 under the Securities Act of 1933, relating to the possible issuance from time to time of ALLETE common stock or first mortgage bonds. The amount of securities issuable by ALLETE is established from time to time by its board of directors. We may sell all or a portion of the above-described registered securities if warranted by market conditions and our capital requirements. Any offer and sale of the above-mentioned securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations there under.

On February 1, 2008, we issued $60 million in principal amount of First Mortgage Bonds, 4.86% Series due April 1, 2013, in the private placement market. 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 used the proceeds from the sale of the bonds to fund utility capital expenditures and for general corporate purposes.

On May 14, 2008, we issued $75 million in principal amount of First Mortgage Bonds, 6.02% Series due May 1, 2023, in the private placement market. 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 used the proceeds from the sale of the bonds to fund utility capital expenditures and for general corporate purposes.

We issued $80 million in principal amount of First Mortgage Bonds in the private placement market in three series as follows:

Issue Date	Maturity	Amount	Coupon
December 15, 2008	January 15, 2014	$18 Million	6.94%
December 15, 2008	January 15, 2016	$20 Million	7.70%
January 15, 2009	January 15, 2019	$42 Million	8.17%

ALLETE 2008 Form 10-K

38

Liquidity and Capital Resources (Continued)

Securities (Continued)

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 intend to use the proceeds from the sale of the bonds to fund utility capital expenditures and for general corporate purposes.

On February 19, 2008, we entered into a Distribution Agreement with KCCI, Inc. with respect to the issuance and sale of up to 2.5 million shares of our common stock, without par value. The shares may be offered for sale, from time to time, in accordance with the terms of the Distribution Agreement, which terminates on June 30, 2009. For the year ended December 31, 2008, 1,556,200 shares of common stock have been issued under this agreement resulting in net proceeds of $60.8 million.

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. The most restrictive covenant requires ALLETE to maintain a ratio of its Funded Debt to Total Capital of less than or equal to 0.65 to 1.00 measured quarterly. As of December 31, 2008 our ratio was approximately 0.40 to 1.00. Failure to meet this covenant could give rise to an event of default, if not corrected 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, 2008, ALLETE was in compliance with its financial covenants.

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 8.

Contractual Obligations and Commercial Commitments. Our long-term debt obligations, including long-term debt due within one year, represent the principal amount of bonds, notes and loans which are recorded on our consolidated balance sheet, plus interest. The table below assumes the interest rate in effect at December 31, 2008, remains constant through the remaining term. (See Note 8. Commitment, Guarantees and Contingencies.)

Unconditional purchase obligations represent our Square Butte power purchase agreements, minimum purchase commitments under coal and rail contracts, and purchase obligations for certain capital expenditure projects. (See Note 8. Commitments, Guarantees and Contingencies.)

Under our power purchase agreement with Square Butte that extends through 2026, we are obligated to pay our pro rata share of Square Butte’s costs based on our entitlement to the output of Square Butte’s 455-MW coal-fired generating unit near Center, North Dakota. Our payment obligation is 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 following table reflects our share of future debt service based on our output entitlement of 50 percent. For further information on Square Butte see Note. 8 Commitments, Guarantees and Contingencies.

We have two wind power purchase agreements with an affiliate of NextEra Energy 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 and the output from Oliver Wind II, a 48-MW facility in November 2007. Each agreement is for 25 years and provides for the purchase of all output from the facilities. There are no fixed capacity charges, and we only pay for energy as it is delivered to us.

	Payments Due by Period
Contractual Obligations		Less than	1 to 3	4 to 5	After
As of December 31, 2008	Total	1 Year	Years	Years	5 Years
Millions
Long-Term Debt (a)	$979.6	$40.1	$106.6	$140.8	$692.1
Operating Lease Obligations	93.7	8.3	24.8	15.1	45.5
FIN 48 – Uncertain Tax Positions	1.2	1.0	0.2	–	–
Unconditional Purchase Obligations	352.9	77.1	63.3	28.8	183.7
	$1,427.4	$126.5	$194.9	$184.7	$921.3

(a)      Includes interest and assumes variable interest rates in effect at December 31, 2008, remains constant through remaining term.

We expect to contribute approximately $30 - $35 million to our defined benefit pension plans and $11 million to our postretirement health and life plans in 2009. We are unable to predict contribution levels to our defined benefit pension or postretirement health and life plans after 2009.

ALLETE 2008 Form 10-K

39

Liquidity and Capital Resources (Continued)

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

Credit Ratings	Standard & Poor’s	Moody’s
Issuer Credit Rating	BBB+	Baa1
Commercial Paper	A-2	P-2
Senior Secured
First Mortgage Bonds	A–	A3
Pollution Control Bonds	A–	A3
Unsecured Debt
Collier County Industrial Development Revenue Bonds – Fixed Rate	BBB	–

Payout Ratio. In 2008, we paid out 61 percent (53 percent in 2007; 53 percent in 2006) of our per share earnings in dividends.

On January 22, 2009, our Board of Directors increased the dividend on ALLETE common stock by 2.3 percent, declaring a dividend of $0.44 per share payable on March 1, 2009, to shareholders of record at the close of business on February 16, 2009.

Capital Requirements

ALLETE’s projected capital expenditures for the years 2009 through 2013 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.

Capital Expenditures			2009	2010	2011	2012	2013	Total
Regulated Utility Operations
	Base and Other		$197	$125	$109	$114	$128	$673
	Current Cost Recovery(a)
		Environmental	43	9	37	56	112	257
		Renewable	29	138	16	15	–	198
		Transmission	3	17	18	18	17	73
		Generation	21	17	–	–	–	38
	Total Current Cost Recovery		96	181	71	89	129	566
Regulated Utility Capital Expenditures			293	306	180	203	257	1,239
Other			7	8	11	8	26	60
Total Capital Expenditures			$300	$314	$191	$211	$283	$1,299

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

We intend to finance expenditures from both internally generated funds and incremental debt and equity.

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 8. (See Item 1. Business – Environmental Matters.)

Market Risk

Securities Investments

Available-for-Sale Securities. At December 31, 2008, our available-for-sale securities portfolio consisted of securities in a grantor trust, established to fund certain employee benefits, and auction rate securities. (See Note 6. Investments.)

Emerging Technology Portfolio.As part of our emerging technology portfolio, we have several minority investments in venture capital funds and direct investments in privately-held, start-up companies. (See Note 6. Investments.)

ALLETE 2008 Form 10-K

40

Market Risk (Continued)

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. The table below presents the long-term debt obligations and the corresponding weighted average interest rate at December 31, 2008.

	Expected Maturity Date
Interest Rate Sensitive								Fair
Financial Instruments	2009	2010	2011	2012	2013	Thereafter	Total	Value
Dollars in Millions
Long-Term Debt
Fixed Rate	$2.2	$1.1	$1.2	$1.2	$70.6	$438.6	$514.9	$477.6
Average Interest Rate – %	5.5	6.2	6.2	6.2	5.2	5.6	5.7
Variable Rate	$8.2	$3.6	$10.5	$1.7	$2.8	$57.0	$83.8	$83.8
Average Interest Rate – % (a)	1.2	1.8	3.5	2.7	1.2	1.7	1.9

(a) Assumes rate in effect at December 31, 2008, remains constant through remaining term.

The interest rates on variable rate long-term debt are reset on a periodic basis reflecting current market conditions. Based on the variable rate debt outstanding at December 31, 2008, 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 million. This amount was determined by considering the impact of a hypothetical 100 basis point change to the average variable interest rate on the variable rate debt outstanding as of December 31, 2008.

Commodity Price Risk. Our regulated utility operations in Minnesota and Wisconsin incur costs for fuel (primarily coal), power and natural gas purchased for resale in our regulated service territories, and related transportation. Our regulated utilities’ exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory environment, which generally allows a fuel clause surcharge if costs are in excess of those in our last rate filing. Conversely, costs below those in our last rate filing result in a rate credit. We seek to prudently manage our customers’ exposure to price risk by entering into contracts of various durations and terms for the purchase of coal and power (in Minnesota), power and natural gas (in Wisconsin), and related transportation costs.

Power Marketing. Our power marketing activities consist of (1) purchasing energy in the wholesale market for resale in our regulated service territories when retail energy requirements exceed generation output and (2) selling excess available energy and purchased power.

From time to time, our utility operations may have excess energy that is temporarily not required by retail and wholesale customers in our regulated service territory. We actively sell this energy to the wholesale market to optimize the value of our generating facilities. This energy is typically sold in the MISO market at market prices or through bilateral agreements of various duration to Other Power Suppliers.

New Accounting Standards

New accounting standards are discussed in Note 1.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Item 8. Financial Statements and Supplementary Data

See our consolidated financial statements as of December 31, 2008 and 2007, and for each of the three years in the period ended December 31, 2008, and supplementary data, also included, which are indexed in Item 15(a).

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

Not applicable.

ALLETE 2008 Form 10-K

41

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, 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) and 15d-15(e) of the Securities Exchange Act of 1934 (“Exchange Act”)). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to our management, including our principal executive 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). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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. Based on our evaluation under the framework in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2008.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Item 9B. Other Information

None.

ALLETE 2008 Form 10-K

42

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Unless otherwise stated, the information required for this Item is incorporated by reference herein from our Proxy Statement for the 2009 Annual Meeting of Shareholders (2009 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.

Our 2009 Proxy Statement will be filed with the SEC within 120 days after the end of our 2008 fiscal year.

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

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

· Corporate Governance Guidelines;

· Audit Committee Charter;

· Executive Compensation Committee Charter; and

· Corporate Governance and Nominating Committee Charter.

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

Item 11. Executive Compensation

The information required for this Item is incorporated by reference herein from the “Compensation of Executive Officers,” the “Compensation Discussion and Analysis”, the “Executive Compensation Committee Report” and the “Director Compensation – 2008” sections in our 2009 Proxy Statement.

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

The information required for this Item is incorporated by reference herein from the “Securities Owned by Certain Beneficial Owners,” the “Securities owned by Directors and Management” and the “Equity Compensation Plan Information” sections in our 2009 Proxy Statement.

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 2009 Proxy Statement.

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

Item 14. Principal Accounting Fees and Services

The information required by this Item is incorporated by reference herein from the “Audit Committee Report” section in our 2009 Proxy Statement.

ALLETE 2008 Form 10-K

43

Part IV

Item 15.                      Exhibits and Financial Statement Schedules

(a)	Certain Documents Filed as Part of this Form 10-K.
(1)	Financial Statements			Page
		ALLETE
		Report of Independent Registered Public Accounting Firm		49
		Consolidated Balance Sheet at December 31, 2008 and 2007		50
		For the Three Years Ended December 31, 2008
			Consolidated Statement of Income	51
			Consolidated Statement of Cash Flows	52
			Consolidated Statement of Shareholders’ Equity	53
		Notes to Consolidated Financial Statements		54
(2)	Financial Statement Schedules
		Schedule II – ALLETE Valuation and Qualifying Accounts and Reserves		84
	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

*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, effective 12:00 p.m. Eastern Time on September 20, 2004 (filed as Exhibit 3 to the September 21, 2004, Form 8-K, File No. 1-3548).
*3(a)3	-	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 (filed as Exhibit 3 to the August 25, 2004, 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. MacInnes (successor to Richard H. West), Trustees (filed as Exhibit 7(c), File No. 2-5865).
*4(a)2	-	Supplemental Indentures to ALLETE’s Mortgage and Deed of Trust:
		Number	Dated as of	Reference File	Exhibit
		First	March 1, 1949	2-7826	7(b)
		Second	July 1, 1951	2-9036	7(c)
		Third	March 1, 1957	2-13075	2(c)
		Fourth	January 1, 1968	2-27794	2(c)
		Fifth	April 1, 1971	2-39537	2(c)
		Sixth	August 1, 1975	2-54116	2(c)
		Seventh	September 1, 1976	2-57014	2(c)
		Eighth	September 1, 1977	2-59690	2(c)
		Ninth	April 1, 1978	2-60866	2(c)
		Tenth	August 1, 1978	2-62852	2(d)2
		Eleventh	December 1, 1982	2-56649	4(a)3
		Twelfth	April 1, 1987	33-30224	4(a)3
		Thirteenth	March 1, 1992	33-47438	4(b)
		Fourteenth	June 1, 1992	33-55240	4(b)
		Fifteenth	July 1, 1992	33-55240	4(c)
		Sixteenth	July 1, 1992	33-55240	4(d)
		Seventeenth	February 1, 1993	33-50143	4(b)
		Eighteenth	July 1, 1993	33-50143	4(c)
		Nineteenth	February 1, 1997	1-3548 (1996 Form 10-K)	4(a)3
		Twentieth	November 1, 1997	1-3548 (1997 Form 10-K)	4(a)3
		Twenty-first	October 1, 2000	333-54330	4(c)3
		Twenty-second	July 1, 2003	1-3548 (June 30, 2003 Form 10-Q)	4
		Twenty-third	August 1, 2004	1-3548 (Sept. 30, 2004 Form 10-Q)	4(a)
		Twenty-fourth	March 1, 2005	1-3548 (March 31, 2005 Form 10-Q)	4
		Twenty-fifth	December 1, 2005	1-3548 (March 31, 2006 Form 10-Q)	4
		Twenty-sixth	October 1, 2006	1-3548 (2006 Form 10-K)	4
		Twenty-seventh	February 1, 2008	1-3548 (2007 Form 10-K)	4(a)3
		Twenty-eighth	May 1, 2008	1-3548 (June 30, 2008 Form 10-Q)	4

ALLETE 2008 Form 10-K

44

Exhibit Number

4(a)3	-	Twenty-ninth Supplemental Indenture, dated as of November 1, 2008, between ALLETE and The Bank of New York Mellon and Douglas J. MacInnes, as Trustees.
4(a)4	-	Thirtieth Supplemental Indenture, dated as of January 1, 2009, between ALLETE and The Bank of New York Mellon and Douglas J. MacInnes, as Trustees.
*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 Trust N.A., as Trustee (filed as Exhibit 7(c), File No. 2-8668).
*4(c)2	-	Supplemental Indentures to Superior Water, Light and Power Company’s Mortgage and Deed of Trust:
		Number	Dated as of	Reference File	Exhibit
		First	March 1, 1951	2-59690	2(d)(1)
		Second	March 1, 1962	2-27794	2(d)1
		Third	July 1, 1976	2-57478	2(e)1
		Fourth	March 1, 1985	2-78641	4(b)
		Fifth	December 1, 1992	1-3548 (1992 Form 10-K)	4(b)1
		Sixth	March 24, 1994	1-3548 (1996 Form 10-K)	4(b)1
		Seventh	November 1, 1994	1-3548 (1996 Form 10-K)	4(b)2
		Eighth	January 1, 1997	1-3548 (1996 Form 10-K)	4(b)3
		Ninth	October 1, 2007	1-3548 (2007 Form 10-K)	4(c)3
		Tenth	October 1, 2007	1-3548 (2007 Form 10-K)	4(c)4
*4(c)3	-	Eleventh Supplemental Indenture, dated as of December 1, 2008, between Superior Water, Light and Power Company and U.S. Bank National Association, as Trustees.
*4(d)	-	Amended and Restated Rights Agreement, dated as of July 12, 2006, between ALLETE and the Corporate Secretary of ALLETE, as Rights Agent (filed as Exhibit 4 to the July 14, 2006, 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(c)	-	Master Agreement (without Appendices and Exhibits), dated December 28, 2004, by and between Rainy River Energy Corporation and Constellation Energy Commodities Group, Inc. (filed as Exhibit 10(c) to the 2004 Form 10-K, File No. 1-3548).
*10(d)1	-	Fourth Amended and Restated Committed Facility Letter (without Exhibits), dated January 11, 2006, by and among ALLETE and LaSalle Bank National Association, as Agent (filed as Exhibit 10 to the January 17, 2006, Form 8-K, File No. 1-3548).
*10(d)2	-	First Amendment to Fourth Amended and Restated Committed Facility Letter dated June 19, 2006, by and among ALLETE and LaSalle Bank National Association, as Agent (filed as Exhibit 10(a) to the June 30, 2006, Form 10-Q, File No. 1-3548).
10(d)3	-	Second Amendment to Fourth Amended and Restated Committed Facility Letter dated December 14, 2006, by and among ALLETE and LaSalle Bank National Association, as Agent.
*10(e)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)2	-	Letter of Credit Agreement, dated as of July 5, 2006, among ALLETE, the Participating Banks and Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (filed as Exhibit 10(b)2 to the June 30, 2006, Form 10-Q, File No. 1-3548).
*10(g)	-	Agreement (without Exhibit) dated December 16, 2005, among ALLETE, Wisconsin Public Service Corporation and WPS Investments, LLC (filed as Exhibit 10 to the December 21, 2005 Form 8-K, File No. 1-3548).
+*10(h)1	-	Minnesota Power (now ALLETE) Executive Annual Incentive Plan, as amended, effective January 1, 1999 with amendments through January 2003 (filed as Exhibit 10 to the September 30, 2003, Form 10-Q, File No. 1-3548).
+*10(h)2	-	November 2003 Amendment to the ALLETE Executive Annual Incentive Plan (filed as Exhibit 10(t)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(h)3	-	July 2004 Amendment to the ALLETE Executive Annual Incentive Plan (filed as Exhibit 10(a) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(h)4	-	January 2007 Amendment to the ALLETE Executive Annual Incentive Plan (filed as Exhibit 10(h)4 to the 2006 Form 10-K, File No. 1-3548).

ALLETE 2008 Form 10-K

45

Exhibit Number

+*10(h)5	-	Form of ALLETE Executive Annual Incentive Plan 2006 Award (filed as Exhibit 10 to the February 17, 2006, Form 8-K, File No. 1-3548).
+*10(h)6	-	Form of ALLETE Executive Annual Incentive Plan Awards Effective 2007 (filed as Exhibit 10(h)7 to the 2006 Form 10-K, File No. 1-3548).
+*10(h)7	-	Form of ALLETE Executive Annual Incentive Plan Form of Awards Effective 2009.
+*10(i)1	-	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan, as amended and restated, effective January 1, 2004 (filed as Exhibit 10(u) to the 2003 Form 10-K, File No. 1-3548).
+*10(i)2	-	January 2005 Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (filed as Exhibit 10(b) to the March 31, 2005, Form 10-Q, File No. 1-3548).
+*10(i)3	-	August 2006 Amendments to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (filed as Exhibit 10(a) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(i)4	-	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan I (SERP I), as amended and restated, effective January 1, 2009.
+*10(i)5	-	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), effective January 1, 2009.
+*10(i)6	-	January 2009 Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), effective January 20, 2009.
+*10(j)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)2	-	Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(v)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(j)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)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)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)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)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)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(l)	-	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).
+*10(m)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)2	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan 2006 Nonqualified Stock Option Grant (filed as Exhibit 10(a)1 to the January 30, 2006, Form 8-K, File No. 1-3548).
+*10(m)3	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan 2006 Performance Share Grant (filed as Exhibit 10(a)2 to the January 30, 2006, Form 8-K, File No. 1-3548).
+*10(m)4	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan 2006 Long-Term Cash Incentive Award – President of ALLETE Properties (filed as Exhibit 10(a)3 to the January 30, 2006, Form 8-K, File No. 1-3548).
+*10(m)5	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan 2006 Stock Grant – President of ALLETE Properties (filed as Exhibit 10(a)4 to the January 30, 2006, Form 8-K, File No. 1-3548).
+10(m)6	-	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)7	-	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)8	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan Long-Term Cash Incentive Award Effective 2007 (filed as Exhibit 10(m)8 to the 2006 Form 10-K, File No. 1-3548).
+10(m)9	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan Stock Grant Effective 2007 (filed as Exhibit 10(m)9 to the 2006 Form 10-K, File No. 1-3548).
+10(m)10	-	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)11	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2009.

ALLETE 2008 Form 10-K

46

Exhibit Number

+*10(m)12	-	Form of ALLETE Executive Long-Term Incentive Compensation Plan – Restricted Stock Unit Grant Effective 2009.
+*10(n)1	-	Minnesota Power (now ALLETE) Director Stock Plan, effective January 1, 1995 (filed as Exhibit 10 to the March 31, 1995 Form 10-Q, File No. 1-3548).
+*10(n)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)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)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)5	-	ALLETE Non-Management Director Compensation Summary Effective February 15, 2007 (filed as Exhibit 10(n)6 to the 2006 Form 10-K, File No. 1-3548).
+*10(o)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)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)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)4	-	August 2006 Amendment to the ALLETE Director Compensation Deferral Plan (filed as Exhibit 10(d) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(o)5	-	ALLETE Non-Employee Director Compensation Deferral Plan II, effective January 1, 2009.
+*10(p)	-	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(q)	-	ALLETE Change of Control Severance Pay Plan Effective February 13, 2008 (filed as Exhibit 10(q) to the 2007 Form 10-K, File No. 1-3548).
12	-	Computation of Ratios of Earnings to Fixed Charges.
21	-	Subsidiaries of the Registrant.
23(a)	-	Consent of Independent Registered Public Accounting Firm.
23(b)	-	Consent of General Counsel.
31(a)	-	Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)	-	Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	-	Section 1350 Certification of Annual Report by the Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99	-	ALLETE News Release dated February 13, 2009, announcing earnings for the year ended December 31, 2008. (This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.)

SWL&P is a party to other long-term debt instruments, $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, that, pursuant to Regulation S-K, Item 601(b)(4)(iii), are not filed as exhibits since 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 required to be filed as an exhibit to this report pursuant to Item 15(b) of Form 10-K.

ALLETE 2008 Form 10-K

47

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 13, 2009	By	/s/ Donald J. Shippar
		Donald J. Shippar
		Chairman, President and 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	Chairman, President, Chief Executive Officer	February 13, 2009
Donald J. Shippar	and Director (Principal Executive Officer)
Mark A. Schober	Senior Vice President and Chief Financial Officer	February 13, 2009
Mark A. Schober	(Principal Financial Officer)
Steven Q. DeVinck	Controller	February 13, 2009
Steven Q. DeVinck	(Principal Accounting Officer)
Kathleen A. Brekken	Director	February 13, 2009
Kathleen A. Brekken
Heidi J. Eddins	Director	February 13, 2009
Heidi J. Eddins
Sidney W. Emery, Jr.	Director	February 13, 2009
Sidney W. Emery, Jr.
James J. Hoolihan	Director	February 13, 2009
James J. Hoolihan
Madeleine W. Ludlow	Director	February 13, 2009
Madeleine W. Ludlow
George L. Mayer	Director	February 13, 2009
George L. Mayer
Douglas C. Neve	Director	February 13, 2009
Douglas C. Neve
Jack I. Rajala	Director	February 13, 2009
Jack I. Rajala
Bruce W. Stender	Director	February 13, 2009
Bruce W. Stender

ALLETE 2008 Form 10-K

48

Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholders of ALLETE, Inc,

In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of ALLETE, Inc. and its subsidiaries (the Company) at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing 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, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 11 to the consolidated financial statements, in 2007 the Company adopted the provisions of FIN 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109."

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.

PricewaterhouseCoopers LLP

Minneapolis, MN

February 13, 2009

ALLETE 2008 Form 10-K

49

Consolidated Financial Statements

ALLETE Consolidated Balance Sheet

December 31	2008	2007
Millions
Assets
Current Assets
Cash and Cash Equivalents	$102.0	$23.3
Short-Term Investments	–	23.1
Accounts Receivable (Less Allowance of $0.7 and $1.0)	76.3	79.5
Inventories	49.7	49.5
Prepayments and Other	24.3	39.1
Total Current Assets	252.3	214.5
Property, Plant and Equipment – Net	1,387.3	1,104.5
Investment in ATC	76.9	65.7
Other Investments	136.9	148.1
Other Assets	281.4	111.4
Total Assets	$2,134.8	$1,644.2
Liabilities and Shareholders’ Equity
Liabilities
Current Liabilities
Accounts Payable	$75.7	$72.7
Accrued Taxes	12.9	14.8
Accrued Interest	8.9	7.8
Long-Term Debt Due Within One Year	10.4	11.8
Deferred Profit on Sales of Real Estate	–	2.7
Notes Payable	6.0	–
Other	36.8	27.3
Total Current Liabilities	150.7	137.1
Long-Term Debt	588.3	410.9
Deferred Income Taxes	169.6	144.2
Other Liabilities	389.3	200.1
Minority Interest	9.8	9.3
Total Liabilities	1,307.7	901.6
Commitments and Contingencies
Shareholders’ Equity
Common Stock Without Par Value, 43.3 Shares Authorized
32.6 and 30.8 Shares Outstanding	534.1	461.2
Unearned ESOP Shares	(54.9)	(64.5)
Accumulated Other Comprehensive Loss	(33.0)	(4.5)
Retained Earnings	380.9	350.4
Total Shareholders’ Equity	827.1	742.6
Total Liabilities and Shareholders’ Equity	$2,134.8	$1,644.2

The accompanying notes are an integral part of these statements.

ALLETE 2008 Form 10-K

50

ALLETE Consolidated Statement of Income

For the Year Ended December 31	2008	2007	2006
Millions Except Per Share Amounts
Operating Revenue	$801.0	$841.7	$767.1
Operating Expenses
Fuel and Purchased Power	305.6	347.6	281.7
Operating and Maintenance	318.1	313.9	298.4
Depreciation	55.5	48.5	48.7
Total Operating Expenses	679.2	710.0	628.8
Operating Income from Continuing Operations	121.8	131.7	138.3
Other Income (Expense)
Interest Expense	(26.3)	(22.6)	(25.0)
Equity Earnings in ATC	15.3	12.6	3.0
Other	15.6	15.5	11.9
Total Other Income (Expense)	4.6	5.5	(10.1)
Income from Continuing Operations Before Minority
Interest and Income Taxes	126.4	137.2	128.2
Income Tax Expense	43.4	47.7	46.3
Minority Interest	0.5	1.9	4.6
Income from Continuing Operations	82.5	87.6	77.3
Loss from Discontinued Operations – Net of Tax	–	–	(0.9)
Net Income	$82.5	$87.6	$76.4
Average Shares of Common Stock
Basic	29.2	28.3	27.8
Diluted	29.3	28.4	27.9
Basic Earnings (Loss) Per Share of Common Stock
Continuing Operations	$2.82	$3.09	$2.78
Discontinued Operations	–	–	(0.03)
	$2.82	$3.09	$2.75
Diluted Earnings (Loss) Per Share of Common Stock
Continuing Operations	$2.82	$3.08	$2.77
Discontinued Operations	–	–	(0.03)
	$2.82	$3.08	$2.74
Dividends Per Share of Common Stock	$1.72	$1.64	$1.45

The accompanying notes are an integral part of these statements.

ALLETE 2008 Form 10-K

51

ALLETE Consolidated Statement of Cash Flows

For the Year Ended December 31	2008	2007	2006
Millions
Operating Activities
Net Income	$82.5	$87.6	$76.4
Loss from Discontinued Operations	–	–	0.9
Allowance for Funds Used During Construction	(3.3)	(3.8)	(0.5)
Income from Equity Investments, Net of Dividends	(3.1)	(2.7)	(1.8)
Gain on Sale of Assets	(4.8)	(2.2)	–
Gain on Sale of Available-for-sale Securities	(6.4)	–	–
Loss on Impairment of Investments	–	0.3	–
Depreciation Expense	55.5	48.5	48.7
Deferred Income Tax Expense	38.8	14.0	27.8
Minority Interest	0.5	1.9	4.6
Stock Compensation Expense	1.8	2.0	1.8
Bad Debt Expense	0.7	1.0	0.7
Changes in Operating Assets and Liabilities
Accounts Receivable	2.4	(6.6)	7.5
Inventories	(0.2)	(6.1)	(10.3)
Prepayments and Other	11.2	(11.7)	(2.3)
Accounts Payable	(14.1)	9.4	5.1
Other Current Liabilities	5.9	(10.0)	0.2
Other Assets	(2.5)	0.8	(4.3)
Other Liabilities	(12.8)	0.7	1.0
Net Operating Activities for Discontinued Operations	–	–	(13.5)
Cash from Operating Activities	152.1	123.1	142.0
Investing Activities
Proceeds from Sale of Available-for-sale Securities	62.3	449.7	608.8
Payments for Purchase of Available-for-sale Securities	(44.8)	(368.3)	(596.4)
Investment in ATC	(7.4)	(8.7)	(51.4)
Changes to Investments	(0.1)	(10.9)	(0.6)
Additions to Property, Plant and Equipment	(301.1)	(210.2)	(101.8)
Proceeds from Sale of Assets	20.4	1.5	–
Other	(5.4)	(7.2)	(15.0)
Net Investing Activities from Discontinued Operations	–	–	2.2
Cash for Investing Activities	(276.1)	(154.1)	(154.2)
Financing Activities
Issuance of Common Stock	71.1	20.6	15.8
Issuance of Long-Term Debt	198.7	123.9	77.8
Issuance of Notes Payable	6.0	–	–
Reductions of Long-Term Debt	(22.7)	(90.7)	(78.9)
Dividends on Common Stock and Distributions to Minority Shareholders	(50.4)	(44.3)	(43.9)
Net Decrease in Book Overdrafts	–	–	(3.4)
Cash from (for) Financing Activities	202.7	9.5	(32.6)
Change in Cash and Cash Equivalents	78.7	(21.5)	(44.8)
Cash and Cash Equivalents at Beginning of Period	23.3	44.8	89.6
Cash and Cash Equivalents at End of Period	$102.0	$23.3	$44.8

The accompanying notes are an integral part of these statements.

ALLETE 2008 Form 10-K

52

ALLETE Consolidated Statement of Shareholders’ Equity

			Accumulated
	Total		Other	Unearned
	Shareholders’	Retained	Comprehensive	ESOP	Common
	Equity	Earnings	Income (Loss)	Shares	Stock
Millions
Balance at December 31, 2005	$602.8	$272.1	$(12.8)	$(77.6)	$421.1
Comprehensive Income
Net Income	76.4	76.4
Other Comprehensive Income – Net of Tax
Unrealized Gains on Securities – Net	1.9		1.9
Additional Pension Liability	6.4		6.4
Total Comprehensive Income	84.7
Adjustment to initially apply SFAS 158 – Net of Tax	(4.3)		(4.3)
Common Stock Issued – Net	17.6				17.6
Dividends Declared	(40.7)	(40.7)
ESOP Shares Earned	5.7			5.7
Balance at December 31, 2006	665.8	307.8	(8.8)	(71.9)	438.7
Comprehensive Income
Net Income	87.6	87.6
Other Comprehensive Income – Net of Tax
Unrealized Gains on Securities – Net	1.1		1.1
Defined Benefit Pension and Other Postretirement Plans	3.2		3.2
Total Comprehensive Income	91.9
Adjustment to initially apply FIN 48	(0.7)	(0.7)
Common Stock Issued – Net	22.5				22.5
Dividends Declared	(44.3)	(44.3)
ESOP Shares Earned	7.4			7.4
Balance at December 31, 2007	742.6	350.4	(4.5)	(64.5)	461.2
Comprehensive Income
Net Income	82.5	82.5
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 Income	54.0
Adjustment to initially apply FAS 158 measurement date	(1.6)	(1.6)
Common Stock Issued – Net	72.9				72.9
Dividends Declared	(50.4)	(50.4)
ESOP Shares Earned	9.6			9.6
Balance at December 31, 2008	$827.1	$380.9	$(33.0)	$(54.9)	$534.1

The accompanying notes are an integral part of these statements.

ALLETE 2008 Form 10-K

53

Notes to Consolidated Financial Statements

Note 1.    Operations and Significant Accounting Policies

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

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. In 2008, we changed our reportable segments (see Note 2. Business Segments.) Our Regulated Operations and Investments and Other segments were determined in accordance with SFAS 131, “Disclosures about Segments of an Enterprise and Related Information.” 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. Discontinued Operations includes our Water Services businesses, the majority of which were sold in 2003. (See Note 12. Discontinued Operations.)

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. Minnesota Power provides regulated utility electric service to 142,000 retail customers in northeastern Minnesota. 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. Approximately 40 percent of revenue from regulated operations is from Large Power Customers (36 percent of consolidated revenue). Large Power Customers consist of five taconite producers, four paper and pulp mills, two pipeline companies and one manufacturer under all-requirements contracts with expiration dates extending from April 2009 through December 2015. Revenue of $100.2 million (12.5 percent of consolidated revenue) was received from one taconite producer in 2008 (12.0 percent in 2007; 11.6 percent in 2006). 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 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 includes our approximate 8 percent equity ownership interest in 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 operation and ownership of, and investment in, transmission facilities. (See Note 6. Investments.)

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate business. This segment also includes emerging technology investments ($7.4 million at December 31, 2008), a small amount of non-rate base generation, approximately 7,000 acres of land for sale in Minnesota, and earnings on cash and short-term 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 2008, Square Butte supplied approximately 55 percent (250 MWs) of its output to Minnesota Power under a long-term contract. (See Note 8. 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 is our real estate business that has operated in Florida since 1991. Our current strategy is to complete and maintain key entitlements and infrastructure improvements which enhance values without requiring significant additional investment, and position the current property portfolio for a maximization of value and cash flow when market conditions improve.

Full profit recognition is recorded on sales upon closing, provided cash collections are at least 20 percent of the contract price and the other requirements of SFAS 66, “Accounting 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 in accordance with SFAS 66. Pursuant 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, 2008, we had no deferred profit recorded on our consolidated balance sheet. Certain contracts allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

ALLETE 2008 Form 10-K

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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.

Land held for sale is recorded at the lower of cost or fair value determined by the evaluation of individual land parcels and is included in Investments on our consolidated balance sheet. Real estate costs include the cost of land acquired, subsequent development costs and costs of improvements, capitalized development period interest, real estate taxes and payroll costs of certain employees devoted directly to the development effort. These real estate costs incurred are capitalized to the cost of real estate parcels based upon the relative sales value of parcels within each development project in accordance with SFAS 67, “Accounting for Costs and Initial Rental Operations of Real Estate Projects.” The cost of real estate 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 be recorded and the related assets would be adjusted to their estimated fair value, less costs to sell.

As part of our emerging technology portfolio, we have several minority investments in venture capital funds and direct investments in privately-held, start-up companies. We account for our investment in venture capital funds under the equity method and account for our direct investments in privately-held companies under the cost method because of our ownership percentage. Long-term investments include auction rate securities and variable rate demand notes, and are classified as available-for-sale securities. All income generated from these short-term investments is recorded as interest income. (See Note 6. Investments.)

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 and significant replacements and improvements are capitalized; maintenance and repair costs are expensed as incurred. Expenditures for major plant overhauls are also accounted for using this same policy. 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, pursuant to SFAS 71, “Accounting for the Effects of Certain Types of Regulations.” Our Regulated Utility operations capitalize AFUDC, which includes both an interest and equity component. (See Note 3. Property Plant and Equipment.)

Long-Lived Asset Impairments. We account for our long-lived assets at depreciated historical cost. A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. We conduct this assessment using SFAS 144, “Accounting for the Impairment and 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.

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
December 31	2008	2007
Millions
Trade Accounts Receivable
Billed	$61.1	$63.9
Unbilled	15.9	16.6
Less: Allowance for Doubtful Accounts	0.7	1.0
Total Accounts Receivable – Net	$76.3	$79.5

ALLETE 2008 Form 10-K

55

Note 1.     Operations and Significant Accounting Policies (Continued)

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

Inventories
December 31	2008	2007
Millions
Fuel	$16.6	$22.1
Materials and Supplies	33.1	27.4
Total Inventories	$49.7	$49.5

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

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
For the Year Ended December 31	2008	2007	2006
Millions
Cash Paid During the Period for
Interest – Net of Amounts Capitalized	$25.2	$26.3	$25.3
Income Taxes	$6.5	$34.2	$32.4 (a)
Noncash Investing Activities
Accounts Payable for Capital Additions to Property, Plant and Equipment	$17.1	$9.8	$7.1
AFUDC – Equity	$3.3	$3.8	$0.5

(a) Net of a $24.3 million cash refund.

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) and variable rate demand notes, classified as available-for-sale securities, are recorded at cost because their cost approximates fair market value. These ARS were historically auctioned every 35 days to set new rates and provide a liquidating event in which investors could either buy or sell securities. The auctions have been unable to sustain themselves during 2008 due to the overall lack of credit market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified the 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. 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 6. Investments.)

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56

Note 1.    Operations and Significant Accounting Policies (Continued)

Accounting for Stock-Based Compensation. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS 123R, “Share-Based Payment,” using the modified prospective transition method. Under this method, we recognize compensation expense for all share-based payments granted after January 1, 2006, and those granted prior to but not yet vested as of January 1, 2006. Under the fair value recognition provisions of SFAS 123R, we recognize stock-based compensation net of an estimated forfeiture rate and only recognize compensation expense for those shares expected to vest over the required service period of the award. (See Note 15. Employee Stock and Incentive Plans.)

Prepayments and Other Current Assets
December 31	2008	2007
Millions
Deferred Fuel Adjustment Clause	$13.1	$26.5
Other	11.2	12.6
Total Prepayments and Other Current Assets	$24.3	$39.1

Other Assets
December 31	2008	2007
Millions
Deferred Regulatory Assets (See Note 5. Regulatory Matters)	$249.3	$76.6
Other	32.1	34.8
Total Other Assets	$281.4	$111.4
Other Liabilities
December 31	2008	2007
Millions
Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Plans	$251.8	$71.6
Deferred Regulatory Liabilities (See Note 5. Regulatory Matters)	50.0	31.3
Asset Retirement Obligation (See Note 3. Property, Plant and Equipment)	39.5	36.5
Other	48.0	60.7
Total Other Liabilities	$389.3	$200.1

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 8. Commitments, Guarantees and Contingencies.)

Income Taxes. We file a consolidated federal income tax return. We account for income taxes using the liability method as prescribed by SFAS 109, “Accounting 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, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. 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 adopted the provisions of FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109.” Under this provision 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. Only tax positions that meet the “more-likely-than-not” threshold may be recognized, and the term “more-likely-than-not” means more than 50 percent. (See Note 11. Income Tax Expense.)

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

ALLETE 2008 Form 10-K

57

Note 1.     Operations and Significant Accounting Policies (Continued)

New Accounting Standards. SFAS 157. In September 2006, the FASB issued SFAS 157, “Fair Value Measurements,” to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value in GAAP, and expanding disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement. It clarifies the extent to which fair value is used to measure recognized assets and liabilities, the inputs used to develop the measurements, and the effect of certain measurements on earnings for the period. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and is applied on a prospective basis. In February 2008, the FASB issued FSP FAS 157-1, "Application of FAS 157 to FAS 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under FAS 13", which excludes FAS 13, "Accounting for Leases," and its related interpretive accounting pronouncements that address leasing transactions, from the scope of FAS 157.

Also in February 2008, the FASB issued FSP FAS 157-2, "Effective Date of FASB Statement 157," which delayed the effective date of SFAS 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008. The Company elected to defer the adoption of the nonrecurring fair value measurement disclosures of nonfinancial assets and liabilities. The adoption of FSP FAS 157-2 is not expected to have a material impact on our consolidated financial position, results of operations, or cash flows.

The implementation of SFAS 157 for financial assets and financial liabilities and FSP FAS 157-1, effective January 1, 2008, did not have a material impact on our consolidated financial position and results of operations. (See Note 6. Investments.) We are currently assessing the impact of SFAS 157 for nonfinancial assets and nonfinancial liabilities, but it is not expected to have a material impact on our consolidated financial position, results of operations, or cash flows.

In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.” This FSP amends SFAS 157, to clarify various application issues with regard to the measurement principles of SFAS 157 when the market for financial assets is not active. This FSP became effective on October 10, 2008, and is applicable to prior periods for which financial statements have not yet been issued. The adoption of FSP FAS 157-3 did not have a material impact on our consolidated financial position, results of operations, or cash flows.

SFAS 159.In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which is an elective, irrevocable election to measure eligible financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. The election may only be applied at specified election dates and to instruments in their entirety rather than to portions of instruments. Upon initial election, the entity reports the difference between the instruments’ carrying value and their fair value as a cumulative-effect adjustment to the opening balance of retained earnings. At each subsequent reporting date, an entity reports in earnings, unrealized gains and losses on items for which the fair value option has been elected. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and is applied on a prospective basis. We have elected not to adopt the provisions of SFAS 159 at this time.

SFAS 160. In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin (ARB) 51,” to improve the relevance, comparability, and transparency of the financial information a reporting entity provides in its consolidated financial statements. SFAS 160 amends ARB 51 to establish accounting and reporting standards for noncontrolling interests in subsidiaries and to make certain consolidation procedures consistent with the requirements of SFAS 141R. It defines a noncontrolling interest in a subsidiary as an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 changes the way the consolidated income statement is presented by requiring consolidated net income to include amounts attributable to the parent and the noncontrolling interest. SFAS 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary which do not result in deconsolidation. SFAS 160 also requires expanded disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners of a subsidiary. SFAS 160 is effective for financial statements issued for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. SFAS 160 shall be applied prospectively, with the exception of the presentation and disclosure requirements which shall be applied retrospectively for all periods presented. ALLETE Properties does have certain noncontrolling interests in consolidated subsidiaries. If SFAS 160 had been applied as of December 31, 2008, the $9.8 million reported as Minority Interest in the Liabilities section on our consolidated balance sheet would have been reported as $9.8 million of Noncontrolling Interest in Subsidiaries in the Equity section of our consolidated balance sheet. Effective January 1, 2009, SFAS 160 will impact the presentation of our consolidated balance sheet, but it is not expected to have a material impact on our consolidated financial position, results of operations, or cash flows.

FSP FAS 132(R)-1. In December 2008, the FASB issued FSP FAS 132(R)-1. This FSP amends SFAS 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide guidance on an employer’s disclosures about plan assets, including employers’ 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. This FSP is effective for fiscal years ending after December 15, 2009. Upon initial application, the provisions of this FSP are not required for earlier periods that are presented for comparative purposes. Early application of the provisions of this FSP is permitted.

ALLETE 2008 Form 10-K

58

Note 1.    Operations and Significant Accounting Policies (Continued)

FSP FAS 140-4 and FIN 46(R)-8.In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8. This pronouncement amends SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” to require public entities to provide additional disclosures about the transfers of financial assets. The pronouncement also amends FIN 46, “Consolidation of Variable Interest Entities,” requiring additional disclosures about a company’s involvement with variable interest entities and qualifying special purpose entities. This FSP is effective for the first reporting period ending after December 15, 2008. We have adopted FSP FAS 140-R and FIN 46(R)-8 and have determined that ALLETE is not the primary beneficiary of any variable interest entities it is associated with. FSP FAS 140-4 and FIN 46(R)-8 did not have a material impact on our consolidated financial position, results of operations, or cash flows. (See Note 8. Commitments, Guarantees and Contingencies.)

Note 2.    Business Segments

In the fourth quarter of 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. Previously, we reported a Regulated Utility segment which included our regulated utilities Minnesota Power and SWL&P. This prior segment is now combined with our previously disclosed segment, Investment in ATC, and renamed Regulated Operations. In addition, we combined the three previously reportable business segments Non-regulated Energy Operations, Real Estate, and Other into one reportable business segment called Investments and Other. The Real Estate segment was not a key component of ALLETE’s business in 2008 and is not expected to be significant in the future. The Investments and Other segment also includes emerging technologies, and earnings on cash and short term investments. In 2008, none of the components of the Investments and Other segment contribute revenue, profit, or assets that are greater than 10 percent of consolidated revenue, profit, or assets. We have recast our segment information for fiscal years ended 2007 and 2006 to reflect the new reportable business segments. Presented below are the operating results and other financial information related to our reportable business segments. For a description of our reportable business segments, see Item 1. Business.

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
2008
Operating Revenue	$801.0	$712.2	$88.8
Fuel and Purchased Power	305.6	305.6	–
Operating and Maintenance	318.1	239.3	78.8
Depreciation Expense	55.5	50.7	4.8
Operating Income from Continuing Operations	121.8	116.6	5.2
Interest Expense	(26.3)	(24.0)	(2.3)
Equity Earnings in ATC	15.3	15.3	–
Other Income	15.6	3.6	12.0
Income from Continuing Operations Before Minority Interest and Income Taxes	126.4	111.5	14.9
Income Tax Expense (Benefit)	43.4	43.6	(0.2)
Minority Interest	0.5	–	0.5
Net Income	$82.5	$67.9	$14.6
Total Assets	$2,134.8	$1,832.1	$302.7
Capital Additions	$322.9	$317.0	$5.9

ALLETE 2008 Form 10-K

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Note 2. Business Segments (Continued)

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
2007
Operating Revenue	$841.7	$723.8	$117.9
Fuel and Purchased Power	347.6	347.6	–
Operating and Maintenance	313.9	229.3	84.6
Depreciation Expense	48.5	43.8	4.7
Operating Income from Continuing Operations	131.7	103.1	28.6
Interest Expense	(22.6)	(21.0)	(1.6)
Equity Earnings in ATC	12.6	12.6	–
Other Income	15.5	4.1	11.4
Income from Continuing Operations Before Minority Interest and Income Taxes	137.2	98.8	38.4
Income Tax Expense	47.7	36.4	11.3
Minority Interest	1.9	–	1.9
Net Income	$87.6	$62.4	$25.2
Total Assets	$1,644.2	$1,396.6	$247.6
Capital Additions	$223.9	$220.6	$3.3

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
2006
Operating Revenue	$767.1	$639.2	$127.9
Fuel and Purchased Power	281.7	281.7	–
Operating and Maintenance	298.4	217.9	80.5
Depreciation Expense	48.7	44.2	4.5
Operating Income from Continuing Operations	138.3	95.4	42.9
Interest Expense	(25.0)	(20.2)	(4.8)
Equity Earnings in ATC	3.0	3.0	–
Other Income	11.9	0.9	11.0
Income from Continuing Operations Before Minority Interest and Income Taxes	128.2	79.1	49.1
Income Tax Expense	46.3	30.4	15.9
Minority Interest	4.6	–	4.6
Income from Continuing Operations	77.3	$48.7	$28.6
Loss from Discontinued Operations – Net of Tax	(0.9)
Net Income	$76.4
Total Assets	$1,533.4	$1,197.0	$336.4
Capital Additions	$109.4	$107.5	$1.9

ALLETE 2008 Form 10-K

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Note 3.     Property, Plant and Equipment

Property, Plant and Equipment
December 31	2008	2007
Millions
Regulated Utility	$1,837.2	$1,683.0
Construction Work in Progress	303.0	165.8
Accumulated Depreciation	(806.8)	(796.8)
Regulated Utility Plant – Net	1,333.4	1,052.0
Non-Rate Base Energy Operations	94.0	89.9
Construction Work in Progress	3.9	2.5
Accumulated Depreciation	(47.2)	(43.2)
Non-Rate Base Energy Operations Plant – Net	50.7	49.2
Other Plant – Net	3.2	3.3
Property, Plant and Equipment – Net	$1,387.3	$1,104.5

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 –	Generation	3 to 35 years	Non-Rate Base Operations	3 to 61 years
	Transmission	42 to 61 years	Other Plant	5 to 25 years
	Distribution	14 to 65 years

Asset Retirement Obligations. Pursuant to SFAS 143, “Accounting for 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 steam generating facilities and land reclamation at BNI Coal, and are included in Other Liabilities on our consolidated balance sheet. Removal costs associated with certain distribution and transmission assets have not been recognized under SFAS 143 as these facilities have indeterminate useful lives. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. 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 SFAS 143, accumulated plant removal costs were reclassified either as AROs or as a regulatory liability for non-ARO obligations. To the extent annual accruals for plant removal costs determined under SFAS 143 differ from accruals under approved depreciation rates, a regulatory asset has been established under SFAS 71. (See Note 5. Regulatory Matters.)

Asset Retirement Obligation
Millions
Obligation at December 31, 2006	$27.2
Accretion Expense	2.1
Additional Liabilities Incurred in 2007	7.2
Obligation at December 31, 2007	36.5
Accretion Expense	2.0
Additional Liabilities Incurred in 2008	1.0
Obligation at December 31, 2008	$39.5

Note 4. Jointly-Owned Electric Facility

We own 80 percent of the 536-MW Boswell Energy Center Unit 4 (Boswell Unit 4). While we operate the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which we and Wisconsin Public Power, Inc., the owner of the other 20 percent of Boswell Unit 4, have equal representation and voting rights. Each of us must provide our own financing and is obligated to pay our ownership share of operating costs. Our share of direct operating expenses of Boswell Unit 4 is included in operating expense on our consolidated statement of income. Our 80 percent share of the original cost of Boswell Unit 4, which is included in property, plant and equipment at December 31, 2008, was $328 million ($316 million at December 31, 2007). The corresponding accumulated depreciation balance was $173 million at December 31, 2008 ($170 million at December 31, 2007).

ALLETE 2008 Form 10-K

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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.

On February 8, 2008, the FERC approved Minnesota Power’s wholesale rate increase effective March 1, 2008. Minnesota Power’s wholesale customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. The FERC authorized an average 10.0 percent increase for wholesale municipal customers, and an overall return on equity of 11.25 percent. Incremental revenue in 2008 from the FERC authorized wholesale rate increase was approximately $6 million.

In 2008 Minnesota Power entered into new contracts with all of our wholesale customers with the exception of one small customer whose contract is now in the cancellation period. The new contracts transition each customer to formula based rates, which means rates can be adjusted annually based on changes in costs. The new agreement with the private utility in Wisconsin is subject to PSCW approval. In November 2008, we filed a request with the FERC to implement the formula based rate provision in the new contracts. We anticipate final resolution and implementation of new rates in the first quarter of 2009.

On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC seeking an average rate increase of 8.5 percent for retail customers. The rate filing seeks a return on equity of 11.15 percent, and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. On an annualized basis, the requested rate increase would generate approximately $40 million in additional revenue. Interim rates were effective on August 1, 2008, and resulted in an increase for retail customers of approximately $36 million, or 7.5 percent, on an annualized basis, subject to refund pending the final rate order. Incremental revenue in 2008 from the interim retail rate increase was approximately $13 million. The transition to a new base cost of fuel coincident with interim rates resulted in the non-recovery through the fuel adjustment clause of approximately $19 million of fuel and purchased power costs incurred in 2008. We have entered into a stipulation and settlement agreement that would allow recovery of the $19 million in 2009 and which addresses specific concerns identified by interveners in the rate case; the stipulation and settlement agreement is subject to MPUC approval. The final rate order is expected in the second quarter of 2009. We cannot predict the final level of rates that may be approved by the MPUC. Prior to the May 2008 retail rate request Minnesota Power’s rates were based on a 1994 MPUC retail rate order that allowed for an 11.6 percent return on equity.

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 common 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.

In 2008, 81 percent of our consolidated operating revenue was under regulatory authority (76 percent in 2007; 72 percent in 2006). The MPUC had regulatory authority over approximately 62 percent of our consolidated operating revenue in 2008 (58 percent in 2007; 56 percent in 2006).

Deferred Regulatory Assets and Liabilities. Our regulated utility operations are subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation.” We capitalize as regulatory assets incurred costs which are probable of recovery in future utility rates. Regulatory liabilitiesrepresent amounts expected to be credited to customers in rates. Regulatory assets and liabilitiesare included in Other Assets and Other Liabilities on our consolidated balance sheet except for deferred fuel adjustment clause charges which are included in Prepayments and Other Current Assets (See Note 1. Operations and Significant Accounting Policies). No regulatory assets or liabilities are currently earning a return.

Deferred Regulatory Assets and Liabilities
December 31	2008	2007
Millions
Regulatory Assets
Income Taxes	$12.2	$11.3
Premium on Reacquired Debt	2.2	2.3
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans (See Note 14. Pension and Other Postretirement Benefit Plans)	216.5	53.7
Deferred MISO Costs	3.9	3.7
Asset Retirement Obligation	5.1	3.6
Boswell Unit 3 Environmental Rider	3.8	–
Other	5.6	2.0
	249.3	76.6
Regulatory Liabilities
Income Taxes	28.7	31.3
Plant Removal Obligations	15.9	–
Accrued MISO Refund	4.7	–
Other	0.7	–
	50.0	31.3
Net Deferred Regulatory Assets	$199.3	$45.3

ALLETE 2008 Form 10-K

62

Note 5.     Regulatory Matters (Continued)

Investment in ATC. Our wholly owned subsidiary Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATC 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. We account for our investment in ATC under the equity method of accounting, pursuant to EITF 03-16, “Accounting for Investments in Limited Liability Companies.” As of December 31, 2008, our equity investment balance in ATC was $76.9 million ($65.7 million at December 31, 2007). On January 30, 2009, we invested an additional $1.9 million in ATC. In total, we expect to invest an additional $5 to $7 million throughout 2009.

ALLETE’s Interest in ATC
Year Ended December 31	2008	2007
Millions
Equity Investment Beginning Balance	$65.7	$53.7
Cash Investments	7.4	8.7
Equity in ATC Earnings	15.3	12.6
Distributed ATC Earnings	(11.5)	(9.3)
Equity Investment Ending Balance	$76.9	$65.7

Note 6. Investments

Investments. At December 31, 2008, 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, our emerging technology portfolio, auction rate securities, and land held for sale in Minnesota.

Investments
December 31	2008	2007
Millions
ALLETE Properties	$84.9	$91.3
Available-for-sale Securities	32.6	30.5
Emerging Technology Portfolio	7.4	7.9
Other	12.0	18.4
Total Investments	$136.9	$148.1

ALLETE Properties	2008	2007
Millions
Land Held for Sale Beginning Balance	$62.6	$58.0
Additions during period: Capitalized Improvements	10.5	12.8
Deductions during period: Cost of Real Estate Sold	(1.9)	(8.2)
Land Held for Sale Ending Balance	71.2	62.6
Long-Term Finance Receivables	13.6	15.3
Other (a)	0.1	13.4
Total Real Estate Assets	$84.9	$91.3

(a) Consisted primarily of a shopping center that was sold on May 1, 2008. The pre-tax gain of $4.5 million resulting from this sale is included in operating revenue on the Consolidated Statement of Income.

Land Held for Sale. Land held for sale is recorded at the lower of cost or fair value determined by the evaluation of individual land parcels. Land values are reviewed for impairment and no impairments were recorded in 2008 (none in 2007).

Finance Receivables. Finance receivables, which are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts of $0.1 million at December 31, 2008 ($0.2 million at December 31, 2007). The majority are receivables having maturities up to four years. Minority interest associated with real estate operations was $9.8 million at December 31, 2008 ($9.3 million at December 31, 2007).

ALLETE 2008 Form 10-K

63

Note 6.    Investments (Continued)

Available-for-Sale Investments.We account for our available-for-sale portfolio in accordance with SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities.” Our available-for-sale securities portfolio consisted of securities in a grantor trust established to fund certain employee benefits and auction rate securities.

Available-For-Sale Securities
Millions
		Gross Unrealized
At December 31	Cost	Gain	(Loss)	Fair Value
2008	$40.5	–	$(7.9)	$32.6
2007(a)	$45.3	$8.4	$(0.1)	$53.6
2006	$123.2	$7.0	$(0.1)	$130.1

(a) Included $23.1 million of auction rate securities that were classified as Short-Term Investments and were subsequently reclassified in 2008 as Investments.

				Net Unrealized
				Gain (Loss)
				in Other
Year Ended	Net	Gross Realized		Comprehensive
December 31	Proceeds	Gain	(Loss)	Income
2008	$17.5	$6.5	$(0.1)	$(9.7)
2007	$81.4	–	–	$1.4
2006	$12.4	–	–	$2.5

Auction Rate Securities. As of December 31, 2008, we held $15.2 million of investments ($23.1 million at December 31, 2007) consisting of three auction rate municipal bonds (auction rate securities) with stated maturity dates ranging between 15 and 28 years. These ARS consist of guaranteed student loans insured or reinsured by the federal government. These ARS were historically auctioned every 35 days to set new rates and provide a liquidating event in which investors could either buy or sell securities. The auctions have been unable to sustain themselves during 2008 due to the overall lack of credit market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified the 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. In the meantime, these securities will pay a default rate which is typically above market interest rates.

The Company has used a discounted cash flow model to determine the estimated fair value of its investment in ARS as of December 31, 2008. The assumptions used in preparing the discounted cash flow model include the following: estimated interest rates, estimated discount rates (using yields of comparable traded instruments adjusted for illiquidity and other risk factors), 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. Based upon the results of the discounted cash flow model and the fact that these ARS consist of guaranteed student loans insured or reinsured by the federal government no other than temporary impairment loss has been reported.

Emerging Technology Investments. The majority of our emerging technology investments are minority investments in venture capital funds. We account for our investment in venture capital funds under the equity method of accounting. The total carrying value of our emerging technology portfolio was $7.4 million at December 31, 2008. Our remaining commitment of $0.7 million at December 31, 2008 may be invested in 2009. We do not have plans to make any additional investments beyond this commitment. Based on our impairment analysis, we did not record any impairment in 2008 ($0.5 million in 2007, none in 2006).

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 Power Customers. Receivables from these customers totaled approximately $11 million at December 31, 2008 ($14 million at December 31, 2007). 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 are on a weekly billing cycle, which allows us to closely manage collection of amounts due.

ALLETE 2008 Form 10-K

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Note 6.    Investments (Continued)

Fair Value of Financial Instruments. With the exception of the items listed 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.

Financial Instruments
December 31	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
2008	$598.7	$561.6
2007	$422.7	$410.9

Fair Value. Effective January 1, 2008, the Company adopted SFAS 157 as discussed in Note 1, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

As defined in SFAS 157, 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). The Company utilizes 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. The Company primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. 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 defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting 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. Instruments in this category include primarily mutual fund investments held to fund employee benefits.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category represent the Company’s deferred compensation obligation and fixed income securities.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, management performs an analysis of all instruments subject to SFAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. Instruments in this category include auction rate securities consisting of guaranteed student loans classified as Level 3 investments as of December 31, 2008. The Company also holds certain financial transmission rights (FTRs) related to our participation in MISO. These FTRs are accounted for as derivatives. While our valuation of these FTRs is based on Level 3 inputs, the fair value of our FTRs at December 31, 2008, is immaterial, and as a result we have not presented them in the tables below.

ALLETE 2008 Form 10-K

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Note 6.     Investments (Continued)

The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	At Fair Value as of December 31, 2008
Recurring Fair Value Measures		Level 1	Level 2	Level 3	Total
Millions
Assets:
Mutual Funds		$13.5	–	–	$13.5
Bonds		–	$3.3	–	3.3
Auction Rate Securities		–	–	$15.2	15.2
Money Market Funds		10.6	–	–	10.6
Total Assets		$24.1	$3.3	$15.2	$42.6
Liabilities:
Deferred compensation obligation		–	$13.5	–	$13.5
Total Liabilities		–	$13.5	–	$13.5
Total Net Assets (Liabilities)		$24.1	$(10.2)	$15.2	$29.1

Recurring Fair Value Measures as of December 31, 2008		Auction Rate
Activity in Level 3		Securities
Millions
Balance as of January 1, 2008		–
	Purchases, sales, issuances and settlements, net (a)	$(10.0)
	Level 3 transfers in	25.2
Balance as of December 31, 2008		$15.2

(a) Includes a $5.2 million transfer of auction rate securities to our Voluntary Employee Benefit Association trust used to fund postretirement health and life benefits.

Note 7. Short-Term and Long-Term Debt

Short-Term Debt. Total short-term debt outstanding at December 31, 2008, was $10.4 million ($11.8 million at December 31, 2007) and consisted of Long-Term Debt Due Within One Year.

As of December 31, 2008, we had bank lines of credit aggregating $160.5 million ($160.0 million at December 31, 2007), the majority of which expire in January 2012. These bank lines of credit make financing available through short-term bank loans and provide credit support for commercial paper. At December 31, 2008, $7.3 million ($4.3 million at December 31, 2007) was drawn on our lines of credit leaving a $153.2 million balance available for use ($155.7 million at December 31, 2007). There was no commercial paper issued as of December 31, 2008 and 2007.

In January 2006, we renewed, increased and extended a committed, syndicated, unsecured revolving credit facility (Line) with Bank of America as Agent, and four other banks, for $150 million. No individual bank has more than 25 percent participation in the Line. The line was subsequently extended for an additional year in December 2006 and currently matures in January 2012. At our request and subject to certain conditions, the Line may be increased to $200 million and extended for two additional 12-month periods. The Line may be used for general corporate purposes and working capital, and to provide liquidity in support of our commercial paper program. We may prepay amounts outstanding under the Line in whole or in part at our discretion without premium or penalty. Additionally, we may irrevocably terminate or reduce the size of the Line prior to maturity without premium or penalty. No funds were drawn under this Line at December 31, 2008 and 2007.

On May 16, 2008, Florida Landmark Communities, Inc., a wholly owned subsidiary of Lehigh Acquisition Corporation, renewed and extended a revolving development loan with RBC Bank (successor by merger to CypressCoquina Bank) for $8.5 million. In October 2008, the revolving development loan was amended and restated as a $10.0 million term loan. ALLETE Properties through its subsidiaries also entered into a $3.0 million revolving development loan with Intracoastal Bank. At December 31, 2008, $1.3 million was drawn on this line of credit.

On May 21, 2008, BNI Coal, a wholly owned subsidiary of ALLETE, entered into a $6.0 million Promissory Note and Supplement (Line of Credit) with CoBANK, ACB. The Line of Credit has a variable interest rate with the option to fix the rate based on LIBOR plus a certain spread. The term of the Line of Credit is 12 months, with the option to renew annually. The Line of Credit is being used for general corporate purposes. As of December 31, 2008, the full amount of $6.0 million was drawn on the Line of Credit.

ALLETE 2008 Form 10-K

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Note 7.     Short-Term and Long-Term Debt (Continued)

Long-Term Debt. The aggregate amount of long-term debt maturing during 2009 is $10.4 million ($4.7 million in 2010; $11.7 million in 2011; $2.9 million in 2012; $73.4 million in 2013; and $495.5 million thereafter). Substantially all of our electric plant is subject to the lien of the mortgages collateralizing various first mortgage bonds.

On February 1, 2008, we issued $60 million in principal amount of First Mortgage Bonds, 4.86% Series due April 1, 2013, in the private placement market. 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 used the proceeds from the sale of the bonds to fund utility capital expenditures and for general corporate purposes.

On May 14, 2008, we issued $75 million in principal amount of First Mortgage Bonds, 6.02% Series due May 1, 2023, in the private placement market. 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 intend used the proceeds from the sale of the bonds to fund utility capital expenditures and for general corporate purposes.

We issued $80 million in principal amount of First Mortgage Bonds in the private placement market in three series as follows:

Issue Date	Maturity	Principal Amount	Coupon
December 15, 2008	January 15, 2014	$18 Million	6.94%
December 15, 2008	January 15, 2016	$20 Million	7.70%
January 15, 2009	January 15, 2019	$42 Million	8.17%

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 intend to use the proceeds from the sale of the bonds to fund utility capital expenditures and for general corporate purposes.

Long-Term Debt
December 31	2008	2007
Millions
First Mortgage Bonds
4.86% Series Due 2013	$60.0	–
6.94% Series Due 2014	18.0	–
7.70% Series Due 2016	20.0	–
5.28% Series Due 2020	35.0	$35.0
4.95% Pollution Control Series F Due 2022	111.0	111.0
6.02% Series Due 2023	75.0	–
5.99% Series Due 2027	60.0	60.0
5.69% Series Due 2036	50.0	50.0
SWL&P First Mortgage Bonds
7.25% Series Due 2013	10.0	–
Senior Unsecured Notes 5.99% Due 2017	50.0	50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2009 – 2020	28.3	36.5
Industrial Development Revenue Bonds 6.5% Due 2025	6.0	6.0
Industrial Development Variable Rate Demand Refunding
Revenue Bonds Series 2006 Due 2025	27.8	27.8
Other Long-Term Debt, 2.0% – 8.0% Due 2009 – 2037	47.6	46.4
Total Long-Term Debt	598.7	422.7
Less: Due Within One Year	10.4	11.8
Net Long-Term Debt	$588.3	$410.9

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. The most restrictive covenant requires ALLETE to maintain a ratio of its Funded Debt to Total Capital of less than or equal to 0.65 to 1.00 measured quarterly. As of December 31, 2008 our ratio was approximately 0.40 to 1.00. Failure to meet this covenant could give rise to an event of default, if not corrected 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.

ALLETE 2008 Form 10-K

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Note 8.    Commitments, Guarantees and Contingencies

Off-Balance Sheet Arrangements. Square Butte Power Purchase Agreement. Minnesota Power has a power purchase agreement with Square Butte that extends through 2026 (Agreement). It provides a long-term supply of low-cost 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-MW coal-fired generating unit (Unit) near Center, North Dakota. The Unit is adjacent to a generating unit owned by Minnkota Power, a North Dakota cooperative corporation whose Class A members are also members of Square Butte. Minnkota Power serves as the operator of the Unit and also purchases power from Square Butte.

Minnesota Power was entitled to approximately 55 percent of the Unit’s output under the Agreement in 2008. Beginning January 1, 2009, our output entitlement will remain 50 percent for the remainder of the contract.

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. 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 December 31, 2008, Square Butte had total debt outstanding of $315.1 million. Total annual debt service for Square Butte is expected to be approximately $29 million in each of the years 2009 through 2013. Variable operating costs include the price of coal purchased from BNI Coal, our subsidiary, under a long-term contract.

On May 13, 2008, we announced plans to develop several hundred megawatts of wind energy in North Dakota and purchase an existing 250 kV DC transmission line to transport this wind energy to customers while gradually reducing the supply of energy currently delivered to our system on this same transmission line from Square Butte’s coal-fired Milton R. Young Unit 2. The North Dakota wind project is expected to complete the 2025 renewable energy supply requirements for our retail load. In September 2008, we signed an agreement to purchase the transmission line from Square Butte Electric Cooperative for approximately $80 million. The transaction is subject to regulatory approvals and is anticipated to close in 2009.

Minnesota Power’s cost of power purchased from Square Butte during 2008 was $56.7 million ($57.3 million in 2007; $57.9 million in 2006). This reflects Minnesota Power’s pro rata share of total Square Butte costs, based on the 55 percent output entitlement in 2008, the 60 percent output entitlement in 2007 and the 66 percent output entitlement in 2006. Included in this amount was Minnesota Power’s pro rata share of interest expense of $11.6 million in 2008 ($11.0 million in 2007; $12.6 million in 2006). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Wind Power Purchase Agreements. We have two wind power purchase agreements with an affiliate of NextEra Energy 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 and the output from Oliver Wind II, a 48-MW facility in November 2007. Each agreement is for 25 years and provides for the purchase of all output from the facilities.

The power purchase agreements (PPA) described above have been evaluated under the provisions of FIN 46-R. We have determined that either we have no variable interest in the PPA, 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, and we do not exude significant control over the operations of each of these facilities. Our financial exposure relating to these PPAs relates to our fixed capacity and energy payments, which are disclosed above.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at a fair market rental, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We 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 $8.3 million in 2009, $8.2 million in 2010, $8.3 million in 2011, $8.2 million in 2012, $7.8 million in 2013 and $52.9 million thereafter. Total rent and lease expense was $8.5 million in 2008 ($8.4 million in 2007; $8.3 million in 2006).

Coal, Rail and Shipping Contracts. We have three coal supply agreements with various expiration dates ranging from December 2009 to December 2011. We also have rail and shipping agreements for the transportation of all of our coal, with various expiration dates ranging from December 2009 to December 2011. Our minimum annual payment obligations under these coal, rail and shipping agreements are currently $43.9 million in 2009, $9.5 million in 2010, $5.4 million in 2011, and no specific commitments beyond 2011. Our minimum annual payment obligations will increase when annual nominations are made for coal deliveries in future years.

ALLETE 2008 Form 10-K

68

Note 8.     Commitments, Guarantees and Contingencies (Continued)

On January 24, 2008, we received a letter from BNSF alleging that the Company defaulted on a material obligation under the Company’s Coal Transportation Agreement (CTA). In the notice, BNSF claimed the Company underpaid approximately $1.6 million for coal transportation services in 2006 and that failure to pay such amount plus interest may result in BNSF’s termination of the CTA. We believe we do not owe the amount claimed. On April 1, 2008, to ensure that BNSF did not attempt to terminate the CTA, we paid under protest the full amount claimed by BNSF and filed a demand for arbitration of the issue. On April 22, 2008, BNSF filed a counterclaim in the arbitration disputing our position that we are entitled to a refund from BNSF of $1.5 million plus interest for amounts that we overpaid for 2007 deliveries. The arbitration is proceeding in connection with the claim regarding 2006 payments and the counterclaim regarding 2007 payments, and we are unable to predict the outcome at this time. The delivered costs of fuel for the Company’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Fuel Clause Recovery of MISO Day 2 Costs. Under a December 2006 MPUC order, we are allowed to accumulate MISO Day 2 administrative charges as a regulatory asset until we file our next rate case, at which time recovery for such charges will be determined. The balance of this regulatory asset is $3.9 million on December 31, 2008, and we are currently recovering these charges in interim rates. The final rate order is expected in the second quarter of 2009. We cannot predict the final level of rates that may be approved by the MPUC.

Emerging Technology Portfolio. We have investments in emerging technologies through minority investments in venture capital funds structured as limited liability companies, and direct investments in privately-held, start-up companies. We have committed to make additional investments in certain emerging technology venture capital funds. The remaining commitment of $0.7 million at December 31, 2008 may be invested in 2009. We do not have plans to make any additional investments beyond this commitment.

Environmental Matters. Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Due to future restrictive environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. 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 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 expense unless recoverable in rates from customers.

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 in 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 acourt 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, Minnesota Power has been assured by the EPA that it intends to publish a rule amending 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. Minnesota Power anticipates the EPA will act regarding this Minnesota administrative stay of the CAIR before CAIR compliance reporting would be required in 2010.

On remand, the EPA has been instructed by the Court to remedy the CAIR’s “more than several fatal flaws” and to reevaluate the inclusion of Minnesota as a CAIR state. If the EPA revises the CAIR, the EPA would need to specifically justify including Minnesota with those states subject to such revised rules. If the CAIR ultimately goes into effect in Minnesota, we expect we will haveto supplement ongoing emission control retrofits by providing for CAIR related emission allowance purchases, supplemental emission reductions or a combination of both. Though we anticipate that emission reduction measures taken with AREA and Boswell Unit 3 emission control retrofits will suffice to satisfy environmental requirements for the next several years, it is uncertain when or how the CAIR will change as a result of EPA’s rulemaking on remand.

ALLETE 2008 Form 10-K

69

Note 8.     Commitments, Guarantees and Contingencies (Continued)

Environmental Matters (Continued)

MinnesotaRegional Haze. The regional haze rule requires States to submit state implementation plans (SIPs) to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the regional haze rule, certain large stationary sources of visibility-impairing emissions that were put in place between 1962 and 1977 are required to install emission controls, known as best available retrofit technology (BART). We have certain steam units (Boswell Unit 3 and Taconite Harbor Unit 3) that 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, the MPCA has requested that companies with BART eligible units complete and submit a BART emissions control retrofit study, which we did as to Taconite Harbor Unit 3 in November 2008. The retrofit work currently underway on Boswell Unit 3 meets the BART requirement for that unit. It is uncertain what controls will ultimately be required by the MPCA at Taconite Harbor Unit 3 in connection with the regional haze rule.

EPA Clean Air Mercury Rule. In March 2005, the EPA also announced the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped emissions of electric utility mercury emissions in the continental United States. In February 2008, the Court overturned the CAMR and remanded the rulemaking to the EPA for reconsideration. In October 2008, the Department of Justice (DOJ), on behalf of the EPA, petitioned the Supreme Court to review the Court’s decision in the CAMR case. It is uncertain how the Supreme Court will respond. Cost estimates for complying with future mercury regulations under the Clean Air Act are therefore premature at this time.

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

The EPA has been conducting a nationwide enforcement initiative since 1999 relating to NSR requirements. In 2000, 2001, and 2002 Minnesota Power received requests from the EPA pursuant to Section 114(a) of the Clean Air Act seeking information regarding capital expenditures with respect to Boswell and Laskin. Minnesota Power responded to these requests; however, we had no further communications from the EPA regarding the information provided until receipt of the NOV.

We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome 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. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding. We are unable to predict the ultimate financial impact or the resolution of these matters at this time.

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site within the City 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. We have accrued a $0.5 million liability for this site at December 31, 2008, and have recorded a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.

Real Estate. As of December 31, 2008, ALLETE Properties, through its subsidiaries, had surety bonds outstanding of $21.4 million primarily related to performance and maintenance obligations to governmental entities to construct improvements in the company’s various projects. The remaining work to be completed on these improvements is estimated to be approximately $10.2 million, and ALLETE Properties does not believe it is likely that any of these outstanding bonds will be drawn upon.

Community Development District Obligations. TownCenter. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6% Capital Improvement Revenue Bonds, Series 2005, which are payable through property tax assessments on the land owners over 31 years (by May 1, 2036). The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements at Town Center. The bonds are payable from and secured by the revenue derived from assessments imposed, levied and collected by the Town Center District. The assessments represent an allocation of the costs of the improvements, including bond financing costs, to the lands within the Town Center District benefiting from the improvements. The assessments were billed to Town Center landowners effective November 2006. To the extent that we still own land at the time of the assessment, in accordance with EITF 91-10, “Accounting for Special Assessments and Tax Increment Financing Entities,” we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At December 31, 2008, we owned approximately 69 percent of the assessable land in the Town Center District (approximately 69 percent at December 31, 2007). As we sell property, the obligation to pay special assessments will pass to the new landowners. Under current accounting rules, these bonds are not reflected as debt on our consolidated balance sheet.

ALLETE 2008 Form 10-K

70

Note 8.   Commitments, Guarantees and Contingencies (Continued)

PalmCoastPark. In May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7% Special Assessment Bonds, Series 2006, which are payable through property tax assessments on the land owners over 31 years (by May 1, 2037). The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements at Palm Coast Park 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 the Palm Coast Park District. The assessments represent an allocation of the costs of the improvements, including bond financing costs, to the lands within the Palm Coast Park District benefiting from the improvements. The assessments were billed to Palm Coast Park landowners effective November 2007. To the extent that we still own land at the time of the assessment, in accordance with EITF 91-10, “Accounting for Special Assessments and Tax Increment Financing Entities,” we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At December 31, 2008, we owned 86 percent of the assessable land in the Palm Coast Park District (86 percent at December 31, 2007). As we sell property, the obligation to pay special assessments will pass to the new landowners. Under current accounting rules, these bonds are not reflected as debt on our consolidated balance sheet.

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, 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.

Note 9. Common Stock and Earnings Per Share

Our Articles of Incorporation contain provisions that, under certain circumstances, would restrict the payment of common stock dividends. As of December 31, 2008, no retained earnings were restricted as a result of these provisions.

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance at December 31, 2005	30,143	$421.1
2006   Employee Stock Purchase Plan	12	0.5
Invest Direct (a)	218	10.0
Options and Stock Awards	63	7.1
Balance at December 31, 2006	30,436	$438.7
2007   Employee Stock Purchase Plan	17	0.7
Invest Direct (a)	331	15.1
Options and Stock Awards	43	6.7
Balance at December 31, 2007	30,827	$461.2
2008   Employee Stock Purchase Plan	17	0.6
Invest Direct (a)	161	6.9
Options and Stock Awards	24	4.6
Equity Issuance Program	1,556	60.8
Balance at December 31, 2008	32,585	$534.1

(a) Invest Direct is ALLETE’s direct stock purchase and dividend reinvestment plan.

Equity Issuance Program. On February 19, 2008, we entered into a Distribution Agreement with KCCI, Inc. with respect to the issuance and sale of up to 2.5 million shares of our common stock, without par value. The shares may be offered for sale, from time to time, in accordance with the terms of the Distribution Agreement, which terminates on June 30, 2009. For the year ended December 31, 2008, 1,556,200 shares of common stock have been issued under this agreement resulting in net proceeds of $60.8 million.

Shareholder Rights Plan. In 1996, we adopted a rights plan that provides for a dividend distribution of one preferred share purchase right (Right) to be attached to each share of common stock. In July 2006, we amended the rights plan to extend the expiration of the Rights to July 11, 2009. The amendment also provides that the Company may not consolidate, merge, or sell a majority of its assets or earning power if doing so would be counter to the intended benefits of the Rights or would result in the distribution of Rights to the shareholders of the other parties to the transaction. Finally, the amendment provides for the creation of a committee of independent directors to annually review the terms and conditions of the amended rights plan (Rights Plan), as well as to consider whether termination or modification of the Rights Plan would be in the best interests of the shareholders and to make a recommendation based on such review to the Board of Directors.

ALLETE 2008 Form 10-K

71

Note 9. Common Stock and Earnings Per Share (Continued)

The Rights, which are currently not exercisable or transferable apart from our common stock, entitle the holder to purchase one-and-a-half one-hundredths (three two-hundredths) of a share of ALLETE’s Junior Serial Preferred Stock A, without par value. The purchase price, as defined in the Rights Plan, remains at $90. These Rights would become exercisable if a person or group acquires beneficial ownership of 15 percent or more of our common stock or announces a tender offer which would increase the person’s or group’s beneficial ownership interest to 15 percent or more of our common stock, subject to certain exceptions. If the 15 percent threshold is met, each Right entitles the holder (other than the acquiring person or group) to receive, upon payment of the purchase price, the number of shares of common stock (or, in certain circumstances, cash, property or other securities of ours) having a market value equal to twice the exercise price of the Right. If we are acquired in a merger or business combination, or more than 50 percent of our assets or earning power are sold, each exercisable Right entitles the holder to receive, upon payment of the purchase price, the number of shares of common stock of the acquiring or surviving company having a value equal to twice the exercise price of the Right. Certain stock acquisitions will also trigger a provision permitting the Board of Directors to exchange each Right for one share of our common stock.

The Rights are nonvoting and may be redeemed by us at a price of $0.005 per Right at any time they are not exercisable. One million shares of Junior Serial Preferred Stock A have been authorized and are reserved for issuance under the Rights Plan.

Earnings Per Share. The difference between basic and diluted earnings per share arises from outstanding stock options and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. In accordance with SFAS 128, “Earnings Per Share,” for 2008, 0.6 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, and therefore, their effect would be anti-dilutive (0.2 million shares were excluded for 2007 and none in 2006).

Reconciliation of Basic and Diluted
Earnings Per Share		Dilutive
For the Year Ended December 31	Basic	Securities	Diluted
Millions Except Per Share Amounts
2008
Income from Continuing Operations	$82.5	–	$82.5
Common Shares	29.2	0.1	29.3
Per Share from Continuing Operations	$2.82	–	$2.82
2007
Income from Continuing Operations	$87.6	–	$87.6
Common Shares	28.3	0.1	28.4
Per Share from Continuing Operations	$3.09	–	$3.08
2006
Income from Continuing Operations	$77.3	–	$77.3
Common Shares	27.8	0.1	27.9
Per Share from Continuing Operations	$2.78	–	$2.77

Note 10.    Other Income (Expense)

For the Year Ended December 31	2008	2007	2006
Millions
Loss on Emerging Technology Investments	$(0.7)	$(1.3)	$(0.9)
AFUDC - Equity	3.3	3.8	0.5
Debt Prepayment Premium and Unamortized Debt Issuance Costs	–	–	(0.6)
Investments and Other Income	13.0	13.0	12.9
Total Other Income	$15.6	$15.5	$11.9

ALLETE 2008 Form 10-K

72

Note 11.    Income Tax Expense

Income Tax Expense
Year Ended December 31	2008	2007	2006
Millions
Current Tax Expense
Federal	$6.2	$26.5	$8.9	(a)
State	(1.6)	7.2	9.6
Total Current Tax Expense	4.6	33.7	18.5
Deferred Tax Expense
Federal	29.3	10.7	28.0	(a)
State	13.4	4.7	2.0
Change in Valuation Allowance	(2.9)	(0.3)	(1.1)
Investment Tax Credit Amortization	(1.0)	(1.1)	(1.1)
Total Deferred Tax Expense	38.8	14.0	27.8
Income Tax Expense for Continuing Operations	43.4	47.7	46.3
Income Tax Expense (Benefit) for Discontinued Operations	–	–	(0.6)
Total Income Tax Expense	$43.4	$47.7	$45.7

(a) Included a current federal tax benefit of $24.3 million and a deferred federal tax expense of $24.3 million related to the refund from the Kendall County capital loss carryback.

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense for Continuing Operations
Year Ended December 31	2008	2007	2006
Millions
Income from Continuing Operations Before Minority Interest and Income Taxes	$126.4	$137.2	$128.2
Statutory Federal Income Tax Rate	35%	35%	35%
Income Taxes Computed at 35% Statutory Federal Rate	$44.2	$48.0	$44.9
Increase (Decrease) in Tax Due to:
Amortization of Deferred Investment Tax Credits	(1.0)	(1.1)	(1.1)
State Income Taxes – Net of Federal Income Tax Benefit	4.8	7.4	6.5
Depletion	(0.8)	(0.9)	(1.1)
Employee Benefits	0.2	0.4	0.1
Domestic Manufacturing Deduction	(0.1)	(1.1)	(0.6)
Regulatory Differences for Utility Plant	(1.6)	(2.2)	(0.9)
Positive Resolution of Audit Issues	–	(1.6)	–
Other	(2.3)	(1.2)	(1.5)
Total Income Tax Expense for Continuing Operations	$43.4	$47.7	$46.3

The effective tax rate on income from continuing operations before minority interest was a 34.3 percent for 2008; (34.8 percent for 2007; 36.1 percent for 2006). The 2008 effective tax rate was impacted by deductions for Medicare health subsidies (included in Employee Benefits, above), domestic manufacturing deduction, 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 uncertain tax position ($1.7 million included in Other, above) and a benefit for the reversal of a state income tax valuation allowance ($2.9 million included in State Income Taxes, above). The 2007 effective tax rate was impacted by state income tax audit settlements ($1.6 million), deductions for Medicare health subsidies (included in Employee Benefits, above), domestic manufacturing deduction, AFUDC-Equity (included in Regulatory Differences for Utility Plant, above), investment tax credits and depletion.

ALLETE 2008 Form 10-K

73

Note 11.   Income Tax Expense (Continued)

Deferred Tax Assets and Liabilities
December 31	2008	2007
Millions
Deferred Tax Assets
Employee Benefits and Compensation (a)	$125.2	$80.5
Property Related	36.4	26.5
Investment Tax Credits	10.7	11.4
Other	16.3	13.4
Gross Deferred Tax Assets	188.6	131.8
Deferred Tax Asset Valuation Allowance	(0.4)	(3.3)
Total Deferred Tax Assets	$188.2	$128.5
Deferred Tax Liabilities
Property Related	$235.6	$201.7
Regulatory Asset for Benefit Obligations	87.7	21.6
Unamortized Investment Tax Credits	15.1	16.1
Employee Benefits and Compensation	1.2	19.5
Fuel Clause Adjustment	5.3	10.7
Other	14.0	8.1
Total Deferred Tax Liabilities	$358.9	$277.7
Accumulated Deferred Income Taxes	$170.7	$149.2
Recorded as:
Net Current Deferred Tax Liabilities (b)	$1.1	$5.0
Net Long-Term Deferred Tax Liabilities	169.6	144.2
Net Deferred Tax Liabilities	$170.7	$149.2

(a) Includes Unfunded Employee Benefits

(b) Included in Other Current Liabilities.

Uncertain Tax Positions. Effective January 1, 2007, we adopted the provisions of FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109.” As a result of the implementation of FIN 48, we recognized a $1.0 million increase in the liability for unrecognized tax benefits. The adoption of FIN 48 also resulted in a reduction in retained earnings of $0.7 million, a reduction of deferred tax liabilities of $0.8 million and an increase in accrued interest of $0.5 million. Subsequent to the implementation of FIN 48, ALLETE’s gross unrecognized tax benefits were $10.4 million. Of this total, $6.8 million (net of federal tax benefit on state issues) represents the amount of unrecognized tax benefits that, if recognized, would favorably impact the effective income tax rate.

Uncertain Tax Positions
Millions December 31, 2007	Gross Unrecognized Income Tax Benefits
Balance at January 1, 2007	$10.4
Additions for Tax Positions Related to the Current Year	0.8
Reductions for Tax Positions Related to the Current Year	–
Additions for Tax Positions Related to Prior Years	–
Reduction for Tax Positions Related to Prior Years	(2.4)
Settlements	(3.5)
Balance at December 31, 2007	$5.3
Less: Tax Attributable to Temporary Items and Federal Benefit on State Tax	(2.3)
Total Unrecognized Tax Benefits that, if Recognized, Would Impact the Effective Income Tax Rate as of December 31, 2007	$3.0
December 31, 2008
Balance at January 1, 2008	$5.3
Additions for Tax Positions Related to the Current Year	0.7
Reductions for Tax Positions Related to the Current Year	–
Additions for Tax Positions Related to Prior Years	4.5
Reduction for Tax Positions Related to Prior Years	(2.5)
Settlements	–
Balance at December 31, 2008	$8.0
Less: Tax Attributable to Temporary Items and Federal Benefit on State Tax	(6.8)
Total Unrecognized Tax Benefits that, if Recognized, Would Impact the Effective Tax Rate as of December 31, 2008	$1.2

ALLETE 2008 Form 10-K

74

Note 11.    Income Tax Expense (Continued)

We recognize interest related to unrecognized tax benefits in interest expense and penalties in operating expenses in the Consolidated Statement of Income. As of December 31, 2007, the Company had $0.9 million of accrued interest and no accrued penalties related to unrecognized tax benefits included in the Consolidated Balance Sheet. As of December 31, 2008, the liability for the payment of interest is $0.6 million with no penalties.

We file income tax returns in the U.S. federal and various state jurisdictions. ALLETE is no longer subject to federal examination for years before 2005 or state examinations for years before 2004.

We expect that the total amount of unrecognized tax benefits as of December 31, 2008, will change by less than $1.0 million in the next 12 months due to statute expirations.

Note 12.    Discontinued Operations

Water Services. Financial results for 2006 reflected additional legal and administrative expenses incurred by the Company to exit the Water Services businesses. There were no discontinued operations in 2008 or 2007.

Discontinued Operations
Summary Income Statement
For the Year Ended December 31	2006
Millions
Loss on Disposal
Water Services	$(1.5)
	(1.5)
Income Tax Expense (Benefit)
Water Services	(0.6)
	(0.6)
Net Loss on Disposal	(0.9)
Loss from Discontinued Operations	$(0.9)

Note 13.    Other Comprehensive Income (Loss)

Other Comprehensive Income (Loss)	Pre-Tax	Tax Expense	Net-of-Tax
Year Ended December 31	Amount	(Benefit)	Amount
Millions
2008
Unrealized Loss on Securities During the Year	$(9.7)	$(3.7)	$(6.0)
Reclassification Adjustment for Gains Included in Income	(6.4)	(2.7)	(3.7)
Defined Benefit Pension and Other Postretirement Plans	(32.1)	(13.3)	(18.8)
Other Comprehensive Loss	$(48.2)	$(19.7)	$(28.5)
2007
Unrealized Gain on Securities During the Year	$1.4	$0.3	$1.1
Defined Benefit Pension and Other Postretirement Plans	5.5	2.3	3.2
Other Comprehensive Income	$6.9	$2.6	$4.3
2006
Unrealized Gain on Securities During the Year	$2.5	$0.6	$1.9
Defined Benefit Pension and Other Postretirement Plans	11.0	4.6	6.4
Other Comprehensive Income	$13.5	$5.2	$8.3

Accumulated Other Comprehensive Income (Loss)

December 31	2008	2007
Millions
Unrealized Gain (Loss) on Securities	$(4.6)	$5.1
Defined Benefit Pension and Other Postretirement Plans	(28.4)	(9.6)
Total Accumulated Other Comprehensive Loss	$(33.0)	$(4.5)

ALLETE 2008 Form 10-K

75

Note 14.    Pension and Other Postretirement Benefit Plans

We have noncontributory defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. We also have defined contribution pension plans covering substantially all employees; employer contributions are made through our employee stock ownership plan. (See Note 15. Employee Stock and Incentive Plans.) In 2008, we made a total of $10.9 million in contributions to ALLETE’s defined benefit pension plans (no contributions were made in 2007).

On August 9, 2006, ALLETE’s Board of Directors approved amendments to the Minnesota Power and Affiliated Companies Retirement Plan A (Retirement Plan A) and the Minnesota Power and Affiliated Companies Retirement Savings and Stock Ownership Plan (RSOP). Retirement Plan A was amended to suspend further crediting service pursuant to the plan, effective as of September 30, 2006, and to close Retirement Plan A to new participants. Participants will continue to accrue benefits under the plan for future pay increases. In conjunction with this change, the Board of Directors took action to increase benefits employees will receive under the RSOP. The modification of Retirement Plan A required us to re-measure our pension expense as of August 9, 2006. As a result of the re-measurement, Retirement Plan A pension expense for 2006 was reduced by $0.2 million.

We have postretirement health care and life insurance plans covering eligible employees. The postretirement health plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and an irrevocable grantor trust. Contributions deductible for income tax purposes are made directly to the VEBAs; nondeductible contributions are made to the irrevocable grantor trust. Amounts are transferred from the irrevocable grantor trust to the VEBAs when they become deductible for income tax purposes. In 2008, $10.1 million was transferred from the grantor trust to the VEBAs ($6.2 million in 2007; $3.6 million in 2006). In 2008, including the amount transferred from the grantor trust, we made a total of $13.8 million in contributions to ALLETE’s postretirement health and life plan ($12.6 million in 2007).

We expect to contribute approximately $30 - $35 million to our defined benefit pension plans and $11 million to our postretirement health and life plans in 2009. We are unable to predict contribution levels to our defined benefit pension or postretirement health and life plans after 2009.

In September 2006, the FASB issued SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). SFAS 158 requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their consolidated balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but that are not recognized as components of net periodic benefit cost. SFAS 158 also requires additional disclosures in the notes to financial statements. SFAS 158 was effective for fiscal years ending after December 15, 2006.

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 under the provisions of SFAS 158 have been recognized as a long-term regulatory asset on our consolidated balance sheet, in accordance with the requirements of SFAS 71. 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, in accordance with SFAS 158.

Pursuant to SFAS 158, we were required to change our measurement date from September 30 to December 31 during the year ended December 31, 2008. 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.

ALLETE 2008 Form 10-K

76

Note 14.      Pension and Other Postretirement Benefit Plans (Continued)

	December 31,	September 30,
Pension Obligation and Funded Status	2008	2007
Millions
Accumulated Benefit Obligation	$406.6	$384.9
Change in Benefit Obligation
Obligation, Beginning of Year	$421.9	$417.7
Service Cost	7.3	5.3
Interest Cost	31.8	23.4
Actuarial Loss (Gain)	3.2	(5.6)
Benefits Paid	(29.9)	(21.6)
Participant Contributions	6.1	2.7
Obligation, End of Year	$440.4	$421.9
Change in Plan Assets
Fair Value, Beginning of Year	$405.6	$364.7
Actual Return on Plan Assets	(120.2)	58.9
Employer Contribution	18.2	3.6
Benefits Paid	(29.9)	(21.6)
Fair Value, End of Year	$273.7	$405.6
Funded Status, End of Year	$(166.7)	$(16.3)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Noncurrent Assets	–	$29.3
Current Liabilities	$(0.9)	$(0.8)
Noncurrent Liabilities	$(165.8)	$(44.8)

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

Unrecognized Pension Costs
Year Ended December 31	2008	2007
Millions
Net Loss	$193.2	$31.1
Prior Service Cost	2.4	3.2
Transition Obligation	–	–
Total Unrecognized Pension Costs	$195.6	$34.3

Components of Net Periodic Pension Expense
Year Ended December 31	2008	2007	2006
Millions
Service Cost	$5.8	$5.3	$9.1
Interest Cost	25.4	23.4	22.2
Expected Return on Plan Assets	(32.5)	(30.6)	(28.6)
Amortization of Loss	1.6	4.9	4.6
Amortization of Prior Service Costs	0.6	0.6	0.6
Net Pension Expense	$0.9	$3.6	$7.9

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2008	2007
Millions
Net Loss (Gain)	$164.0	$(35.4)
Amortization of Prior Service Costs	(0.6)	(0.6)
Amortization of Loss (Gain)	(1.6)	(3.3)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$161.8	$(39.3)

ALLETE 2008 Form 10-K

77

Note 14.    Pension and Other Postretirement Benefit Plans (Continued)

Information for Pension Plans with an	December 31,	September 30,
Accumulated Benefit Obligation in Excess of Plan Assets	2008	2007
Millions
Projected Benefit Obligation	$440.4	$170.6
Accumulated Benefit Obligation	$406.6	$188.3
Fair Value of Plan Assets	$273.7	$145.3

	December 31,	September 30,
Postretirement Health and Life Obligation and Funded Status	2008	2007
Millions
Change in Benefit Obligation
Obligation, Beginning of Year	$153.7	$138.9
Service Cost	5.0	4.2
Interest Cost	11.7	7.9
Actuarial Loss	4.0	7.5
Participant Contributions	2.0	1.4
Benefits Paid	(9.5)	(6.2)
Obligation, End of Year	$166.9	$153.7
Change in Plan Assets
Fair Value, Beginning of Year	$90.9	$78.9
Actual Return on Plan Assets	(25.2)	9.6
Employer Contribution	20.3	6.8
Participant Contributions	1.9	1.4
Benefits Paid	(9.3)	(5.8)
Fair Value, End of Year	$78.6	$90.9
Funded Status, End of Year	$(88.3)	$(62.8)
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(0.7)	$(0.6)
Noncurrent Liabilities	$(87.6)	$(62.2)

Under SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” 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 $14.1 million in an irrevocable grantor trusts at December 31, 2008 ($30.5 million at December 31, 2007). We consolidate the irrevocable grantor trusts and it is included in Investments on our consolidated balance sheet.

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

Unrecognized Postretirement Health and Life Costs
Year Ended December 31	2008	2007
Millions
Net Loss	$59.2	$22.7
Prior Service Cost	–	(0.1)
Transition Obligation	9.4	12.6
Total Unrecognized Postretirement Health and Life Costs	$68.6	$35.2

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2008	2007	2006
Millions
Service Cost	$4.0	$4.2	$4.4
Interest Cost	9.4	7.8	7.4
Expected Return on Plan Assets	(7.2)	(6.5)	(5.6)
Amortization of Loss	1.4	1.0	1.7
Amortization of Transition Obligation	2.5	2.4	2.4
Net Postretirement Health and Life Expense	$10.1	$8.9	$10.3

ALLETE 2008 Form 10-K

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Note 14.   Pension and Other Postretirement Benefit Plans (Continued)

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2008	2007
Millions
Net Loss (Gain)	$38.3	$4.5
Amortization of Transition Obligation	(2.5)	(2.5)
Amortization of Prior Service Costs	–	–
Amortization of Loss (Gain)	(1.4)	(0.9)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$34.4	$1.1

		Postretirement
Estimated Future Benefit Payments	Pension	Health and Life
Millions
2009	$24.1	$7.0
2010	$25.6	$7.8
2011	$26.5	$8.7
2012	$27.4	$9.3
2013	$28.6	$10.0
Years 2014 – 2018	$160.0	$59.5

The pension and postretirement health and life costs recorded in other 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, 2009, are as follows:

		Postretirement
	Pension	Health and Life
Millions
Net Loss	$3.4	$2.5
Prior Service Costs	$0.6	–
Transition Obligations	–	$2.5
Total Pension and Postretirement Health and Life Costs	$4.0	$5.0

Weighted-Average Assumptions	December 31,	September 30,
Used to Determine Benefit Obligation	2008	2007
Discount Rate	6.12%	6.25%
Rate of Compensation Increase	4.3 – 4.6%	4.3 – 4.6%
Health Care Trend Rates
Trend Rate	9%	10%
Ultimate Trend Rate	5%	5%
Year Ultimate Trend Rate Effective	2012	2012

Weighted-Average Assumptions
Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2008	2007	2006
Discount Rate	6.25%	5.75%	5.50%
Expected Long-Term Return on Plan Assets (a)
Pension	9.0%	9.0%	9.0%
Postretirement Health and Life	7.2 – 9.0%	5.0 – 9.0%	5.0 – 9.0%
Rate of Compensation Increase	4.3 – 4.6%	4.3 – 4.6%	3.5 – 4.5%

(a)      The expected long term rate of return used to determine net periodic benefit expenses for 2009 has been reduced to 8.5 percent.

In establishing the expected long-term return on plan assets, we consider the diversification and allocation of plan assets, the actual long-term historical performance for the type of securities invested in, the actual long-term historical performance of plan assets, and the impact of current economic conditions, if any, on long-term historical returns.

Currently for plan valuation purposes, the discount rate is determined considering high-quality long-term corporate bond rates at the valuation date. The discount rate is compared to the Citigroup Pension Discount Curve adjusted for ALLETE’s specific cash flows.

ALLETE 2008 Form 10-K

79

Note 14.    Pension and Other Postretirement Benefit Plans (Continued)

Sensitivity of a One-Percentage-Point	One Percent	One Percent
Change in Health Care Trend Rates	Increase	Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost	$2.0	$(1.7)
Effect on Postretirement Health and Life Obligation	$19.5	$(16.2)

	Pension		Postretirement Health and Life (a)
Actual Plan Asset Allocations	2008	2007	2008	2007
Equity Securities	46%	61%	47%	66%
Debt Securities	32%	25%	40%	24%
Real Estate	6%	2%	–	–
Private Equity	16%	9%	9%	5%
Cash	–	3%	4%	5%
	100%	100%	100%	100%

(a) Includes VEBAs and irrevocable grantor trusts.

Pension plan equity securities did not include ALLETE common stock at December 31, 2008 or September 30, 2007.

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. In addition, all debt securities must have a Standard & Poor’s credit rating of A or higher.

		Postretirement
Plan Asset Target Allocations	Pension	Health and Life (a)
Equity Securities	55%	55%
Debt Securities	24%	24%
Real Estate	9%	9%
Private Equity	11%	11%
Cash	1%	1%
	100%	100%

(a)      Includes VEBAs and irrevocable grantor trusts.

FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act)” provides accounting and disclosure guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 requires that the accumulated postretirement benefit obligation and postretirement benefit cost reflect the impact of the Act upon adoption. We provide postretirement health benefits that include prescription drug benefits which qualify us for the federal subsidy under the Act. The expected reimbursement for Medicare health subsidies reduced our after-tax postretirement medical expense by $1.2 million for 2008 ($2.3 million for 2007; $2.4 million in 2006). In 2005 we enrolled with the Centers for Medicare and Medicaid Services’ (CMS) and began recovering the subsidy in 2007. We received $0.3 million in 2007 for 2006, and expect to receive a reimbursement in 2009 for 2007.

Note 15.    Employee Stock and Incentive Plans

Employee Stock Ownership Plan. We sponsor a leveraged employee stock ownership plan (ESOP) within the RSOP. As of their date of hire, all employees of ALLETE, SWL&P and Minnesota Power Affiliate Resources are eligible to contribute to the plan. In 1990, the ESOP issued a $75 million note (term not to exceed 25 years at 10.25 percent) to us 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 its 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 $10.3 million in 2008 ($9.2 million in 2007; $6.9 million in 2006).

ALLETE 2008 Form 10-K

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Note 15.    Employee Stock and Incentive Plans (Continued)

Pursuant to AICPA Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans,” unallocated 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 31	2008	2007	2006
Millions
ESOP Shares
Allocated	2.0	1.8	1.7
Unallocated	1.9	2.2	2.5
Total	3.9	4.0	4.2
Fair Value of Unallocated Shares	$61.3	$87.1	$115.2

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 1.5 million shares of common stock reserved for issuance under the Executive Plan, with 0.7 million of these shares available for issuance as of December 31, 2008.

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 3,879 options were outstanding under the Director Plan at December 31, 2008.

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

Non-Qualified Stock Options. The 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 cancelled 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.

The following assumptions were used in determining the fair value of stock options granted during 2008, under the Black-Scholes option-pricing model:

	2008	2007	2006
Risk-Free Interest Rate	2.8%	4.8%	4.5%
Expected Life	5 Years	5 Years	5 Years
Expected Volatility	20%	20%	20%
Dividend Growth Rate	4.4%	5.0%	5.0%

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 these awards, the number of shares earned is contingent upon attaining specific performance targets over a three-year performance period. In the case of qualified retirement, death or disability during a performance period, a pro-rata portion of the award will be earned at the conclusion of the performance period based on the performance goals achieved. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro-rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is equal to the grant date fair value which is estimated based upon the assumed share-based payment three years from the date of grant. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients.

ALLETE 2008 Form 10-K

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Note 15.     Employee Stock and Incentive Plans (Continued)

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 by SFAS 123R to apply fair value accounting to these awards.

RSOP. Shares held in our RSOP are excluded from SFAS 123R and are accounted for in accordance with the AICPA Statement of Position No. 93-6, “Employers’ Accounting for Employee Stock Ownership Plans.”

The following share-based compensation expense amounts were recognized in our consolidated statement of income for the periods presented since our adoption of SFAS 123R.

Share-Based Compensation Expense
For the Year Ended December 31	2008	2007	2006
Millions
Stock Options	$0.7	$0.8	$0.8
Performance Shares	1.1	1.0	1.0
Total Share-Based Compensation Expense	$1.8	$1.8	$1.8
Income Tax Benefit	$0.7	$0.7	$0.7

There were no capitalized stock-based compensation costs at December 31, 2008, 2007, or 2006.

As of December 31, 2008, the total unrecognized compensation cost for the performance share awards not yet recognized in our statements of income was $1.3 million. This amount is expected to be recognized over a weighted-average period of 1.7 years.

The following table presents information regarding our outstanding stock options for the year ended December 31, 2008.

				Weighted-Average
		Weighted-Average	Aggregate	Remaining
	Number of	Exercise	Intrinsic	Contractual
	Options	Price	Value	Term
			Millions
Outstanding at December 31, 2007	510,992	$39.83	$(0.1)	6.8 years
Granted	180,815	$39.10
Exercised	(16,627)	$25.56
Forfeited	(2,761)	$39.39
Outstanding at December 31, 2008	672,419	$39.99	$(5.2)	6.9 years
Exercisable at December 31, 2008	406,894	$34.48	$(2.7)	5.7 years
Fair Value of Options
Granted During the Year	$3.97

The weighted-average grant-date fair value of options was $6.18 for 2008 ($6.92 for 2007; $6.48 for 2006). 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 $0.2 million during 2008 ($0.4 million in 2007; $0.6 million in 2006).

At December 31, 2008, 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 3.0 years; all are exercisable at December 31, 2008, at a weighted average price of $26.91. The options with exercise prices ranging from $37.76 to $41.35 have an average remaining contractual life of 7.3 years; less than 0.2 million are exercisable on December 31, 2008, at a weighted average price of $39.52. The options with exercise prices ranging from $44.15 to $48.65 have an average remaining contractual life of 7.5 years; all are exercisable on December 31, 2008, at a weighted average price of $46.25.

ALLETE 2008 Form 10-K

82

Note 15.     Employee Stock and Incentive Plans (Continued)

Performance Shares. The following table presents information regarding our non-vested performance shares for the year ended December 31, 2008.

		Weighted-Average
	Number of	Grant Date
	Shares	Fair Value
Non-vested at December 31, 2007	68,501	$45.63
Granted	36,684	54.05
Unearned Grant Award	(23,624)	42.80
Forfeited	(2,323)	50.87
Non-vested at December 31, 2008	79,238	50.22

Less than 0.1 million performance share were granted in February 2008 for the performance period ending in 2010. The ultimate issuance is contingent upon the attainment of certain future performance goals of ALLETE during the performance periods. The grant date fair value of the performance share awards was $1.8 million.

No performance shares were awarded in February 2008 for the three-year performance period ending in 2007, as performance targets were not met. However, in accordance with SFAS No. 123R, no compensation expense previously recognized in connection with those grants will be reversed.

Note 16.    Quarterly Financial Data (Unaudited)

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

Quarter Ended	Mar. 31	Jun. 30	Sept. 30	Dec. 31
Millions Except Earnings Per Share
2008
Operating Revenue	$213.4	$189.8	$201.7	$196.1
Operating Income	$31.3	$17.5	$33.2	$39.8
Net Income	$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
2007
Operating Revenue	$205.3	$223.3	$200.8	$212.3
Operating Income	$40.7	$33.3	$24.3	$33.4
Net Income	$26.3	$22.6	$16.5	$22.2
Earnings Per Share of Common Stock
Basic	$0.93	$0.80	$0.58	$0.78
Diluted	$0.93	$0.80	$0.58	$0.77

ALLETE 2008 Form 10-K

83

Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves

	Balance at	Additions		Deductions	Balance at
	Beginning	Charged	Other	from	End of
For the Year Ended December 31	of Year	to Income	Changes	Reserves (a)	Period
Millions
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2008  Trade Accounts Receivable	$1.0	$1.0	–	$1.3	$0.7
Finance Receivables – Long-Term	0.2	–	–	0.1	0.1
2007  Trade Accounts Receivable	1.1	1.0	–	1.1	1.0
Finance Receivables – Long-Term	0.2	–	–	–	0.2
2006  Trade Accounts Receivable	1.0	0.7	_	0.6	1.1
Finance Receivables – Long-Term	0.6	_	_	0.4	0.2
Deferred Asset Valuation Allowance
2008  Deferred Tax Assets	3.3	(2.9)	–	–	0.4
2007  Deferred Tax Assets	3.6	(0.3)	–	–	3.3
2006  Deferred Tax Assets	4.1	(1.1)	$0.6	–	3.6

(a)      Includes uncollectible accounts written off.

ALLETE 2008 Form 10-K

84