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


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

Residential and Commercial Customers.In ~~2009,~~2012, our residential and commercial customers represented 2220 percent of total regulated utility kilowatt-hour sales. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately ~~144,000~~143,000 residential and commercial customers. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers.

~~ALLETE 2009 Form 10-K~~

~~REGULATED OPERATIONS (Continued)~~

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

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

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

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

ALLETE 2012 Form 10-K

Regulated Operations (Continued)

Other Power Suppliers (Continued)

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

Power Supply

In order to meet our customers’ electric requirements, we utilize a mix of Company generation and purchased power. The Company’s generation is primarily coal-fired, but also includes approximately ~~112 MWs~~91 MW of ~~hydro~~hydroelectric generation from ten hydro stations in Minnesota, 317 MW of nameplate capacity wind generation, and ~~25 MWs~~81 MW of ~~wind~~biomass co-fired generation. Purchased power ~~is made up~~consists of long-term ~~power purchase agreements~~coal, wind and hydro PPAs as well as market purchases. The following table reflects the Company’s generating capabilities as of December 31, 2012, and total electrical ~~requirements as of December 31, 2009.~~output for 2012. Minnesota Power had an annual net peak load of ~~1,414 MWs~~1,633 MW on ~~January 15, 2009.~~

July 2, 2012.

ALLETE ~~2009~~2012 Form 10-K

~~REGULATED OPERATIONS~~Regulated Operations (Continued)

Power Supply (Continued)



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

Regulated Utility
Power Supply
Unit
No.
Year
Installed
Net Winter
Capability
Year Ended
December 31, 2009
Electric Requirements
MW MWh %
Coal-Fired
Boswell Energy Center 1 1958 68
in Cohasset, MN 2 1960 67
3 1973 352
4 1980 429
916 5,390,131 42.8%
Laskin Energy Center 1 1953 55
in Hoyt Lakes, MN 2 1953 51
106 510,505 4.1
Taconite Harbor Energy Center 1 1957 75
in Schroeder, MN 2 1957 74
3 1967 76
225 1,058,263 8.4
Total Coal 1,247 6,958,899 55.3
Biomass/Coal/Natural Gas
Hibbard Renewable Energy Center
in Duluth, MN 3 & 4 1949, 1951 54 40,703 0.3

Cloquet Energy Center
in Cloquet, MN
5 2001 22 19,340 0.2
Total Biomass/Coal/Natural Gas 76 60,043 0.5
Hydro
Group consisting of ten stations in MN Various 109 434,541 3.5
Wind
Taconite Ridge
in Mt. Iron, MN (a)
1-10 2008 4 56,255 0.4
Total Company Generation 1,436 7,509,738 59.7
Long-Term Purchased Power
Square Butte burns lignite coal near Center, ND 1,695,254 13.5
Wind – Oliver County, ND 361,624 2.9
Hydro – Manitoba Hydro in Winnipeg, MB, Canada 433,543 3.4
Total Long-Term Purchased Power 2,490,421 19.8

Other Purchased Power(b)
2,579,408 20.5
Total Purchased Power 5,069,829 40.3
Total 1,436 12,579,567 100.0%


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

(b)

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

(c)

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

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

ALLETE 2012 Form 10-K

Regulated Operations (Continued)

Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin ~~coal~~ region located in Montana and Wyoming. Coal consumption in ~~2009~~2012 for electric generation at Minnesota Power’s coal-fired generating stations was approximately ~~4.2~~4.6 million tons. As of December 31, ~~2009,~~2012, Minnesota Power had a coal inventory of ~~about 810,000~~0.8 million tons. Minnesota Power’s ~~primary~~ coal supply agreements have expiration dates through ~~2011. Under these agreements, Minnesota Power has the flexibility to procure 70 percent to 100 percent of its total coal requirements.~~2014. In ~~2010,~~2013, Minnesota Power expects to obtain coal under these coal supply agreements and in the spot market. ~~This diversity in coal supply options allows~~ Minnesota Power ~~to manage its coal market price and supply risk and to take advantage of favorable spot market prices. Minnesota Power~~also continues to explore other future coal supply options. We believe that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.

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

~~ALLETE 2009 Form 10-K~~

~~REGULATED OPERATIONS (Continued)~~

~~Fuel (Continued)~~fuel adjustment clause.

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



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

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

Square ~~Butte.~~Butte PPA. Under the long-term agreement with Square Butte, which expires at the end of 2026, Minnesota Power is currently entitled to ~~approximately~~ 50 percent of the output of a 455-MW coal-fired generating unit located near Center, North Dakota. (See Note 11. Commitments, Guarantees and Contingencies.) ~~The~~BNI Coal supplies lignite ~~that has been dedicated~~coal to Square ~~Butte by BNI Coal is located on lands essentially all of which are under private control and presently leased by BNI Coal.~~Butte. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit. Square Butte’s cost of lignite burned in ~~2009~~2012 was approximately ~~$1.02~~$1.35 per MBtu.

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

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

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

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

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

ALLETE 2012 Form 10-K

Regulated Operations (Continued)

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), ~~250kV~~345 kV (29 miles), 250 kV (465 miles), 230 kV ~~(605~~(698 miles), 161 kV (43 miles), 138 kV (128 miles), 115 kV ~~(1,220~~(1,244 miles) and less than 115 kV ~~(6,206~~(6,233 miles). We own and operate ~~166~~170 substations with a total capacity of ~~10,287~~11,322 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

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

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

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

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

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

Investment in ATC

Rainy River Energy, our ~~wholly owned~~wholly-owned subsidiary, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATC ~~provides transmission service under~~ rates ~~regulated by the FERC that~~ are ~~set in accordance with the FERC’s policy of establishing the independent operation~~FERC-approved and ~~ownership of, and investment in, transmission facilities. ATC rates~~ are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, ~~2009,~~2012, our equity investment ~~balance~~ in ATC was ~~$88.4~~$107.3 million ($~~76.9~~98.9 million at December 31, ~~2008)~~2011). (See Note 6. Investment in ATC.)

ALLETE 2012 Form 10-K

Regulated Operations (Continued)

Investment in ATC (Continued)

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

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

Properties

We own office and service buildings, an energy control center, repair shops, ~~lease offices,~~ and storerooms in various localities. All of our electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. ~~Generally, we hold fee interest in~~All of our generating plants and most of our substations are located on real ~~properties~~property owned by us, subject ~~only~~ to the lien of ~~the mortgages. Most~~a mortgage, whereas most of our electric lines are located on ~~land not~~real property owned ~~in fee, but are covered~~ by others with appropriate easement rights or by necessary permits from governmental authorities. WPPI Energy owns 20 percent of Boswell Unit 4. WPPI Energy has the right to use our transmission line facilities to transport its share of Boswell generation. (See Note 4. Jointly-Owned ~~Electric Facility.~~Facilities.)

~~ALLETE 2009 Form 10-K~~

~~REGULATED OPERATIONS (Continued)~~

Regulatory Matters

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

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

Information published by the Edison Electric Institute (Typical Bills and Average Rates Report – Summer ~~2009~~2012 and Rankings – July 1, ~~2009~~2012) ranked Minnesota Power as having the ~~eighth~~fourth lowest average retail rates out of ~~175~~169 utilities in the ~~United States. According to this report,~~U.S. Minnesota Power had the lowest rates in Minnesota and ~~third~~second lowest in the region consisting of Iowa, Kansas, Minnesota, Missouri, North Dakota, South Dakota and Wisconsin.

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

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

~~2008~~2010 Rate Case. ~~In May 2008,~~ Minnesota ~~Power filed~~Power’s current retail rates are based on a 2011 MPUC retail rate ~~increase request with the MPUC seeking additional revenues of approximately $40 million annually; the request also sought an 11.15~~order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a ~~capital structure consisting of 54.8~~54.29 percent equity and 45.2 percent debt. As a result of a May 2009 Order and an August 2009 Reconsideration Order, the MPUC granted Minnesota Power a revenue increase of approximately $20 million, including a return on equity of 10.74 percent and a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.ratio.

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

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

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

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

ALLETE ~~2009~~2012 Form 10-K

~~REGULATED OPERATIONS~~Regulated Operations (Continued)

Regulatory Matters (Continued)

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

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

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

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

Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated ~~transmission upgrades.~~with Bison 1. We anticipate filing a cost recovery petition with the MPUC in the first ~~quarter~~half of ~~2010~~2013 to ~~establish~~update customer billing rates for ~~the approved cost recovery.~~ Bison ~~I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will fulfill the 2025 renewable energy supply requirement for our retail load.~~1 and to include investments and expenditures associated with Bison ~~I will be comprised of 33 wind turbines with a total nameplate capacity of 76 MWs, located near Center, North Dakota,~~2 and ~~be in service in late 2010 and 2011.~~Bison 3.

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

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

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

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

~~Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios;~~

~~Reductions in the emission of GHGs (primarily carbon dioxide); and~~

~~Compliance with mandated renewable energy standards.~~

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

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

~~Emission Reduction Plans.~~ ~~We have made investments in pollution control equipment at our Boswell Unit 3 generating unit that reduces particulates, SO~~2~~, NO~~x ~~and~~ mercury emissions ~~to meet future federal and state requirements. This equipment was placed in service in November 2009. During the construction phase,~~reduction plan, which then is reviewed by the MPUC ~~authorized~~for a ~~cash return~~decision. We expect a decision by the MPUC on ~~construction work~~the plan in ~~progress~~the third quarter of 2013. After approval by the MPUC we anticipate filing a petition to include investments and expenditures in ~~lieu of AFUDC, and this amount was collected through a current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to base~~customer billing rates.

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

~~Boswell NO~~X ~~Reduction Plan.~~ ~~In September 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for expenditures relating to NO~~X ~~emission reductions from Boswell Units 1, 2, and 4. The Boswell NO~~X ~~Reduction Plan is expected to significantly reduce NO~~X ~~emissions from these units. In conjunction with the NO~~X reduction, we plan to make an efficiency improvement to our existing turbine/generator at Boswell Unit 4 adding approximately 60 MWs of total output. The Boswell 1, 2 and 4, selective non-catalytic reduction NOX ~~controls are currently in service, while the Boswell 4 low NO~~X ~~burners and turbine efficiency projects are anticipated to be in service in late 2010. Our 2010 rate case seeks recovery for this project in base rates.~~

ALLETE ~~2009~~2012 Form 10-K

~~REGULATED OPERATIONS~~Regulated Operations (Continued)

Regulatory Matters (Continued)

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

Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues from service provided in the state on energy CIPs each year. These investments are recovered from retail customers through a ~~billing adjustment and amounts~~combination of the conservation cost recovery charge included in retail base ~~rates.~~rates and a conservation program adjustment, which is adjusted annually through the CIP consolidated filing. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, ~~as well as~~any financial incentive earned for cost-effective program achievements, and a carrying charge on the deferred account balance. Minnesota’s Next Generation Energy Act of 2007 introduced, in addition to the minimum spending requirements, an energy-saving goal of 1.5 percent of gross annual retail electric energy sales bybeginning with program year 2010. In June ~~2008,~~2010, a ~~biennial~~triennial filing was submitted for ~~2009~~2011 through ~~2010,~~2013, and was subsequently approved by the ~~OES. For future program years,~~ Minnesota ~~Power will build upon current successful CIPs in an effort to meet the newly established 1.5 percent energy-saving goal.~~Department of Commerce. Minnesota Power’s CIP investment goal was $6.0 million for 2012 ($5.9 million for 2011; $4.6 million for ~~2009 ($3.7 million for 2008; $3.2 million for 2007)~~2010), with actual spending of ~~$5.5~~$6.8 million in ~~2009~~2012 ($~~4.8~~6.3 million in ~~2008; $3.9~~2011; $5.6 million in ~~2007)~~2010).

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

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

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

Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. ~~In 2008,~~ Minnesota ~~Power entered into new~~Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with ~~these~~the remaining 15 Minnesota municipal customers ~~which transitioned customers to formula-based~~and SWL&P are effective through June 30, 2019. The rates ~~allowing rates to be adjusted annually based on changes~~included in ~~cost. In February 2009, the FERC approved our municipal~~these contracts ~~which expire December 31, 2013. Under the formula-based rates provision, wholesale rates~~ are calculated using a cost-based formula methodology that is set ~~at the beginning of the year based on expected~~each July 1, using estimated costs and ~~provide~~a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The formula-based rate methodology also provides for a yearly true-up calculation for actual ~~costs. Wholesale rate increases totaling approximately $6 million and $10 million annually were implemented~~costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin. This customer submitted a cancellation notice with termination effective on ~~February 1, 2009 and January 1, 2010, respectively, with approximately $6 million~~December 31, 2013. The 17 MW of ~~additional revenues under the true-up provision accrued~~average monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in ~~2009, which will be billed in 2010.~~2014.

ALLETE 2012 Form 10-K

Regulated Operations (Continued)

Regulatory Matters (Continued)

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

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

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

During 2012, SWL&P’s ~~current~~retail rates were based on a 2010 PSCW retail rate order, which was effective January 1, 2011. SWL&P’s 2013 retail rates are based on a ~~December 2008~~2012 PSCW retail rate order, ~~that became~~ effective January 1, ~~2009,~~2013, and allows for ~~an 11.1~~a 10.9 percent return on common equity. The new rates ~~reflected a 3.5~~reflect an average overall increase of 2.4 percent ~~average increase in~~for retail ~~utility rates for SWL&P~~ customers (a ~~13.4~~13.8 percent increase in water rates, a ~~4.7~~1.2 percent increase in electric rates, and a ~~0.6~~2.0 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3$1.7 million in additional revenue.

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

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

~~ALLETE 2009 Form 10-K~~

Regional Organizations

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

conditions of transmission service over its ~~broad~~ region, ~~encompassing~~which encompasses all or parts of 1511 states and ~~one~~the Canadian province of Manitoba, and over 100,000 ~~MWs~~MW of generating capacity.

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

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

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

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

Minnesota Legislation

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and municipal energy sales in Minnesota ~~come~~be from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. ~~Minnesota Power has identified a plan to meet the renewable goals set by Minnesota and has included this in the most recent filing of the IRP with the MPUC.~~ The law allows the MPUC to modify or delay meeting a ~~standard obligation~~milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a ~~standard,~~milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power ~~was developing~~met the 2012 milestone and ~~making~~has developed a plan to meet the future renewable ~~supply additions as part of~~milestones which is included in its ~~generation planning strategy prior to~~2010 Integrated Resource Plan. The MPUC approved the ~~enactment of this law~~Integrated Resource Plan in its order issued in May 2011. Minnesota Power will submit its next Integrated Resource Plan on March 1, 2013, and ~~this activity continues.~~include an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025.

~~Greenhouse Gas Reduction.~~ ~~In 2007,~~

ALLETE 2012 Form 10-K

Regulated Operations (Continued)

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

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

Competition

Retail electric energy sales in Minnesota and Wisconsin are made to customers in assigned service territories. As a result, most retail electric customers in Minnesota do not have the ability to choose their electric supplier. Large energy users ~~outside of a municipality~~ of 2 MW and above that are located outside of a municipality may be allowed to choose a supplier upon MPUC approval. Minnesota Power serves 10 Large Power facilities over 10 MW, none of which have engaged in a competitive rate process. ~~Two~~No other large commercial or small industrial customers ~~within the past 15 years that are over 2 MW but less than 10 MW under our Large Light and Power tariff~~in Minnesota Power’s service territory have ~~participated in~~attempted to seek a ~~competitive rate process with neighboring electric cooperatives but were ultimately retained by~~provider outside Minnesota ~~Power.~~Power’s service territory since 1994. Retail electric and natural gas customers in Wisconsin do not have the ability to choose their energy supplier. In both states, however, electricity may compete with other forms of energy. Customers may also choose to generate their own electricity, or substitute other ~~fuels~~forms of energy for their manufacturing processes.

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

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

~~ALLETE 2009 Form 10-K~~

Franchises

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

~~INVESTMENTS AND OTHER~~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 ~~investment.~~investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately ~~7,000~~6,100 acres of land ~~available-for-sale~~ in Minnesota, and earnings on cash and investments.

BNI Coal

~~BNI Coal operates a lignite mine in North Dakota.~~ BNI Coal is a ~~low-cost~~ supplier of lignite in North Dakota, producing about 4 million tons annually. Two electric generating cooperatives, Minnkota Power and Square Butte, presently consume virtually all of BNI Coal’s production of lignite under ~~cost-plus,~~a cost plus fixed fee coal supply ~~agreements~~agreement extending through 2026. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 11. Commitments, Guarantees and Contingencies.) The mining process disturbs and reclaims between 200 and 250 acres per year. Laws require that the reclaimed land be at least as productive as it was prior to mining. ~~The average cost to reclaim one acre~~As of ~~land is approximately $35,000; however, depending~~December 31, 2012, BNI had a $11.0 million asset reclamation obligation ($10.3 million at December 31, 2011) included in other non-current liabilities on ~~conditions, it could be significantly higher. Reclamation~~our Consolidated Balance Sheet. These costs are included in the cost plus fixed fee contract, for which an asset reclamation cost receivable was included in other non-current assets on our Consolidated Balance Sheet. The asset reclamation obligation is guaranteed by surety bonds and a letter of ~~coal passed through to customers. With~~credit. (See Note 11. Commitments, Guarantees and Contingencies.) BNI Coal has lignite reserves of an estimated ~~600~~650 million ~~tons, BNI Coal has ample capacity to expand production.~~tons.

ALLETE 2012 Form 10-K

Investments and Other (Continued)

ALLETE Properties

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

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

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

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

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

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

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

~~ALLETE 2009 Form 10-K~~

~~INVESTMENTS AND OTHER (Continued)~~

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

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

ALLETE Clean Energy

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

Non-Rate Base Generation

As of December 31, ~~2009,~~2012, non-rate base generationconsists of ~~30 MWs~~29 MW of generation at Rapids Energy Center. ~~For January through October non-rate base generation also included Cloquet Energy Center (23 MWs of generation), which was transferred to rate base as a result of our 2008 rate order.~~ In ~~2009,~~2012, we sold ~~0.2~~0.1 million MWh of non-rate base generation ~~(0.2~~(0.1 million in ~~2008~~2011 and ~~2007)~~0.1 million in 2010).

Non-Rate Base Power Supply Unit No.
Year
Installed
Year
Acquired
Net
Capability (MW)
Steam
Biomass (a)

Cloquet Energy Center (b)
5 2001 2001 22
in Cloquet, MN
Rapids Energy Center (c)
6 & 7 1969, 1980 2000 29
in Grand Rapids, MN
Hydro
Conventional Run-of-River
Rapids Energy Center (c)
4 & 5 1917 2000 1
in Grand Rapids, MN



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

~~(a)~~

~~Cloquet Energy Center is supplemented by natural gas; Rapids Energy Center is supplemented by coal.~~

~~(b)~~

~~Transferred to Regulated Operations as a result of our 2008 rate order on November 1, 2009.~~

~~(c)~~(a)

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


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

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

~~Other~~

ALLETE 2012 Form 10-K

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

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration by both ~~the~~ Congress and the EPA. ~~Most notably, clean energy technologies and the regulation of GHGs have taken a lead in these discussions.~~ Minnesota Power’s fossil ~~fueled~~fuel facilities will likely to be subject to regulation under these ~~climate change policies.~~proposals. Our intention is to reduce our exposure to ~~possible future carbon and GHG legislation~~these requirements by reshaping our generation portfolio over time to reduce our reliance on coal.

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

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

~~ALLETE 2009 Form 10-K~~

~~Environmental Matters (Continued)~~

Air.~~Clean Air Act.~~ The electric utility industry is heavily regulated both at the federal ~~Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO~~2and ~~system-wide average NO~~X ~~limits.~~state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. ~~Square Butte, located in North Dakota, burns lignite coal.~~ All of ~~these~~Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses ~~or electrostatic precipitators. Minnesota Power’s generating~~and low NO_X technologies. Under currently applicable environmental regulations, these facilities are ~~currently in compliance~~substantially compliant with applicable emission requirements.

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

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

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

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

ALLETE 2012 Form 10-K

Environmental Matters (Continued)

Air (Continued)

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

~~EPA Clean Air Interstate Rule.~~ ~~In March 2005, the EPA announced the Clean Air Interstate Rule (CAIR) that sought to reduce and permanently cap emissions of SO~~2~~, NO~~X, and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit (Court) vacated the CAIR and remanded the rulemaking to the EPA for reconsideration while also granting our petition that the EPA reconsider including Minnesota asif a CAIR state. In September 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested that the CAIR be remanded without a court order. In December 2008, the Court granted the request that the CAIR be remanded without a court order, effectively reinstating a January 1, 2009, compliance date for the CAIR, including Minnesota. However, in the May 12, 2009, Federal Register, the EPA issued a proposedCSAPR replacement rule that would amend the CAIR to stay its effectiveness with respect to Minnesota until completion of the EPA’s determination of whether Minnesota should be included as a CAIR state. The formal administrative stay of CAIR for Minnesota was published in the November 3, 2009, Federal Register with an effective date of December 3, 2009. The EPA has indicated the CAIR Replacement Rule is ~~expected in April 2010 with finalization in early 2011. At this time we do not have any indication whether Minnesota will be included in the Replacement Rule.~~promulgated.

~~Minnesota~~ Regional Haze. The federal ~~regional haze rule~~Regional Haze Rule requires states to submit ~~state implementation plans (SIPs)~~SIPs to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the ~~regional haze rule,~~first phase of the Regional Haze Rule, certain large stationary sources, ~~that were~~ put in place between 1962 and 1977, with emissions contributing to visibility impairment, are required to install emission controls, known as ~~best available retrofit technology~~Best Available Retrofit Technology (BART). We have ~~certain~~two steam units, Boswell Unit 3 and Taconite Harbor Unit 3, ~~which~~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, theThe MPCA requested that companies with ~~BART eligible~~BART-eligible units complete and submit a BART emissions control retrofit study, which was ~~done on~~completed for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART ~~requirement~~requirements for that unit. OnIn December ~~15,~~ 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA.

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

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register on February 16, 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the ~~regional haze rule.~~rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that they have approved Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas addressing the MATS requirements. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

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

ALLETE ~~2009~~2012 Form 10-K

Environmental Matters (Continued)

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

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

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

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

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

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

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

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

ALLETE 2012 Form 10-K

Environmental Matters (Continued)

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

~~Expand our renewable energy supply.~~

~~Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies.~~

~~Provide energy conservation initiatives with our customers and demand side efforts.~~

~~Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.~~

~~Achieve overall carbon emission reductions.~~

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

Expand our renewable energy supply;

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

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

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

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

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

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

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

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

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

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

~~ALLETE 2009 Form 10-K~~

~~Environmental Matters (Continued)~~

~~Climate Change (Continued)~~

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

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

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

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

In late 2010, the EPA issued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the project-specific, top-down BACT determination process used for other pollutants will also be used to determine BACT for ~~GHGs. However, modifying~~GHG emissions. Through sector-specific white papers, the EPA also provided examples and technical summaries of GHG emission control technologies and techniques the EPA considers available or ~~installing units with GHG emissions~~likely to be available to sources. It is possible that ~~trigger the PSD permitting requirements~~these control technologies could ~~require amending operating permits~~be determined to ~~incorporate~~be BACT ~~to control GHG emissions.~~on a project-by-project basis.

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

Legal challenges have been filed with respect to the EPA’s regulation of ~~six GHG, including CO~~2~~, methane, and nitrous oxide, endanger human health or welfare. This finding may result in regulations that establish motor vehicle~~ GHG emissions, ~~standards in 2010. There is also a possibility that~~including the endangerment finding will enable expansion of the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. withTailoring Rule. On June 26, 2012, the United States District Court ~~Circuit Court of Appeals on December 23, 2009.~~

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

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

We ~~participate~~are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in ~~the Electric Power Research Institute’s CoalFleet for Tomorrow program, which reviews advanced clean coal generation and carbon capture research and assessment. Similarly, we participate as~~ a North Dakota Lignite Interest member of the Canadian Clean Power Coalition. It also reviews advanced clean coal technologies focusing on lower rank sub-bituminous and lignite fuel energy conversion technologies and carbon control options. These provide Minnesota Power the ability to assess what technologies will best fit the economic fuels that are available in our region and when they may be available.general rate case.

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

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

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

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

ALLETE ~~2009~~2012 Form 10-K

Environmental Matters (Continued)

Water (Continued)

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

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

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

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

Employees

At December 31, ~~2009,~~2012, ALLETE had ~~1,474~~1,361 employees, of which ~~1,411~~1,322 were full-time.

Minnesota Power and SWL&P ~~have~~had an aggregate ~~614~~593 employees who are members of ~~the International Brotherhood of Electrical Workers (IBEW)~~IBEW Local 31. ~~Throughout 2009, Minnesota Power, SWL&P and~~The current labor agreements with IBEW Local 31 worked under contract extensions of the agreements which expired on January 31, 2009. On April 10, 2009, IBEW Local 31 requested binding arbitration in accordance with the provisions of the contracts which also provided Minnesota Power and SWL&P with the protections of no strike clauses. Arbitration hearings took place October 5, 2009, with final resolution for Minnesota Power occurring in January 2010. The terms of the agreement are retro active to February 1, 2009, and will expire on January 31, ~~2012. SWL&P continues to work with its union and the arbitrator to resolve the remaining differences between the parties.~~2014.

BNI Coal ~~has 137~~had 162 employees, of which ~~100~~117 are members of ~~the~~ IBEW Local 1593. The current labor agreement between BNI Coal and IBEW Local 1593 ~~have a labor agreement which~~ expires on March 31, ~~2011.~~2014.

Availability of Information

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

ALLETE ~~2009~~2012 Form 10-K

Executive Officers of the Registrant

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



Executive Officers	Initial Effective Date

~~Donald J. Shippar~~,Alan R. Hodnik, Age 60 53
~~Chairman and Chief Executive Officer~~	~~May 12, 2009~~
Chairman, President and Chief Executive Officer – ALLETE	~~January 1, 2006~~May 10, 2011
President and Chief Executive Officer – ALLETE	~~January 21, 2004~~

~~Alan R. Hodnik, Age 50~~	May 1, 2010
President – ALLETE	May ~~12,~~1, 2009
Chief Operating Officer – Minnesota Power	May 8, 2007
~~Senior Vice President – Minnesota Power Operations~~	~~September 22, 2006~~
~~Vice President – Minnesota Power Generation~~	~~May 1, 2005~~

Robert J. Adams,, Age 47 50
Vice President – Business Development and Chief Risk Officer	May 13, 2008
Vice President – Utility Business Development	February 1, 2004

Deborah A. Amberg,, Age 44 47
Senior Vice President, General Counsel and Secretary	January 1, 2006
~~Vice President, General Counsel and Secretary~~	~~March 8, 2004~~

Steven Q. DeVinck,, Age 50 53
Controller and Vice President – Business Support	December ~~17,~~5, 2009
Controller	July 12, 2006

David J. McMillan, Age 51
Senior Vice President – External Affairs – ALLETE	January 1, 2012
Senior Vice President – Marketing, Regulatory and Public Affairs – ALLETE	January 1, 2006
Executive Vice President – Minnesota Power	January 1, 2006

Mark A. Schober,, Age 5457
Senior Vice President and Chief Financial Officer	July 1, 2006
~~Senior Vice President and Controller~~	~~February 1, 2004~~

Donald W. Stellmaker,, Age 52 55
Vice President, Corporate Treasurer	August 19, 2011
Treasurer	July 24, 2004

All of the executive officers have been employed by us for more than five years in executive ~~or management~~ positions. ~~Prior to election to the positions shown above, the following executives held other positions with the Company during the past five years.~~

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

~~Mr. Hodnik~~ ~~was General Manager of Thermal Operations.~~

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

The present term of office of the executive officers listed above extends to the first meeting of our Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May ~~11, 2010.~~14, 2013.

ALLETE ~~2009~~2012 Form 10-K

~~Item 1A.~~

Item 1A. Risk Factors

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

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

Our ~~ten~~9 Large Power Customers accounted for approximately 2333 percent of our ~~2009~~2012 consolidated operating revenue ~~(36~~(34 percent in ~~2008)~~2011; 31 percent in 2010). One of these customers accounted for 812.3 percent of consolidated revenue in ~~2009 (12.5~~2012 (12.6 percent in ~~2008)~~2011; 12.5 percent in 2010). These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the ~~global~~ marketplace. AnMany of our large power customers also have unionized workforces which put them at risk for work stoppages. In addition, the North American paper and pulp industry also faces declining demand due to the impact of electronic substitution for print and changing customer needs.

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

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

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

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

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

ALLETE 2012 Form 10-K

Item 1A. Risk Factors (Continued)

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

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

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

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

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

~~ALLETE 2009 Form 10-K~~

~~Risk Factors (Continued)~~

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

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

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

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

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

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

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

We cannot predict ~~with certainty~~ the amount or timing of all future expenditures related to environmental matters because of the ~~difficulty of estimating such costs.~~uncertainty as to applicable regulations or requirements. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

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

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

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

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

ALLETE ~~2009~~2012 Form 10-K

Item 1A. Risk Factors (Continued)

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

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

~~severe or unexpected weather conditions;~~

~~seasonality;~~

~~changes in electricity usage;~~

~~transmission or transportation constraints, inoperability or inefficiencies;~~

~~availability of competitively priced alternative energy sources;~~

~~changes in supply and demand for energy;~~

~~changes in power production capacity;~~

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

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

~~natural disasters, wars, sabotage, terrorist acts or other catastrophic events; and~~

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

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

~~We are dependent on good labor relations.~~

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

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

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

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

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

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

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postretirement benefit plans. We have significant obligations to these plans and the Company holds significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected rates of return. A decline in the market value of the pension and postretirement benefit plan assets will increase the funding requirements under our benefit plans if the actual asset returns do not recover. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements.

~~ALLETE 2009 Form 10-K~~

~~Risk Factors (Continued)~~

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

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

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

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

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

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

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

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

The price of electricity and fuel may be volatile.

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

severe or unexpected weather conditions and natural disasters;

seasonality;

changes in electricity usage;

transmission or transportation constraints, inoperability or inefficiencies;

availability of competitively priced alternative energy sources;

changes in supply and demand for energy;

changes in power production capacity;

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

availability of fuel transportation;

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

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

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

ALLETE 2012 Form 10-K

Item 1A. Risk Factors (Continued)

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

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

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

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

Emerging technologies may adversely affect our business operations.

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

We may be vulnerable to cyber attacks.

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

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

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

ALLETE 2012 Form 10-K

Item 1A. Risk Factors (Continued)

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

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

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

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

~~Item 1B.~~

Item 1B. Unresolved Staff Comments

None.

~~Item 2.~~

Item 2. Properties

~~Properties are included in the~~A discussion of our ~~businesses~~properties is included in Item 11. Business and ~~are~~is incorporated by reference herein.

~~Item 3.~~

Item 3. Legal Proceedings

~~Material~~A discussion of material legal and regulatory proceedings ~~are~~is included in ~~the discussion of our businesses in~~ Item 11. Business and ~~are~~is incorporated by reference herein.

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

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

~~Item 4.~~

~~Submission of Matters to a Vote of Security Holders~~

Item 4. Mine Safety Disclosures

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

this Form 10-K.

ALLETE ~~2009~~2012 Form 10-K

Part II

~~Item 5.~~

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

Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends, without interruption, on our common stock since 1948. A quarterly dividend of ~~$0.44~~$0.475 per share on our common stock ~~will be paid~~is payable on March 1, ~~2010,~~2013, to the ~~holders~~shareholders of record on February 15, ~~2010.~~2013.

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


	2009			2008				2012				2011
	Price Range		Dividends	Price Range		Dividends	Price Range		Dividends		Price Range		Dividends
Quarter	High	Low	Declared	High	Low	Declared	High	Low	Declared		High	Low	Declared

First	$33.27	$23.35	$0.44	$39.86	$33.76	$0.43	$42.49	$39.98		$0.46	$39.36	$36.33		$0.445
Second	29.14	24.45	0.44	46.11	38.82	0.43	$41.99	$38.03	0.46		$41.43	$37.87	0.445
Third	34.57	27.75	0.44	49.00	38.05	0.43	$42.66	$40.33	0.46		$42.10	$35.51	0.445
Fourth	35.29	32.23	0.44	44.63	28.28	0.43	$42.09	$37.73	0.46		$42.54	$35.14	0.445
Annual Total			$1.76			$1.72				$1.84				$1.78

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



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

ALLETE ~~2009~~2012 Form 10-K

Signatures

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



			ALLETE, Inc.


Dated:	February ~~12, 2010~~15, 2013	By	~~Donald J. Shippar~~ /s/ Alan R. Hodnik
	~~Donald J. Shippar~~		Alan R. Hodnik
			Chairman, ~~and~~President, Chief Executive Officer

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



Signature	Title	Date

~~Donald J. Shippar~~/s/ Alan R. Hodnik	Chairman, President, Chief Executive Officer and Director	February ~~12, 2010~~15, 2013
~~Donald J. Shippar~~Alan R. Hodnik	~~and Director~~ (Principal Executive Officer)

~~Alan R. Hodnik~~	~~President and Director~~	~~February 12, 2010~~
~~Alan R. Hodnik~~

/s/ Mark A. Schober	Senior Vice President and Chief Financial Officer	February ~~12, 2010~~15, 2013
Mark A. Schober	(Principal Financial Officer)

/s/ Steven Q. DeVinck	Controller and Vice President – Business Support	February ~~12, 2010~~15, 2013
Steven Q. DeVinck	(Principal Accounting Officer)

ALLETE ~~2009~~2012 Form 10-K

Signatures (Continued)



Signature	Title	Date

/s/ Kathleen A. Brekken	Director	February ~~12, 2010~~15, 2013
Kathleen A. Brekken

/s/ Kathryn W. Dindo	Director	February ~~12, 2010~~15, 2013
Kathryn W. Dindo

/s/ Heidi J. Eddins	Director	February ~~12, 2010~~15, 2013
Heidi J. Eddins

/s/ Sidney W. Emery, Jr.	Director	February ~~12, 2010~~15, 2013
Sidney W. Emery, Jr.

~~James S. Haines, Jr~~/s/ George G. Goldfarb	Director	February ~~12, 2010~~15, 2013
~~James S. Haines, Jr~~George G. Goldfarb

/s/ James S. Haines, Jr.	Director	February 15, 2013
James S. Haines, Jr.

/s/ James J. Hoolihan	Director	February ~~12, 2010~~15, 2013
James J. Hoolihan

/s/ Madeleine W. Ludlow	Director	February ~~12, 2010~~15, 2013
Madeleine W. Ludlow

~~George L. Mayer~~	~~Director~~	~~February 12, 2010~~
~~George L. Mayer~~

/s/ Douglas C. Neve	Director	February ~~12, 2010~~15, 2013
Douglas C. Neve

~~Jack I. Rajala~~	~~Director~~	~~February 12, 2010~~
~~Jack I. Rajala~~

/s/ Leonard C. Rodman	Director	February ~~12, 2010~~15, 2013
Leonard C. Rodman

/s/ Bruce W. Stender	Director	February ~~12, 2010~~15, 2013
Bruce W. Stender

ALLETE ~~2009~~2012 Form 10-K

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of ALLETE, Inc. and its subsidiaries (the Company) at December 31, ~~2009~~2012 and ~~2008,~~2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, ~~2009~~ 2012in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the indexappearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2009,~~2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The ~~Company's~~Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in ~~Management's~~Management’s Report on Internal Control ~~Over~~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~~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 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007.~~

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

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

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Minneapolis, Minnesota

February ~~12, 2010~~15, 2013

ALLETE ~~2009~~2012 Form 10-K

~~Consolidated Financial Statements~~CONSOLIDATED FINANCIAL STATEMENTS

ALLETE Consolidated Balance Sheet

As of December 31 2009 2008
Millions
Assets
Current Assets
Cash and Cash Equivalents $25.7 $102.0
Accounts Receivable (Less Allowance of $0.9 and $0.7) 118.5 76.3
Inventories 57.0 49.7
Prepayments and Other 24.3 24.3
Total Current Assets 225.5 252.3
Property, Plant and Equipment – Net 1,622.7 1,387.3
Regulatory Assets 293.2 249.3
Investment in ATC 88.4 76.9
Other Investments 130.5 136.9
Other Assets 32.8 32.1
Total Assets $2,393.1 $2,134.8

Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable $62.1 $75.7
Accrued Taxes 20.6 12.9
Accrued Interest 11.1 8.9
Long-Term Debt Due Within One Year 5.2 10.4
Notes Payable 1.9 6.0
Other 32.2 36.8
Total Current Liabilities 133.1 150.7
Long-Term Debt 695.8 588.3
Deferred Income Taxes 253.1 169.6
Regulatory Liabilities 47.1 50.0
Other Liabilities 325.0 339.3
Total Liabilities 1,454.1 1,297.9

Commitments and Contingencies (Note 11)

Equity
ALLETE’s Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 35.2 and 32.6
Shares Outstanding 613.4 534.1
Unearned ESOP Shares (45.3) (54.9)
Accumulated Other Comprehensive Loss (24.0) (33.0)
Retained Earnings 385.4 380.9
Total ALLETE Equity 929.5 827.1
Non-Controlling Interest in Subsidiaries 9.5 9.8
Total Equity 939.0 836.9
Total Liabilities and Equity $2,393.1 $2,134.8



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

The accompanying notes are an integral part of these statements.

ALLETE ~~2009~~2012 Form 10-K

ALLETE Consolidated Statement of Income

Year Ended December 31 2009 2008 2007
Millions Except Per Share Amounts
Operating Revenue
Operating Revenue $766.7 $801.0 $841.7
Prior Year Rate Refunds (7.6) – –
Total Operating Revenue 759.1 801.0 841.7
Operating Expenses
Fuel and Purchased Power 279.5 305.6 347.6
Operating and Maintenance 308.9 318.1 313.9
Depreciation 64.7 55.5 48.5
Total Operating Expenses 653.1 679.2 710.0
Operating Income 106.0 121.8 131.7
Other Income (Expense)
Interest Expense (33.8) (26.3) (22.6)
Equity Earnings in ATC 17.5 15.3 12.6
Other 1.8 15.6 15.5
Total Other Income (Expense) (14.5) 4.6 5.5

Income Before Non-Controlling Interest and Income Taxes 91.5 126.4 137.2
Income Tax Expense 30.8 43.4 47.7
Net Income 60.7 83.0 89.5
Less: Non-Controlling Interest in Subsidiaries (0.3) 0.5 1.9
Net Income Attributable to ALLETE $61.0 $82.5 $87.6

Average Shares of Common Stock
Basic 32.2 29.2 28.3
Diluted 32.2 29.3 28.4

Basic Earnings Per Share of Common Stock $1.89 $2.82 $3.09
Diluted Earnings Per Share of Common Stock $1.89 $2.82 $3.08

Dividends Per Share of Common Stock $1.76 $1.72 $1.64



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

The accompanying notes are an integral part of these statements.

ALLETE ~~2009~~2012 Form 10-K

ALLETE Consolidated Statement of Comprehensive Income





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

The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K

ALLETE Consolidated Statement of Cash Flows


Year Ended December 31	2009	2008	2007	2012			2011			2010
Millions
Operating Activities
Net Income	$60.7	$83.0	$89.5		$97.1			$93.6			$74.8
Allowance for Funds Used During Construction	(5.8)	(3.3)	(3.8)
Loss (Income) from Equity Investments, Net of Dividends	0.1	(3.1)	(2.7)
Gain on Sale of Assets	(0.2)	(4.8)	(2.2)
Gain on Sale of Available-for-sale Securities	–	(6.4)	–
Allowance for Funds Used During Construction – Equity				(5.1		)	(2.5		)	(4.2		)
Income from Equity Investments, Net of Dividends				(3.7		)	(3.2		)	(3.1		)
Gain on Real Estate Foreclosure				—			(0.5		)	(0.7		)
Loss (Gain) on Sale of Assets				0.2			(0.9		)	—
Loss on Impairment of Assets	3.1	–	0.3	—			1.7			—
Depreciation Expense	64.7	55.5	48.5	100.2			90.4			80.5
Amortization of Debt Issuance Costs	0.9	0.8	1.0	1.0			0.9			0.9
Deferred Income Tax Expense	75.2	38.8	14.0	37.5			35.8			66.0
Stock Compensation Expense	2.1	1.8	2.0
Share-Based Compensation Expense				2.1			1.6			2.2
ESOP Compensation Expense				7.7			7.4			7.1
Defined Benefit Pension and Other Postretirement Benefit Expense				27.5			23.6			18.0
Bad Debt Expense	1.3	0.7	1.0	1.0			1.2			1.1
Changes in Operating Assets and Liabilities
Accounts Receivable	(43.5)	2.4	(6.6)	(10.1		)	18.6			17.9
Inventories	(7.3)	(0.2)	(6.1)	(0.7		)	(9.1		)	(3.0		)
Prepayments and Other	–	11.2	(11.7)	(6.5		)	1.5			(4.3		)
Accounts Payable	10.5	(14.1)	9.4	(1.5		)	(9.5		)	5.8
Other Current Liabilities	5.3	5.9	(10.0)	21.8			15.4			5.2
Regulatory and Other Assets	(18.3)	(1.8)	0.9
Regulatory and Other Liabilities	(11.4)	(12.8)	0.7
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans				(8.8		)	(24.7		)	(39.3		)
Changes in Regulatory and Other Non-Current Assets				(20.9		)	(7.5		)	4.2
Changes in Regulatory and Other Non-Current Liabilities				0.8			7.9			(0.4		)
Cash from Operating Activities	137.4	153.6	124.2	239.6			241.7			228.7
Investing Activities
Proceeds from Sale of Available-for-sale Securities	8.9	62.3	449.7	1.5			7.8			0.6
Payments for Purchase of Available-for-sale Securities	(2.2)	(44.8)	(368.3)	(1.8		)	(2.3		)	(2.3		)
Investment in ATC	(7.8)	(7.4)	(8.7)	(4.7		)	(2.0		)	(1.6		)
Changes to Other Investments	(0.7)	(9.2)	(12.4)	(9.6		)	(7.4		)	1.3
Additions to Property, Plant and Equipment	(318.5)	(301.1)	(210.2)	(405.8		)	(239.2		)	(248.9		)
Proceeds from Sale of Assets	0.3	20.4	1.5	0.3			2.2			—
Other	–	3.7	(5.7)
Cash for Investing Activities	(320.0)	(276.1)	(154.1)	(420.1		)	(240.9		)	(250.9		)
Financing Activities
Proceeds from Issuance of Common Stock	65.2	71.1	20.6	77.0			39.1			20.5
Proceeds from Issuance of Long-Term Debt	111.4	198.7	123.9	180.6			81.4			155.0
Changes in Notes Payable	(4.1)	6.0	–	(1.1		)	0.1			(0.9		)
Reductions of Long-Term Debt	(9.1)	(22.7)	(90.7)	(25.9		)	(3.1		)	(71.0		)
Debt Issuance Costs	(0.6)	(1.5)	(1.1)	(1.3		)	—			(1.4		)
Dividends on Common Stock	(56.5)	(50.4)	(44.3)	(69.1		)	(62.1		)	(60.8		)
Cash from Financing Activities	106.3	201.2	8.4	160.2			55.4			41.4
Change in Cash and Cash Equivalents	(76.3)	78.7	(21.5)	(20.3		)	56.2			19.2
Cash and Cash Equivalents at Beginning of Period	102.0	23.3	44.8	101.1			44.9			25.7
Cash and Cash Equivalents at End of Period	$25.7	$102.0	$23.3		$80.8			$101.1			$44.9

The accompanying notes are an integral part of these statements.

ALLETE 2012 Form 10-K

ALLETE Consolidated Statement of Shareholders’ Equity



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

The accompanying notes are an integral part of these statements.

ALLETE ~~2009~~2012 Form 10-K

~~ALLETE Consolidated Statement of Shareholders’ Equity~~

Accumulated
Total Other Unearned
Shareholders’ Retained Comprehensive ESOP Common
Equity Earnings Income (Loss) Shares Stock
Millions
Balance as of December 31, 2006 $665.8 $307.8 $(8.8) $(71.9) $438.7
Comprehensive Income
Net Income 89.5 89.5
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 93.8
   Non-Controlling Interest in Subsidiaries (1.9) (1.9)
Comprehensive Income Attributable to ALLETE 91.9
Adjustment to apply accounting standards for Income Taxes (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 as of December 31, 2007 742.6 350.4 (4.5) (64.5) 461.2
Comprehensive Income
Net Income 83.0 83.0
Other Comprehensive Income – Net of Tax
Unrealized Loss on Securities – Net (6.0) (6.0)
Reclassification Adjustment for Gains Included in Income (3.7) (3.7)
Defined Benefit Pension and Other Postretirement Plans (18.8) (18.8)
Total Comprehensive Income 54.5
   Non-Controlling Interest in Subsidiaries (0.5) (0.5)
Comprehensive Income Attributable to ALLETE 54.0
Adjustment to apply change in Pension and Postretirement 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 as of December 31, 2008 827.1 380.9 (33.0) (54.9) 534.1
Comprehensive Income
Net Income 60.7 60.7
Other Comprehensive Income – Net of Tax
Unrealized Gain on Securities – Net 2.8 2.8
Defined Benefit Pension and Other Postretirement Plans 6.2 6.2
Total Comprehensive Income 69.7
   Non-Controlling Interest in Subsidiaries 0.3 0.3
Comprehensive Income Attributable to ALLETE 70.0
Common Stock Issued – Net 79.3 79.3
Dividends Declared (56.5) (56.5)
ESOP Shares Earned 9.6 9.6
Balance as of December 31, 2009 $929.5 $385.4 $(24.0) $(45.3) $613.4

~~The accompanying notes are an integral part of these statements.~~

~~ALLETE 2009 Form 10-K~~

~~Notes to Consolidated Financial Statements~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~Note 1.~~

~~Operations and Significant Accounting Policies~~

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

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

Subsequent Events.The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of ~~issuing~~ the financial statements ~~on February 12, 2010.~~issuance.

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

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

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

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

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

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

~~ALLETE 2009 Form 10-K~~

~~Note 1.~~

~~Operations and Significant Accounting Policies (Continued)~~

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

ALLETE 2012 Form 10-K

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

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

Non-Controlling Interest in Subsidiaries. In August 2011, ALLETE purchased the remaining shares of the ALLETE Properties non-controlling interest at ~~original cost and are reported on the balance sheet net~~book value for $8.8 million by issuing 0.2 million shares of accumulated depreciation. Expenditures for additions and significant replacements and improvements are capitalized; maintenance and repair costs are expensed as incurred. Expenditures for major plant overhauls are alsoALLETE common stock. This was accounted for ~~using this same policy. Gains or losses on non-rate base property, plant~~as an equity transaction, and ~~equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed,~~ no gain or loss iswas recognized pursuant to guidance on accounting for Regulated Operations. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. (See Note 3. Property, Plant and Equipment.)in net income or comprehensive income.

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

Supplemental Statement of Cash Flow Information



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


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

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


Accounts Receivable
As of December 31	2009	2008	2012		2011
Millions
Trade Accounts Receivable
Billed	$56.5	$61.1		$70.4		$63.7
Unbilled	15.1	15.9	17.4		15.6
Less: Allowance for Doubtful Accounts	0.9	0.7	1.0		0.9
Total Trade Accounts Receivable	70.7	76.3	86.8		78.4
Income Taxes Receivable	47.8	–	2.2		1.3
Total Accounts Receivable – Net	$118.5	$76.3
Total Accounts Receivable - Net				$89.0		$79.7

ALLETE 2012 Form 10-K

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

Long-Term Finance Receivables.~~Inventories.~~ ~~Inventories~~ Long-term finance receivables relating to our real estate operations are ~~stated~~collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the ~~lower~~balance of ~~cost or market. Amounts removed from inventory are recorded on an average cost basis.~~

Inventories
As of December 31
2009
2008
Millions
Fuel $23.0 $16.6
Materials and Supplies 34.0 33.1
Total Inventories $57.0 $49.7

~~ALLETE 2009 Form 10-K~~

~~Note 1.~~

~~Operations and Significant Accounting Policies (Continued)~~

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

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

~~Supplemental Statement of Cash Flow Information~~

Consolidated Statement of Cash Flows
Supplemental Disclosure
Year Ended December 31 2009 2008 2007
Millions
Cash Paid During the Period for
Interest – Net of Amounts Capitalized $29.8 $25.2 $26.3
Income Taxes $1.1 $6.5 $34.2

Noncash Investing and Financing Activities
Changes in Accounts Payable for Capital Additions to Property, Plant and Equipment $24.1 $17.1 $9.8
AFUDC – Equity $5.8 $3.3 $3.8
ALLETE Common Stock contributed to the Pension Plan $(12.0) – –

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

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



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

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

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

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

ALLETE 2012 Form 10-K

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

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

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

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

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

Accounting for Stock-Based Compensation.We apply the fair value recognition guidance for share-based payments. Under this ~~method,~~guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture ~~rate and only for those shares expected to vest over the required service period of the award.~~rate. (See Note ~~17.~~16. Employee Stock and Incentive Plans.)



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

ALLETE 2012 Form 10-K

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Prepayments and Other Current Assets
As of December 31 2009 2008
Millions
Deferred Fuel Adjustment Clause $15.5 $13.1
Other 8.8 11.2
Total Prepayments and Other Current Assets $24.3 $24.3



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


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

Other Liabilities
As of December 31 2009 2008
Millions
Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Plans $231.2 $251.8
Asset Retirement Obligation (See Note 3. Property, Plant and Equipment) 44.6 39.5
Other 49.2 48.0
Total Other Liabilities $325.0 $339.3



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

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

~~ALLETE 2009 Form 10-K~~

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

~~Note 1.~~

~~Operations and Significant Accounting Policies (Continued)~~

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

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

Income Taxes. We ALLETE and its subsidiaries file a consolidated federal income tax ~~return.~~return and combined and separate state income tax returns. We account for income taxes using the liability method ~~as prescribed by~~in accordance with the ~~guidance in~~ accounting standards for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. ~~Investment~~Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. ~~Effective January 1, 2007, we adopted~~In accordance with the ~~guidance~~accounting standards for uncertainty in income ~~taxes. Under this guidance~~taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than 50 ~~percent.~~percent likely. (See Note 14. Income Tax Expense.)

ALLETE 2012 Form 10-K

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

New Accounting Standards.

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

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

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

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

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

~~ALLETE 2009 Form 10-K~~

~~Note 1.~~

~~Operations and Significant Accounting Policies (Continued)~~

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

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

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

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

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

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

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

~~ALLETE 2009 Form 10-K~~

~~Note 1.~~

~~Operations and Significant Accounting Policies (Continued)~~

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

~~Note 2.~~

~~Business Segments~~

NOTE 2. BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ~~and~~ ALLETE Properties, our Florida real estate ~~investment.~~investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately ~~7,000~~6,100 acres of land ~~available-for-sale~~ in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.



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

ALLETE 2012 Form 10-K

NOTE 2. BUSINESS SEGMENTS (Continued)

Regulated Investments
Consolidated Operations and Other
Millions
2009
Operating Revenue $766.7 $689.4 $77.3
Prior Year Rate Refunds (7.6) (7.6) –
Total Operating Revenue 759.1 681.8 77.3
Fuel and Purchased Power 279.5 279.5 –
Operating and Maintenance 308.9 235.8 73.1
Depreciation Expense 64.7 60.2 4.5
Operating Income (Loss) 106.0 106.3 (0.3)
Interest Expense (33.8) (28.3) (5.5)
Equity Earnings in ATC 17.5 17.5 –
Other Income (Expense) 1.8 5.8 (4.0)
Income (Loss) Before Non-Controlling Interest and Income Taxes 91.5 101.3 (9.8)
Income Tax Expense (Benefit) 30.8 35.4 (4.6)
Net Income (Loss) 60.7 65.9 (5.2)
Less: Non-Controlling Interest in Subsidiaries (0.3) – (0.3)
Net Income (Loss) Attributable to ALLETE $61.0 $65.9 $(4.9)

Total Assets $2,393.1 $2,184.0 $209.1
Capital Additions $303.7 $299.2 $4.5



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



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

ALLETE ~~2009~~2012 Form 10-K

~~Note 2. Business Segments (Continued)~~

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 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 Before Non-Controlling Interest and Income Taxes 126.4 111.5 14.9
Income Tax Expense (Benefit) 43.4 43.6 (0.2)
Net Income 83.0 67.9 15.1
Less: Non-Controlling Interest in Subsidiaries 0.5 – 0.5
Net Income Attributable to ALLETE $82.5 $67.9 $14.6

Total Assets $2,134.8 $1,832.1 $302.7
Capital Additions $322.9 $317.0 $5.9

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 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 Before Non-Controlling Interest and Income Taxes 137.2 98.8 38.4
Income Tax Expense 47.7 36.4 11.3
Net Income 89.5 62.4 27.1
Less: Non-Controlling Interest in Subsidiaries 1.9 – 1.9
Net Income Attributable to ALLETE $87.6 $62.4 $25.2

Total Assets $1,644.2 $1,396.6 $247.6
Capital Additions $223.9 $220.6 $3.3

~~Note 3.~~

~~Property, Plant and Equipment~~

NOTE 3. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
As of December 31
2009
2008
Millions
Regulated Utility $2,415.7 $1,837.2
Construction Work in Progress 89.6 303.0
Accumulated Depreciation (928.8) (806.8)
Regulated Utility Plant – Net 1,576.5 1,333.4
Non-Rate Base Energy Operations 87.0 94.0
Construction Work in Progress 3.6 3.9
Accumulated Depreciation (45.5) (47.2)
Non-Rate Base Energy Operations Plant – Net 45.1 50.7
Other Plant – Net 1.1 3.2
Property, Plant and Equipment – Net $1,622.7 $1,387.3

~~ALLETE 2009 Form 10-K~~

~~Note 3.~~

~~Property, Plant and Equipment (Continued)~~



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

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets. ~~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	23 to 3435 years	Non-Rate Base Operations	3 to 61 years
	Transmission	42 to 61 years	Other Plant	5 to 25 years
	Distribution	14 to 65 years

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

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

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



Asset Retirement Obligation
Millions
Obligation as of December 31, ~~2007~~2010			$~~36.5~~50.3
Accretion Expense	~~2.0~~	6.4
Additional Liabilities Incurred in ~~2008~~2011	~~1.0~~	0.3
Obligation as of December 31, ~~2008~~2011	~~39.5~~	57.0
Accretion Expense	~~2.3~~	3.8
Additional Liabilities Incurred in ~~2009~~2012	~~2.8~~	17.1
Obligation as of December 31, ~~2009~~2012			$~~44.6~~77.9

ALLETE 2012 Form 10-K

~~Note 4.~~

~~Jointly-Owned Electric Facility~~

NOTE 4. JOINTLY-OWNED FACILITIES

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



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

We own 80 percent of the ~~536-MW~~585 MW Boswell ~~Energy Center~~ Unit ~~4 (Boswell Unit 4).~~4. While we operate the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which we and ~~Wisconsin Public Power, Inc.,~~WPPI Energy, the owner of the remaining 20 percent of Boswell Unit 4, have equal representation and voting rights. Each of us must provide our own financing and is obligated to pay our ownership share of operating costs. Our share of direct operating expenses of Boswell Unit 4 is included in operating expense on our ~~consolidated statement~~Consolidated Statement of ~~income. Our 80 percent share of~~Income. We are a participant in the ~~cost of Boswell Unit 4, which is included~~CapX2020 initiative to ensure reliable electric transmission and distribution in ~~property, plant~~the region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and equipment at December 31, 2009, was $331 million ($328 million at December 31, 2008). The corresponding accumulated depreciation balance was $178 million at December 31, 2009 ($173 million at December 31, 2008).investor-owned utilities. We are currently participating in three CapX2020 projects with varying ownership percentages.

~~Note 5.~~

~~Regulatory Matters~~

NOTE 5. REGULATORY MATTERS

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

~~2008~~2010 Minnesota Rate Case.~~In May 2008,~~ Minnesota ~~Power filed~~Power’s current retail rates are based on a 2011 MPUC retail rate ~~increase request with the MPUC seeking additional revenues of approximately $40 million annually; the request also sought an 11.15~~order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. As a result of a May 2009 Order and an August 2009 Reconsideration Order, the MPUC granted Minnesota Power a revenue increase of approximately $20 million, including a return on equity of 10.74 percent and a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.

~~ALLETE 2009 Form 10-K~~

~~Note 5.~~

~~Regulatory Matters (Continued)~~

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

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

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

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. ~~In 2008,~~ Minnesota ~~Power entered into new~~Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these ~~customers which transitioned customers to formula-based rates, allowing rates to be adjusted annually based on changes in cost. In February 2009, the FERC approved our municipal~~ contracts ~~which expire December 31, 2013. Under the formula-based rates provision, wholesale rates~~ are calculated using a cost-based formula methodology that is set ~~at the beginning of the year based on expected~~each July 1, using estimated costs and ~~provide~~a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The formula-based rate methodology also provides for a yearly true-up calculation for actual ~~costs. Wholesale rate increases totaling approximately $6 million~~costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and ~~$10 million annually were implemented~~ on ~~February 1, 2009 and January 1, 2010, respectively,~~December 31, 2011, this customer submitted a cancellation notice with ~~approximately $6 million~~termination effective on December 31, 2013. The 17 MW of ~~additional revenues under the true-up provision accrued~~average monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in ~~2009, which will be billed in 2010.~~2014.

~~2009~~2012 Wisconsin Rate ~~Increase.~~Case.During 2012, SWL&P’s ~~current~~retail rates were based on a 2010 PSCW retail rate order, which was effective January 1, 2011. SWL&P’s 2013 retail rates are based on a ~~December 2008~~2012 PSCW retail rate order, ~~that became~~ effective January 1, ~~2009,~~2013, and allows for ~~an 11.1~~a 10.9 percent return on common equity. The new rates ~~reflected a 3.5~~reflect an average overall increase of 2.4 percent ~~average increase in~~for retail ~~utility rates for SWL&P~~ customers (a ~~13.4~~13.8 percent increase in water rates, a ~~4.7~~1.2 percent increase in electric rates, and a ~~0.6~~2.0 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3$1.7 million in additional revenue.

ALLETE 2012 Form 10-K

NOTE 5. REGULATORY MATTERS (Continued)

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

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

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

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

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

ALLETE ~~2009~~2012 Form 10-K

~~Note 5.~~

~~Regulatory Matters~~NOTE 5. REGULATORY MATTERS (Continued)

Deferred Regulatory Assets and Liabilities
As of December 31
2009
2008
Millions
Deferred Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans (a)
235.8 216.5
Boswell Unit 3 Environmental Rider (b)
20.9 3.8
Deferred Fuel (c)
20.8 13.1
Income Taxes 15.7 12.2
Asset Retirement Obligation 6.3 5.1
Deferred MISO Costs 2.4 3.9
Premium on Reacquired Debt 2.0 2.2
Other 4.8 5.6
Total Deferred Regulatory Assets $308.7 $262.4

Deferred Regulatory Liabilities
Income Taxes $25.9 $28.7
Plant Removal Obligations 16.9 15.9
Accrued MISO Refund – 4.7
Other 4.3 0.7
Total Deferred Regulatory Liabilities $47.1 $50.0



Regulatory Assets and Liabilities
As of December 31	2012		2011
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.5		$17.5
Total Current Regulatory Assets	22.5		17.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans	260.7		292.8
Income Taxes	36.0		28.6
Asset Retirement Obligation	12.1		9.8
Cost Recovery Riders (b)	18.5		0.7
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	4.3		4.6
Other	3.7		4.4
Total Non-Current Regulatory Assets	340.3		345.9

Total Regulatory Assets		$362.8		$363.4

Non-Current Regulatory Liabilities
Income Taxes		$19.5		$21.9
Plant Removal Obligations	18.1		15.0
Wholesale and Retail Contra AFUDC	15.5		1.5
Other	7.0		5.1
Total Non-Current Regulatory Liabilities		$60.1		$43.5

~~(a)~~

~~See Note 16. Pension and Other Postretirement Benefit Plans.~~

~~(b)~~

~~MPUC-approved current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to base rates.~~

~~(c)~~

As of December 31, 2009, $5 million of this balance relates to deferred fuel costs incurred under the former base cost of fuel calculation. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

Current and Non-Current Deferred Regulatory Assets and Liabilities
As of December 31
2009
2008
Millions
Total Current Deferred Regulatory Assets (a)
$15.5 $13.1
Total Non-Current Deferred Regulatory Assets 293.2 249.3
Total Deferred Regulatory Assets 308.7 262.4
Total Current Deferred Regulatory Liabilities – –
Total Non-Current Deferred Regulatory Liabilities 47.1 50.0
Total Deferred Regulatory Liabilities $47.1 $50.0

(a)	Current ~~deferred~~ regulatory assets are included in prepayments and other on ~~the consolidated balance sheet.~~our Consolidated Balance Sheet.


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

~~Note 6.~~

~~Investment in~~

NOTE 6. INVESTMENT IN ATC

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

ALLETE’s Interest in ATC
Year Ended December 31
2009
2008
Millions
Equity Investment Beginning Balance $76.9 $65.7
Cash Investments 7.8 7.4
Equity in ATC Earnings 17.5 15.3
Distributed ATC Earnings (13.8) (11.5)
Equity Investment Ending Balance $88.4 $76.9



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

ALLETE ~~2009~~2012 Form 10-K

~~Note 6.~~

~~Investment in~~NOTE 6. INVESTMENT IN ATC (Continued)

ATC Summarized Financial Data
Year Ended December 31
Income Statement Data
       2009
       2008
       2007
Millions
Revenue $521.5 $466.6 $408.0
Operating Expense 230.3 209.0 198.2
Other Expense 77.8 69.6 55.7
Net Income $213.4 $188.0 $154.1
ALLETE’s Equity in Net Income $17.5 $15.3 $12.6



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



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

Balance Sheet Data
Millions
Current Assets $51.1 $50.8 $48.3
Non-Current Assets 2,767.3 2,480.0 2,189.0
Total Assets 2,818.4 2,530.8 2,237.3

Current Liabilities 285.5 252.0 317.1
Long-Term Debt 1,259.6 1,109.4 899.1
Other Non-Current Liabilities 76.9 120.2 108.5
Members’ Equity 1,196.4 1,049.2 912.6
Total Liabilities and Members’ Equity $2,818.4 $2,530.8 $2,237.3

~~Note 7.~~

~~Investments~~

NOTE 7. INVESTMENTS

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

Investments
As of December 31
2009
2008
Millions
ALLETE Properties $93.1 $84.9
Available-for-sale Securities 29.5 32.6
Other 7.9 19.4
Total Investments $130.5 $136.9



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

ALLETE 2012 Form 10-K

NOTE 7. INVESTMENTS (Continued)


ALLETE Properties
As of December 31	2009	2008	2012			2011
Millions
Land Held-for-Sale Beginning Balance	$71.2	$62.6
Additions during period: Capitalized Improvements	5.6	10.5
Deductions during period: Cost of Real Estate Sold	(1.9)	(1.9)
Land Held-for-Sale Ending Balance	74.9	71.2
Long-Term Finance Receivables	12.9	13.6
Land Inventory Beginning Balance				$86.0			$86.0
Deeds to Collateralized Property			0.5			1.8
Land Impairment			—			(1.7		)
Cost of Sales			(0.2		)	(0.3		)
Capitalized Improvements and Other			0.2			0.2
Land Inventory Ending Balance			86.5			86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)			1.4			2.0
Other	5.3	0.1	3.2			3.3
Total Real Estate Assets	$93.1	$84.9		$91.1			$91.3

Land Inventory. Land ~~Held-for-Sale.~~ ~~Land held-for-sale~~inventory is accounted for as held for use and is recorded at cost, unless the ~~lower of cost or~~carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair ~~value determined by the evaluation of individual land parcels.~~value. Land values are reviewed for impairment on a quarterly basis. In 2012, impairment analysis’ of estimated future undiscounted cash flows was conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. Consequently, there was no ~~impairments were~~ impairment recorded for the year ended December 31, ~~2009 (none in 2008)~~2012. For the year ended

~~ALLETE 2009 Form 10-K~~

~~Note 7.~~

~~Investments (Continued)~~

December 31, 2011, a 1.7 million impairment charge was recorded.

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

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

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



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

Available-For-Sale Securities
Millions Gross Unrealized
As of December 31
Cost
Gain (Loss) Fair Value

2009 $33.1 $0.1 $(3.7) $29.5
2008 $40.5 – $(7.9) $32.6
2007 $45.3 $8.4 $(0.1) $53.6



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

Net Unrealized
Net Gross Realized Gain (Loss) in Other
Year Ended December 31 Proceeds Gain (Loss) Comprehensive Income

2009 $6.7 – – $4.5
2008 $17.5 $6.5 $(0.1) $(9.7)
2007 $81.4 – – $1.4

ALLETE 2012 Form 10-K

NOTE 8. DERIVATIVES

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

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

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

~~Note 8.~~

~~Derivatives~~

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

~~ALLETE 2009 Form 10-K~~

~~Note 8.~~

~~Derivatives (Continued)~~

Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria is met. Favorable changes in fair value of $0.3 million and $0.1 million were recorded in operating revenue in the first and second quarters of 2009, respectively; and a $0.4 million decrease was recorded in the third quarter of ~~2009 when~~2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the ~~corresponding energy~~interest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 8 percent of the Company’s outstanding long-term debt as of December 31, 2012. (See Note 10. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap ~~contract ended.~~

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

~~Note 9.~~

~~Fair Value~~

NOTE 9. FAIR VALUE

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

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

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

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

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, ~~2009~~2012 and December 31, ~~2008.~~2011. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, ~~and~~which may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the tables below.

ALLETE 2012 Form 10-K

NOTE 9. FAIR VALUE (Continued)

At Fair Value as of December 31, 2009
Recurring Fair Value Measures Level 1 Level 2 Level 3 Total
Millions
Assets:
Equity Securities $17.8 – – $17.8
Corporate Debt Securities – $6.4 – 6.4
Derivatives – – $0.7 0.7
Debt Securities Issued by States of the United States (ARS) – – 6.7 6.7
Money Market Funds 1.4 – – 1.4
Total Fair Value of Assets $19.2 $6.4 $7.4 $33.0

Liabilities:
Deferred Compensation – $14.6 – $14.6
Total Fair Value of Liabilities – $14.6 – $14.6

Total Net Fair Value of Assets (Liabilities) $19.2 $(8.2) $7.4 $18.4

~~ALLETE 2009 Form 10-K~~

~~Note 9.~~

~~Fair Value (Continued)~~



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$18.0	—		—		$18.0
Available-for-sale Securities – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5

Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

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

~~(a)~~

~~ARS called during 2009 at par value.~~



	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$17.6	—		—		$17.6
Available-for-sale Securities – Corporate Debt Securities	—			$8.2	—	8.2
Cash Equivalents	11.4		—		—	11.4
Total Fair Value of Assets		$29.0		$8.2	—		$37.2

Liabilities:
Deferred Compensation	—			$12.8	—		$12.8
Derivatives – Interest Rate Swap	—			$0.4	—		$0.4
Total Fair Value of Liabilities	—			$13.2	—		$13.2
Total Net Fair Value of Assets (Liabilities)		$29.0	$(5.0)		—		$24.0

At Fair Value as of December 31, 2008
Recurring Fair Value Measures Level 1 Level 2 Level 3 Total
Millions
Assets:
Equity Securities $13.5 – – $13.5
Corporate Debt Securities – $3.3 – 3.3
Debt Securities Issued by States of the United States (ARS) – – $15.2 15.2
Money Market Funds 10.6 – – 10.6
Total Fair Value of Assets $24.1 $3.3 $15.2 $42.6

Liabilities:
Deferred Compensation – $13.5 – $13.5
Total Fair Value of Liabilities – $13.5 – $13.5

Total Net Fair Value of Assets (Liabilities) $24.1 $(10.2) $15.2 $29.1

			~~Debt Securities~~
	~~Issued by the States~~
Recurring Fair Value Measures	~~of the United States~~
Activity in Level 3	Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, ~~2007~~2010	–	$6.7
~~Purchases, sales, issuances and settlements, net~~ Redeemed During the Period (a)	~~$(10.0)~~
~~Level 3 transfers in~~(6.7	~~25.2~~)
Balance as of December 31, ~~2008~~2011		$~~15.2~~—


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

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

ALLETE 2012 Form 10-K

NOTE 9. FAIR VALUE (Continued)

~~(a)~~

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

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


Financial Instruments	Carrying Amount	Fair Value	Carrying Amount		Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2009	$701.0	$734.8
December 31, 2008	$598.7	$561.6
December 31, 2012				$1,018.1		$1,143.7
December 31, 2011				$863.3		$966.4

~~Note 10.~~

~~Short-Term and Long-Term Debt~~

NOTE 10. SHORT-TERM AND LONG-TERM DEBT

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

~~ALLETE 2009 Form 10-K~~

~~Note 10.~~

~~Short-Term and Long-Term Debt (Continued)~~

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

As of December 31, 2012, we had bank lines of credit aggregating ~~$157.0~~$406.4 million ~~($160.5~~ ($256.4 million at December 31, ~~2008)~~2011), ~~the majority~~ of which ~~expire~~$150.0 million expires in January ~~2012.~~2014, and $250.0 million expires in June 2015. These bank lines of credit ~~make financing~~are available ~~through~~to provide short-term bank loans and ~~provide credit~~liquidity support for ALLETE’s commercial ~~paper. At December 31, 2009, $69.2~~paper program and to issue up to $50.0 million ~~($7.3 million at December 31, 2008) was drawn~~ in letters of credit. We had no outstanding draws on our lines of credit ~~leaving a $87.8 million balance available for use ($153.2 million at~~ as of December 31, ~~2008). In December 2009, we drew $65.0~~2012 ($1.1 million on our $150.0 million syndicated revolving credit facility to temporarily fund the purchase of the 250 kV DC transmission line. In December 2009, we agreed to sell $80.0 million of First Mortgage Bonds in February 2010 (see Long-Term Debt, below). We intend to use proceeds from these bonds to repay the amount drawn on the line, resulting in $65.0 million of our line of credit being classified as long-term at December 31, ~~2009.~~2011).

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

Long-Term Debt. Total long-term debt outstanding as of December 31, 2012, was $933.6 million ($857.9 million at December 31, 2011). The aggregate amount of long-term debt maturing during ~~2010~~2013 is ~~$5.2~~$84.5 million ~~($13.9~~ ($94.8 million in ~~2011; $3.3~~2014; $17.4 million in ~~2012; $73.9~~2015; $21.7 million in ~~2013; $19.6~~2016; $51.2 million in ~~2014;~~2017; and ~~$520.1~~$748.5 million thereafter). Substantially all of our electric plant is subject to the lien of the ~~mortgages~~mortgage collateralizing ~~various~~outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

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

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



Issue Date ~~(on or about)~~	Maturity Date	Principal Amount	~~Coupon~~Interest Rate
~~February 17, 2010~~July 2, 2012	~~April~~July 15, ~~2021~~2026	$1575 Million	~~4.85%~~3.20%
~~February 17, 2010~~July 2, 2012	~~April~~July 15, ~~2025~~2042	$3085 Million	~~5.10%~~
~~February 17, 2010~~	~~April 15, 2040~~	~~$35 Million~~	~~6.00%~~4.08%

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

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

ALLETE ~~2009~~2012 Form 10-K

~~Note 10.~~

~~Short-Term and Long-Term Debt~~NOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt
As of December 31 2009 2008
Millions
First Mortgage Bonds
4.86% Series Due 2013 $60.0 $60.0
6.94% Series Due 2014 18.0 18.0
7.70% Series Due 2016 20.0 20.0
8.17% Series Due 2019 42.0 –
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 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 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 28.3
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
Line of Credit Facility (a)
65.0 –
Other Long-Term Debt, 2.0% – 8.0% Due 2009 – 2037 42.9 47.6
Total Long-Term Debt 701.0 598.7
Less: Due Within One Year 5.2 10.4
Net Long-Term Debt $695.8 $588.3

~~(a)~~

~~The $80 million First Mortgage Bonds due in 2021, 2025 and 2040 to be issued on or about February 17, 2010, will replace the balance due on the Line of Credit Facility as of December 31, 2009.~~



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

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive covenant requires ALLETE to maintain a ratio of its ~~Funded Debt~~Indebtedness to Total ~~Capital~~Capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00 measured quarterly. As of December 31, ~~2009,~~2012, our ratio was approximately ~~0.41~~0.46 to ~~1.00.~~1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ~~None of ALLETE’s long-term debt arrangements or credit facilities contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances.~~ As of December 31, ~~2009,~~2012, ALLETE was in compliance with its financial covenants.

~~Note 11.~~

~~Commitments, Guarantees and Contingencies~~

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES

~~Off-Balance Sheet Arrangements~~

Power Purchase Agreements.Our long-term ~~power purchase agreements (PPA)~~PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the ~~PPA,~~PPAs, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the ~~following factors: we have no equity investment in these facilities and do not incur actual or expected losses related to the loss of facility value, and~~fact that we do not have ~~significant~~both control over activities that are most significant to the ~~operations of each of these facilities.~~entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our ~~fixed~~ capacity and energy payments.

ALLETE 2012 Form 10-K

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

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

~~ALLETE 2009 Form 10-K~~

~~Note 11. Commitments, Guarantees and Contingencies (Continued)~~

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the ~~contract.~~contract, subject to the provisions of the Minnkota Power sales agreement described below. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s ~~fixed~~ costs consist primarily of debt ~~service. At~~ service, operating and maintenance, depreciation and fuel expenses. As of December 31, ~~2009,~~2012, Square Butte had total debt outstanding of ~~$351.0 million.~~$416.9 million. Annual debt service for Square Butte is expected to be approximately ~~$34~~$44 million in each of the next five years, ~~2010~~2013 through ~~2014. Variable operating costs~~2017, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the ~~price~~cost of coal purchased from BNI Coal, ~~our subsidiary,~~ under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during ~~2009~~2012 was ~~$53.9~~$67.1 million ~~($56.7~~ ($61.2 million in ~~2008; $57.3~~2011; $55.2 million in ~~2007)~~2010). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output ~~entitlement in 2009, the 55 percent output entitlement in 2008 and the 60 percent output entitlement in 2007.~~entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of ~~$11.0~~$11.1 million in ~~2009 ($11.6~~2012 ($11.1 million in ~~2008; $11.0~~2011; $10.2 million in ~~2007)~~2010). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

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

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

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

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

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

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

ALLETE 2012 Form 10-K

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

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

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

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

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

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

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

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

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling ~~$2.8~~$2.8 million annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at a fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a ~~$3.0~~$3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is ~~$8.8~~$11.5 million in ~~2010, $8.9~~2013, $11.7 million in ~~2011, $9.0~~2014, $11.4 million in ~~2012, $8.5~~2015, $9.3 million in ~~2013, $8.2~~2016, $8.5 million in ~~2014~~2017 and ~~$45.7~~$35.0 million thereafter. Total rent and lease expense was ~~$9.3~~$11.5 million in ~~2009 ($8.5~~2012 ($9.4 million in ~~2008; $8.4~~2011; $9.4 million in ~~2007)~~2010).

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

ALLETE ~~2009~~2012 Form 10-K

~~Note~~NOTE 11. ~~Commitments, Guarantees and Contingencies~~COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

Transmission Investments.~~Coal, Rail and Shipping Contracts.~~ We have ~~two primary coal supply agreements with expiration dates through December~~an approved cost recovery rider in place for certain transmission investments and expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. ~~We also have rail and shipping agreements~~The billing factor allows us to charge our retail customers on a current basis for the ~~transportation~~costs of ~~all~~constructing certain transmission facilities plus a return on the capital invested. In June 2011, we filed an updated billing factor that includes additional transmission expenditures, which we expect to be approved in the first quarter of ~~our coal, with expiration dates~~2013.

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

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

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

Environmental ~~Matters.~~Matters

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~~Accruals are adjusted ~~periodically~~ as assessment and remediation efforts progress or as additional technical or legal information ~~become~~becomes available. Accruals for environmental liabilities are included in the ~~consolidated balance sheet~~Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.

ALLETE 2012 Form 10-K

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

~~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 SO~~2~~, NO~~X, and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit (Court) vacated the CAIR and remanded the rulemaking to the EPA for reconsideration while also granting our petition that the EPA reconsider including Minnesota as a CAIR state. In September 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested that the CAIR be remanded without a court order. In December 2008, the Court granted the request that the CAIR be remanded without a court order, effectively reinstating a January 1, 2009 compliance date for the CAIR, including Minnesota. However, in the May 12, 2009 Federal Register the EPA issued a proposed rule that would amend the CAIR to stay its effectiveness with respect to Minnesota until completion of the EPA’s determination of whether Minnesota should be included as a CAIR state. The formal administrative stay of CAIR for Minnesota was published in the November 3, 2009, Federal Register with an effective date of December 3, 2009.

~~ALLETE 2009 Form 10-K~~

~~Note 11.~~

~~Commitments, Guarantees and Contingencies (Continued)~~

~~Environmental Matters (Continued)~~

ALLETE 2012 Form 10-K

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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

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

ALLETE 2012 Form 10-K

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

Expand our renewable energy supply;

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

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

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

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

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

Clean Air Act’s Title V program. For our existing facilities, the ~~proposed~~ rule does not require amending our existing Title V operating permits to include ~~BACT for GHGs.~~GHG requirements. However, ~~modifying or installing units with~~ GHG ~~emissions that trigger the PSD permitting~~ requirements ~~could require amending~~are likely to be added to our existing Title V operating permits ~~to incorporate BACT to control GHG emissions.~~by the MPCA as these permits are renewed or amended.

ALLETE ~~2009~~2012 Form 10-K

~~Note 11.~~

~~Commitments, Guarantees and Contingencies~~NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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

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

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

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

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

ALLETE 2012 Form 10-K

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

~~EPA Endangerment Findings.~~ ~~On December 15, 2009, the EPA published its findings that the emissions of six GHG, including CO~~2, methane, and nitrous oxide, endanger human health or welfare. This finding may result in regulations that establish motor vehicle GHG emissions standards in 2010. There is also a possibility that the endangerment finding will enable expansion of the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. with the United States District Court Circuit Court of Appeals on December 23, 2009.

Coal Ash Management ~~Facilities.~~Facilities. Minnesota Power generates coal ash at all five of its ~~steam~~coal-fired electric ~~stations.~~generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. ~~Minnesota Power continues to monitor state and federal legislative and~~In June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory ~~activities that may affect its ash management practices. The USEPA is expected to propose new regulations~~schemes for coal ash. Comments on the proposed rule were due in ~~February 2010, pertaining to the management of coal ash by electric utilities.~~November 2010. It is ~~unknown how potential coal ash management~~estimated that the final rule ~~changes~~ will ~~affect Minnesota Power’s facilities. On March 9, 2009,~~be published in 2013. We are unable to predict the ~~EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received an~~compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional EPA information request pertaining to Boswell. Minnesota Power responded to both these information requests. On August 19, 2009, Dam Safety officials from the Minnesota DNR visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findingscosts through cost recovery riders or ~~concerns from the DNR staff during the inspections.~~in a general rate case.

Other Matters

BNI Coal.~~Manufactured Gas Plant Site.~~ ~~We are reviewing and addressing environmental conditions at a former manufactured gas plant site within the City~~ As of ~~Superior, Wisconsin and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. At~~ December 31, ~~2009 we have a $0.5 million liability for this site, and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.~~2012

~~BNI Coal.~~ ~~As of December 31, 2009,~~, BNI Coal had surety bonds outstanding of ~~$18.4~~$29.8 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, an additional ~~guarantee~~assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a ~~Letter~~letter of ~~Credit~~credit with CoBANK ACB for an additional ~~$10.0~~$2.6 million ~~of which $6.7 million is needed~~ to ~~meet the requirements~~provide for ~~BNI’s~~BNI Coal’s total reclamation liability, which is currently estimated at ~~$25.1 million.~~$32.4 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties.As of December 31, ~~2009,~~2012, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of ~~$19.1~~credit to governmental entities totaling $10.2 million primarily related to ~~performance~~development and maintenance obligations ~~to governmental entities to construct improvements in the company’s~~for various projects. The estimated cost of the remaining development work ~~to be completed on these improvements~~ is ~~estimated to be~~ approximately ~~$10.2~~$7.4 million ~~and~~, of which $0.6 million is the contractual obligation of land purchasers. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued ~~$26.4~~$26.4 million of tax-exempt, 6 percent ~~Capital Improvement Revenue Bonds, Series 2005;~~capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued ~~$31.8~~$31.8 million of tax-exempt, 5.7 percent ~~Special Assessment Bonds, Series 2006.~~special assessment bonds. The ~~Capital Improvement Revenue Bonds~~capital improvement revenue bonds and the ~~Special Assessment Bonds~~special assessment bonds are payable ~~through property tax assessments on the land owners~~ over 31 years (by May 1, 2036 and 2037, respectively). and secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The ~~bonds are payable from and secured by the revenue derived from assessments imposed, levied and collected by each district. The~~ assessments were billed to the landowners beginning in November 2006 for Town Center and November 2007 for Palm Coast Park. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At December 31, ~~2009,~~2012, we owned 6973 percent of the assessable land in the Town Center District ~~(69~~(73 percent at December 31, ~~2008)~~2011) and 8693 percent of the assessable land in the Palm Coast Park District ~~(86~~(93 percent at December 31, ~~2008)~~2011). At these ownership levels, our annual assessments are ~~$1.4~~approximately $1.4 million for Town Center and ~~$1.9~~$2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. ~~Under current~~In accordance with accounting ~~rules,~~guidance, these bonds are not reflected as debt on our ~~consolidated balance sheet.~~Consolidated Balance Sheet.

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

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

ALLETE ~~2009~~2012 Form 10-K

~~Note 12.~~

~~Common Stock and Earnings Per Share~~

NOTE 12. COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock Shares Equity
Thousands Millions
Balance as of December 31, 2006 30,436 $438.7
2007   Employee Stock Purchase Plan 17 0.7
Invest Direct 331 15.1
Options and Stock Awards 43 6.7
Balance as of December 31, 2007 30,827 $461.2
2008   Employee Stock Purchase Plan 17 0.6
Invest Direct 161 6.9
Options and Stock Awards 24 4.6
Equity Issuance Program 1,556 60.8
Balance as of December 31, 2008 32,585 $534.1
2009   Employee Stock Purchase Plan 24 0.7
Invest Direct 456 13.6
Options and Stock Awards 8 1.1
Equity Issuance Program 1,685 51.9
Contributions to Pension 463 12.0
Balance as of December 31, 2009 35,221 $613.4



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

Equity Issuance Program. We entered into a ~~Distribution Agreement~~distribution agreement with KCCI, Inc., ~~originating~~ in February 2008, ~~and subsequently~~as amended ~~in February 2009,~~most recently on August 3, 2012, with respect to the issuance and sale of up to an aggregate of ~~6.6~~9.6 million shares of our common stock, without par ~~value.~~value, of which 4.5 million remain available for issuance. For the year ended December 31, 2012, 1.3 million shares of common stock were issued under this agreement resulting in net proceeds of $53.1 million. During 2011, 0.4 million shares of common stock were issued for net proceeds of $16.0 million. The shares issued in 2012 and 2011 were, and the remaining shares may be, offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-147965. During 2009, 1.7 million shares of common stock were issued under this agreement resulting in net proceeds of $51.9 million. In 2008, 1.6 million shares were issued for net proceeds of $60.8 million. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.)333-170289.

~~Contributions to Pension.~~ In March 2009, we contributed 0.5 shares of ALLETE common stock, with an aggregate value of $12.0 million, to our pension plan. On May 19, 2009, we registered the 0.5 shares of ALLETE common stock with the SEC pursuant to Registration Statement No. 333-147965. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.)

~~Authorized Common Stock.~~ On May 12, 2009, shareholders approved an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from 43.3 million to 80.0 million.

~~Shareholder Rights Plan.~~ On July 25, 1996, ALLETE adopted a shareholder rights plan, which was amended and restated on July 12, 2006 (collectively, the “Rights Plan”). The amendment to the Rights Plan, among other things, extended the final expiration date of the Rights Plan to July 11, 2009. The Rights Plan expired according to its terms on July 11, 2009. As a result, ALLETE’s preferred share purchase rights issued in accordance with the Rights Plan are no longer outstanding.

Earnings Per Share. The difference between basic and diluted earnings per share, ~~arises,~~ if any, arises from outstanding stock options, non-vested restricted stock, and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. In 2012, in accordance with accounting standards for earnings per share, ~~for 2009, 0.6~~0.2 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market ~~prices, and~~prices; therefore, their effect would behave been anti-dilutive ~~(0.6~~(0.3 million shares were excluded in 2011 and 0.5 million in 2010).

Purchase of Non-Controlling Interest. In 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased at book value for ~~2008 and~~ $8.8 million by issuing 0.2 million unregistered shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss is recognized in ~~2007).~~net income or comprehensive income.

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

ALLETE ~~2009~~2012 Form 10-K

~~Note 12.~~

~~Common Stock and Earnings Per Share~~NOTE 12. COMMON STOCK AND EARNINGS PER SHARE (Continued)

Reconciliation of Basic and Diluted
Earnings Per Share Dilutive
Year Ended December 31 Basic Securities Diluted
Millions Except Per Share Amounts

2009
Net Income Attributable to ALLETE $61.0 – $61.0
Common Shares 32.2 – 32.2
Per Share of Common Stock $1.89 – $1.89

2008
Net Income Attributable to ALLETE $82.5 – $82.5
Common Shares 29.2 0.1 29.3
Per Share of Common Stock $2.82 – $2.82

2007
Net Income Attributable to ALLETE $87.6 – $87.6
Common Shares 28.3 0.1 28.4
Per Share of Common Stock $3.09 – $3.08



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

~~Note 13.~~

~~Other Income (Expense)~~

NOTE 13. OTHER INCOME (EXPENSE)

Year Ended December 31 2009 2008 2007
Millions
Loss on Emerging Technology Investments $(4.6) $(0.7) $(1.3)
AFUDC - Equity 5.8 3.3 3.8
Investments and Other Income (a)
0.6 13.0 13.0
Total Other Income $1.8 $15.6 $15.5

~~(a)~~

In 2008, Investment and Other Income included a gain from the sale of certain available-for-sale securities. The gain was triggered when securities were sold to reallocate investments to meet defined investment allocations based upon an approved investment strategy. In 2007, Investment and Other Income primarily included earnings on excess cash and Minnesota land sales.



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

ALLETE 2012 Form 10-K

~~Note~~NOTE 14. ~~Income Tax Expense~~INCOME TAX EXPENSE

Income Tax Expense
Year Ended December 31 2009 2008 2007
Millions
Current Tax Expense (Benefit)
Federal (a)
$(42.6) $6.2 $26.5
State (1.8) (1.6) 7.2
Total Current Tax Expense (Benefit) (44.4) 4.6 33.7
Deferred Tax Expense
Federal 66.0 29.3 10.7
State 10.3 13.4 4.7
Change in Valuation Allowance (0.1) (2.9) (0.3)
Investment Tax Credit Amortization (1.0) (1.0) (1.1)
Total Deferred Tax Expense 75.2 38.8 14.0
Total Income Tax Expense $30.8 $43.4 $47.7



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

(a)

~~Due~~For the years ended December 31, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation ~~provisions~~provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, a federal current tax benefit was recorded as a result of tax planning initiatives and the bonus depreciation provision in the ~~American Recovery and Reinvestment~~Small Business Jobs Act of ~~2009, we are in a net operating loss position for 2009.~~2010. The ~~loss will be~~2010 federal NOL was partially utilized by carrying it back against prior years’ ~~taxable~~income with the remainder carried forward to offset future years’ income.

(b)

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


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



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

ALLETE ~~2009~~2012 Form 10-K

~~Note 14.~~

~~Income Tax Expense~~NOTE 14. INCOME TAX EXPENSE (Continued)

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31 2009 2008 2007
Millions
Income Before Non-Controlling Interest and Income Taxes $91.5 $126.4 $137.2
Statutory Federal Income Tax Rate 35% 35% 35%
Income Taxes Computed at 35 percent Statutory Federal Rate $32.0 $44.2 $48.0
Increase (Decrease) in Tax Due to:
Amortization of Deferred Investment Tax Credits (1.0) (1.0) (1.1)
State Income Taxes – Net of Federal Income Tax Benefit 5.4 4.8 7.4
Depletion (0.9) (0.8) (0.9)
Regulatory Differences for Utility Plant (2.5) (1.6) (2.2)
Production Tax Credit (1.2) (0.4) –
Positive Resolution of Audit Issues – – (1.6)
Other (1.0) (1.8) (1.9)
Total Income Tax Expense $30.8 $43.4 $47.7

The effective tax rate on income ~~from continuing operations before non-controlling interest~~ was ~~33.7~~28.1 percent for ~~2009; (34.3~~2012 (27.6 percent for ~~2008; 34.8~~2011; 37.2 percent for ~~2007)~~2010). The ~~2009~~2012 effective ~~tax~~ rate was primarily impacted by ~~deductions~~renewable tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above)~~, investment tax credits, wind production tax credits and depletion.~~. The ~~2008~~2011 effective tax rate was primarily impacted by ~~deductions~~the deduction for AFUDC-Equity, ~~(included in Regulatory Differences for Utility Plant, above), investment tax credits, wind production tax credits, depletion, recognition of a benefit on~~ the reversal of a ~~previously uncertain~~deferred tax ~~position ($1.7 million included in Other, above) and~~liability related to a ~~benefit for the reversal~~revenue receivable that Minnesota Power agreed to forgo as part of a ~~state income~~stipulation and settlement agreement in its 2010 rate case, renewable tax ~~valuation allowance ($2.9 million included~~credits, and the MPUC’s approval of our request to defer the retail portion of the tax charge taken in ~~State Income Taxes, above).~~2010 as a result of the PPACA. The 2010 effective tax rate was primarily impacted by the PPACA eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, the deduction for AFUDC-Equity, and renewable tax credits.

Deferred Tax Assets and Liabilities
As of December 31 2009 2008
Millions
Deferred Tax Assets
Employee Benefits and Compensation (a)
$118.2 $125.2
Property Related 46.5 36.4
Investment Tax Credits 10.0 10.7
Other 14.4 16.3
Gross Deferred Tax Assets 189.1 188.6
Deferred Tax Asset Valuation Allowance (0.3) (0.4)
Total Deferred Tax Assets $188.8 $188.2
Deferred Tax Liabilities
Property Related $294.1 $235.6
Regulatory Asset for Benefit Obligations 96.5 87.7
Unamortized Investment Tax Credits 14.1 15.1
Partnership Basis Differences 14.6 3.7
Other 28.2 16.8
Total Deferred Tax Liabilities $447.5 $358.9
Net Deferred Income Taxes $258.7 $170.7

Recorded as:
Net Current Deferred Tax Liabilities (b)
$5.6 $1.1
Net Long-Term Deferred Tax Liabilities 253.1 169.6
Net Deferred Income Taxes $258.7 $170.7



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

~~(a)~~

~~Includes Unfunded Employee Benefits~~

~~(b)~~(a)

Included in Other Current Liabilities.



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


(a)	Pretax amounts


(b)	Net of $0.4 million valuation allowance.


(c)	Net of $2.0 million valuation allowance.

ALLETE 2012 Form 10-K

NOTE 14. INCOME TAX EXPENSE (Continued)

~~As of December 31, 2009~~In 2012, we ~~had a~~generated federal ~~net operating loss of $85.7 million~~and various state NOLs and tax credit carryforwards primarily due to the bonus depreciation provisions inof the ~~American Recovery~~Tax Relief, Unemployment Insurance Reauthorization, and ~~Reinvestment~~Job Creation Act of ~~2009. In 2010, this~~2010. The 2012 federal ~~net operating loss~~NOL will be ~~fully~~ utilized by carrying it ~~back against prior~~forward to offset future years’ ~~taxable~~ income. ~~We also have various state net operating loss~~The federal NOL and tax credit carryforward periods expire between 2019 and 2032; included in the federal NOL carryforward are charitable contribution carryforwards ~~totaling $23.8 million available to reduce future taxable income.~~which expire between 2014 and 2016. We expect to fully utilize the federal NOL, charitable contributions, and federal tax ~~benefit~~credit carryforwards; therefore no valuation allowance has been recognized as of ~~these losses prior to their expirations in 2024 through 2029.~~

~~ALLETE 2009 Form 10-K~~

~~Note 14.~~

~~Income Tax Expense (Continued)~~

Gross Unrecognized Income Tax Benefits 2009 2008 2007
Millions
Balance at January 1 $8.0 $5.3 $10.4
Additions for Tax Positions Related to the Current Year 0.5 0.7 0.8
Reductions for Tax Positions Related to the Current Year – – –
Additions for Tax Positions Related to Prior Years 1.0 4.5 –
Reduction for Tax Positions Related to Prior Years – (2.5) (2.4)
Settlements – – (3.5)
Balance as of December 31 $9.5 $8.0 $5.3
December 31, 2012.

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



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

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

The gross ~~amount of~~ unrecognized tax benefits as of December 31, ~~2009,~~2012, includes ~~$1.5~~$0.5 million of net unrecognized tax benefits that, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $8.7 million in 2012 was due to the removal of our uncertain tax position for our tax accounting method change for deductible repairs. During 2012, the IRS issued a directive from its Large Business and International Division to its local examination teams that led to the removal of the repairs uncertain tax position in 2012.

As of December 31, ~~2009,~~2012, we had ~~$0.9~~$0.5 million ~~($0.6~~ ($1.1 million for ~~2008)~~2011 and $0.7 million for 2010) of accrued interest related to unrecognized tax benefits included in ~~the consolidated balance sheet.~~our Consolidated Balance Sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in ~~the consolidated statement~~our Consolidated Statement of ~~income.~~Income. In ~~2009,~~2012, we recognized ~~$0.4~~a $0.6 million decrease in interest expense (interest expense of $0.4 million for 2011 and a reduction of interest expense ~~($0.4~~of $0.2 million for ~~2008 and $0.1 million for 2007)~~2010). There were no penalties recognized ~~for 2009, 2008~~in 2012, 2011 or ~~2007.~~2010.

WeALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE is currently under examination by the ~~United States and various state jurisdictions.~~IRS for the tax years 2005 through 2009. ALLETE is no longer subject to federal or state examination for years before ~~2005 or state examinations for years before 2004.~~2005.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by ~~$3.6~~$2.5 million due to statute expirations and anticipated audit settlements. This amount is primarily due to ~~timing issues.~~temporary tax positions.

~~Note 15.~~

~~Other Comprehensive Income (Loss)~~

ALLETE 2012 Form 10-K

Other Comprehensive Income (Loss)
Year Ended December 31 2009 2008 2007
Millions
Net Income $60.7 $83.0 $89.5
Other Comprehensive Income
    Unrealized Gain on Securities
   Net of income taxes of $1.7, $(3.7), and $0.3
2.8 (6.0) 1.1
    Reclassification Adjustment for Losses Included in Income
      Net of income taxes of $–, $(2.7), and $–
– (3.7) –
    Defined Benefit Pension and Other Postretirement Plans
   Net of income taxes of $4.1, $(13.3), and $2.3
6.2 (18.8) 3.2
Total Other Comprehensive Income (Loss) 9.0 (28.5) 4.3
Total Comprehensive Income $69.7 $54.5 $93.8
Less: Non-Controlling Interest in Subsidiaries (0.3) 0.5 1.9
Comprehensive Income Attributable to ALLETE $70.0 $54.0 $91.9

Accumulated Other Comprehensive Income (Loss)
As of December 31 2009 2008
Millions
Unrealized Gain (Loss) on Securities $(1.8) $(4.6)
Defined Benefit Pension and Other Postretirement Plans (22.2) (28.4)
Total Accumulated Other Comprehensive Loss $(24.0) $(33.0)

~~Note 16. Pension and Other Postretirement Benefit Plans~~NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. In ~~2009,~~2012, we made a total contributions of ~~$32.9~~$7.3 million ~~($10.9~~ ($33.8 million in ~~2008) in contributions to ALLETE’s defined benefit pension plans~~2011, of which ~~$12.0~~$20.0 million was contributed in shares of ALLETE common ~~stock.~~stock). We also have a defined contribution pension ~~plans~~plan covering substantially all employees. The ~~2009~~2012 plan year employer contributions, which are made through ~~our~~the employee stock ownership plan portion of the RSOP, totaled ~~$9.1~~$7.7 million ~~($7.1~~ ($7.3 million for the ~~2008~~2011 plan year.) (See Note 12. Common Stock and Earnings Per Share and Note ~~17.~~16. Employee Stock and Incentive Plans)

~~ALLETE 2009 Form 10-K~~

~~Note 16.~~

~~Pension and Other Postretirement Benefit Plans (Continued)~~

In 2006, ~~amendments were made to~~ the ~~non-union defined benefit pension plan and the Retirement Savings and stock Ownership Plan (RSOP). The~~ non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and ~~closed~~to close the plan to new participants. In conjunction with ~~the change,~~those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.

We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to age 55 with 10 years of participation in the plan. The postretirement health plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and an irrevocable grantor ~~trusts.~~trust. In ~~2009~~2012, $1.5 million was contributed to the VEBAs. In 2011, we contributed $10.9 million to the VEBAs. There were no contributions made ~~a net contribution of $0.3 million~~ to the grantor trust in 2012and ~~$9.3 million to the VEBAs. In 2008 $3.7 million was contributed to the VEBAs.~~2011.

Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the pension plans. ~~Estimated defined benefit pension contributions for years 2010 through 2014 are expected to be up to $25 million per year, and~~Contributions are based on estimates and assumptions ~~that~~which are subject to change. ~~Funding for~~We do not expect to make any contributions to the ~~other postretirement~~defined benefit ~~plans is impacted by utility regulatory requirements. Estimated~~pension plan in 2013. In January 2013, we contributed $4.8 million to the defined benefit postretirement health and life plan, of which $2.0 million was contributed to an irrevocable grantor trust and $2.8 million was contributed to the VEBAs. We do not expect to make any additional contributions ~~for years 2010 through 2014 are approximately $11 million per year,~~to the defined benefit postretirement health and ~~are based on estimates and assumptions that are subject to change.~~life plan in 2013.

Accounting for ~~Defined Benefit Pension~~defined benefit pension and ~~Postretirement Benefit Plans~~postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their ~~consolidated balance sheet~~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.

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

~~During the year ended December 31, 2008, we were required to change our measurement date from September 30 to December 31. On January 1, 2008,~~

ALLETE recorded three months of pension expense as a reduction to retained earnings in the amount of $1.6 million, net of tax, to reflect the impact of this measurement date change. Also on January 1, 2008, we recorded $0.8 million relating to three months of amortization for transition obligations, prior service costs, and prior gains and losses within accumulated other comprehensive income.2012 Form 10-K

100

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

Pension Obligation and Funded Status
Year Ended December 31 2009 2008
Millions
Accumulated Benefit Obligation $435.9 $406.6

Change in Benefit Obligation
Obligation, Beginning of Year $440.4 $421.9
Service Cost 5.7 7.3
Interest Cost 26.2 31.8
Actuarial Loss (Gain) 14.6 3.2
Benefits Paid (25.5) (29.9)
Participant Contributions 3.9 6.1
Obligation, End of Year $465.3 $440.4
Change in Plan Assets
Fair Value, Beginning of Year $273.7 $405.6
Actual Return on Plan Assets 41.6 (120.2)
Employer Contribution 37.8 18.2
Benefits Paid (25.5) (29.9)
Fair Value, End of Year $327.6 $273.7
Funded Status, End of Year $(137.7) $(166.7)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities $(0.9) $(0.9)
Noncurrent Liabilities $(136.8) $(165.8)

~~ALLETE 2009 Form 10-K~~

~~Note 16.~~

~~Pension and Other Postretirement Benefit Plans (Continued)~~



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

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(190.9)			$(164.0)

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

Unrecognized Pension Costs
Year Ended December 31 2009 2008
Millions
Net Loss $196.5 $193.2
Prior Service Cost 1.8 2.4
Transition Obligation – –
Total Unrecognized Pension Costs $198.3 $195.6



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

Components of Net Periodic Pension Expense
Year Ended December 31 2009 2008 2007
Millions
Service Cost $5.7 $5.8 $5.3
Interest Cost 26.2 25.4 23.4
Expected Return on Plan Assets (33.8) (32.5) (30.6)
Amortization of Loss 3.4 1.6 4.9
Amortization of Prior Service Costs 0.6 0.6 0.6
Net Pension Expense $2.1 $0.9 $3.6

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income and Regulatory Assets
Year Ended December 31 2009 2008
Millions
Net Loss (Gain) $6.8 $164.0
Amortization of Prior Service Costs (0.6) (0.6)
Amortization of Loss (Gain) (3.4) (1.6)
Total Recognized in Other Comprehensive Income and Regulatory Assets $2.8 $161.8

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 31 2009 2008
Millions
Projected Benefit Obligation $465.3 $440.4
Accumulated Benefit Obligation $435.9 $406.6
Fair Value of Plan Assets $327.6 $273.7



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

ALLETE ~~2009~~2012 Form 10-K

101

~~Note 16.~~

~~Pension and Other Postretirement Benefit Plans~~NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Postretirement Health and Life Obligation and Funded Status
Year Ended December 31 2009 2008
Millions
Change in Benefit Obligation
Obligation, Beginning of Year $166.9 $153.7
Service Cost 4.1 5.0
Interest Cost 10.0 11.7
Actuarial Loss 18.4 4.0
Participant Contributions 1.7 2.0
Plan Amendments (1.3) –
Benefits Paid (7.7) (9.5)
Obligation, End of Year $192.1 $166.9
Change in Plan Assets
Fair Value, Beginning of Year $78.6 $90.9
Actual Return on Plan Assets 13.9 (25.2)
Employer Contribution 9.9 20.3
Participant Contributions 1.6 1.9
Benefits Paid (7.6) (9.3)
Fair Value, End of Year $96.4 $78.6
Funded Status, End of Year $(95.7) $(88.3)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:

Current Liabilities $(0.8) $(0.7)
Noncurrent Liabilities $(94.8) $(87.6)



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



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



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

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(0.8)			$(0.9)
Non-Current Liabilities	$(37.0)			$(88.7)

According to the accounting ~~guidance~~standards for ~~Retirement Benefits~~retirement benefits, only assets in the VEBAs are treated as plan assets in the above table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had ~~$18.2~~$22.1 million in irrevocable grantor trusts is included in Other Investments on our ~~consolidated balance sheet~~Consolidated Balance Sheet at December 31, ~~2009 ($14.1~~2012 ($20.3 million at December 31, ~~2008)~~2011).

ALLETE 2012 Form 10-K

102

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

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

Unrecognized Postretirement Health and Life Costs
Year Ended December 31 2009 2008
Millions
Net Loss $69.6 $59.2
Prior Service Cost (1.3) –
Transition Obligation 6.9 9.4
Total Unrecognized Postretirement Health and Life Costs $75.2 $68.6



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



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

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31 2009 2008 2007
Millions
Service Cost $4.1 $4.0 $4.2
Interest Cost 10.0 9.4 7.8
Expected Return on Plan Assets (8.3) (7.2) (6.5)
Amortization of Loss 2.5 1.4 1.0
Amortization of Transition Obligation 2.5 2.5 2.4
Net Postretirement Health and Life Expense $10.8 $10.1 $8.9



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



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

ALLETE ~~2009~~2012 Form 10-K

103

~~Note 16. Pension and Other Postretirement Benefit Plans~~NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31 2009 2008
Millions
Net Loss (Gain) $12.9 $38.3
Prior Service Cost (Credit) Arising During the Period (1.3) –
Amortization of Transition Obligation (2.5) (2.5)
Amortization of Loss (Gain) (2.5) (1.4)
Total Recognized in Other Comprehensive Income and Regulatory Assets $6.6 $34.4

Estimated Future Benefit Payments
Postretirement
Pension Health and Life
Millions
2010 $26.4 $7.5
2011 $26.9 $8.4
2012 $27.8 $9.2
2013 $28.8 $10.0
2014 $29.9 $10.9
Years 2015 – 2019 $165.0 $65.5

The pension and postretirement health and life costs recorded in ~~other~~regulatory long-term assets and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, ~~2010,~~2013, are as follows:

Postretirement
Pension Health and Life
Millions
Net Loss $6.6 $4.8
Prior Service Costs $0.5 $(0.1)
Transition Obligations – $2.5
Total Pension and Postretirement Health and Life Costs $7.1 $7.2



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

					Weighted-Average Assumptions Used to Determine Benefit Obligation
Year Ended December 31	2009	2008
As of December 31			2012	2011
Discount Rate	5.81%	6.12%
Pension			4.10%	4.54%
Postretirement Health and Life			4.13%	4.56%
Rate of Compensation Increase	4.3 – 4.6%	4.3 – 4.6%	4.3 - 4.6%
Health Care Trend Rates
Trend Rate	8.5%	9%	9.25%	10%
Ultimate Trend Rate	5%	5%	5%
Year Ultimate Trend Rate Effective	2017	2012	2019	2018

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31 2009 2008 2007
Discount Rate 6.12% 6.25% 5.75%
Expected Long-Term Return on Plan Assets
Pension 8.5% 9.0% 9.0%
Postretirement Health and Life 6.8 – 8.5% 7.2 – 9.0% 5.0 – 9.0%
Rate of Compensation Increase 4.3 – 4.6% 4.3 – 4.6% 4.3 – 4.6%

~~ALLETE 2009 Form 10-K~~

~~Note 16.~~

~~Pension and Other Postretirement Benefit Plans (Continued)~~



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

In establishing the expected long-term rate of return on plan assets, we ~~take into account~~determine the ~~actual~~ long-term historical performance of ~~our plan assets, the actual long-term historical performance~~each asset class, adjust these for ~~the type of securities we are invested in,~~current economic conditions, and ~~apply the historical performance~~ utilizing the target allocation of our plan assets, to forecast anthe expected long-term ~~return. Our expected~~ rate of ~~return is then selected after considering the results of each of those factors, in addition to considering the impact of current economic conditions, if applicable, on long-term historical returns.~~return.

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

						Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent		One Percent		One Percent
	Increase	Decrease	Increase		Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost	$2.1	$(1.8)		$2.0	$(1.6)
Effect on Postretirement Health and Life Obligation	$23.6	$(20.9)		$18.2	$(15.1)

ALLETE 2012 Form 10-K

104

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

													Actual Plan Asset Allocations
	Pension		Postretirement Health and Life (a)		Pension				Postretirement Health and Life (a)
	2009	2008	2009	2008	2012		2011		2012		2011
Equity Securities	53%	46%	54%	47%	54	%	52	%	56	%	51	%
Debt Securities	28%	32%	38%	40%	28	%	27	%	35	%	39	%
Private Equity					13	%	16	%	9	%	10	%
Real Estate	5%	6%	–	–	5	%	5	%	—		—
Private Equity	14%	16%	8%	9%
Cash	–	–	–	4%
	100%	100%	100%	100%	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

~~Pension plan equity securities included $9.9 million, or 3.0 percent,~~There were no shares of ALLETE common stock included in pension plan equity securities at December 31, ~~2009 (none at December 31, 2008)~~2012 ($20.0 million, approximately 0.5 million shares, in 2011).

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

Plan Asset Target Allocations
Postretirement
Pension
Health and Life (a)
Equity Securities 50% 48%
Debt Securities 30% 34%
Real Estate 10% 9%
Private Equity 10% 9%
100% 100%



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

~~(a)~~


(a)	Includes VEBAs and irrevocable grantor trusts.

Fair Value

~~ALLETE 2009 Form 10-K~~

~~Note 16.~~

~~Pension and Other Postretirement Benefit Plans (Continued)~~

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

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

ALLETE 2012 Form 10-K

105

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

Fair Value (Continued)

This category includes private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.

Pension Fair Value

At Fair Value as of December 31, 2009
Recurring Fair Value Measures Level 1 Level 2 Level 3 Total
Millions
Assets:
Equity Securities
     U.S. Large-cap (a)
$23.2 $27.5 $5.2 $55.9
     U.S. Mid-cap Growth (a)
8.9 10.6 2.0 21.5
     U.S. Small-cap (a)
8.6 10.1 1.9 20.6
     International – 66.4 – 66.4
     ALLETE 9.9 – – 9.9
Debt Securities:
     Mutual Funds 32.0 – – 32.0
     Fixed Income – 59.3 – 59.3
Other Types of Investments:
     Private Equity Funds – – 44.7 44.7
Real Estate – – 17.3 17.3
Total Fair Value of Assets $82.6 $173.9 $71.1 $327.6



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

~~(a) The underlying investments classified under U.S. Equity Securities represent Money Market Funds~~

(a)

The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and ~~U.S. Government Bonds (Level 1), Hedge Funds (Level 2), and Auction Rate Securities (Level 3), which are combined with futures, which~~ settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.



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

ALLETE 2012 Form 10-K

106

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

Fair Value (Continued)



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

(a)

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



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

Recurring Fair Value Measures Equity Securities
Activity in Level 3 (Auction Rate Securities) Private Equity Funds Real Estate
Millions
Balance as of December 31, 2008 $10.2 $43.2 $17.0
Actual Return on Plan Assets 0.1 (8.7) (8.6)
Purchases, sales, and settlements, net (1.1) 10.2 8.9
Balance as of December 31, 2009 $9.1 $44.7 $17.3

ALLETE ~~2009~~2012 Form 10-K

107

~~Note 16. Pension and Other Postretirement Benefit Plans~~NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Postretirement Health and Life Fair Value

At Fair Value as of December 31, 2009
Recurring Fair Value Measures Level 1 Level 2 Level 3 Total
Millions
Assets:
Equity Securities
     U.S. Large-cap $13.4 – – $13.4
     U.S. Mid-cap Growth 9.0 – – 9.0
     U.S. Small-cap 6.3 – – 6.3
     International 21.4 – – 21.4
Debt Securities:
     Mutual Funds 5.5 – – 5.5
     Fixed Income – $31.4 – 31.4
Other Types of Investments:
     Private Equity Funds – – $9.4 9.4
Total Fair Value of Assets $55.6 $31.4 $9.4 $96.4



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


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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, ~~2008~~2011		$~~7.9~~14.0
Actual Return on Plan Assets	~~(1.1)~~0.2
Purchases, sales, and settlements, net	~~2.6~~(0.7		)
Balance as of December 31, ~~2009~~2012		$~~9.4~~13.5



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


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

ALLETE 2012 Form 10-K

108

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

Fair Value (Continued)



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

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) ~~provides~~provide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health ~~benefits that include~~benefit, including a prescription drug ~~benefits,~~benefit, which ~~qualify~~qualifies us for ~~the~~a federal subsidy under the Act. The ~~expected reimbursement for Medicare health subsidies reduced our after-tax postretirement medical expense~~federal subsidy is reflected in the premiums charged to us by ~~$2.0 million for 2009 ($1.2 million for 2008; $2.3 million in 2007). In 2005 we enrolled with~~ the ~~Centers for Medicare and Medicaid Services’ (CMS) and began recovering the subsidy in 2007. We received a reimbursement of $0.6 million in 2009 and $0.3 million in 2007.~~insurance company.

~~Note 17.~~

~~Employee Stock and Incentive Plans~~

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor a leveraged ~~employee stock ownership plan (ESOP)~~ESOP within the RSOP. AsEligible employees may contribute to the RSOP plan as of their date of ~~hire, all employees of ALLETE, SWL&P and Minnesota Power Affiliate Resources are eligible to contribute to the plan.~~ hire. In 1990, the ESOP issued a ~~$75~~$75.0 million note (term not to exceed 25 years at 10.25 percent) to ususe as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our newly issued common stock. The note was refinanced in 2006 at 6 percent. We make annual contributions to the ESOP equal to the ESOP’s debt service less available dividends received by the ESOP. The majority of dividends received by the ESOP are used to pay debt service, with the balance distributed to participants. The ESOP shares were initially pledged as collateral for ~~its~~the debt. As the debt is repaid, shares are released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares are released from collateral, we report compensation expense equal to the current market price of the shares less dividends on allocated shares. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings; available dividends on unallocated ESOP shares are recorded as a reduction of debt and accrued interest. ESOP compensation expense was ~~$6.5~~$7.7 million in ~~2009 ($10.1~~2012 ($7.4 million in ~~2008; $9.2~~2011; $7.1 million in ~~2007)~~2010).

~~ALLETE 2009 Form 10-K~~

~~Note 17.~~

~~Employee Stock and Incentive Plans (Continued)~~

According to the accounting ~~guidance~~standards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered 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 2009 2008 2007
Millions
ESOP Shares
Allocated 2.2 2.0 1.8
Unallocated 1.5 1.9 2.2
Total 3.7 3.9 4.0
Fair Value of Unallocated Shares $49.0 $61.3 $87.1



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

Stock-Based Compensation.Stock Incentive Plan.Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, stock appreciation rights and other awards. There are ~~1.4~~1.2 million shares of common stock reserved for issuance under the Executive Plan, with 0.6 million of these shares available for issuance as of December 31, ~~2009.~~2012.

We had a Director Long-Term Stock Incentive Plan (Director Plan) which expired on January 1, 2006. No grants have been made since 2003 under the Director Plan. ~~Approximately 3,879~~The 1,293 remaining options outstanding at December 31, 2011, were exercised during 2012. There were no options outstanding under the Director Plan at December 31, ~~2009.~~2012.

ALLETE 2012 Form 10-K

109

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

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

Non-Qualified Stock Options. ~~The~~These options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to three months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are ~~cancelled~~canceled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is retirement eligible.

~~In 2009, no stock~~ Stock options ~~were~~have not been granted under our Executive Long-Term Incentive Compensation Plan. The following assumptions were used in determining the fair value of stock options granted during 2008 and 2007, respectively, under the Black-Scholes option-pricing model:

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

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

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

~~ALLETE 2009 Form 10-K~~

~~Note 17.~~

~~Employee Stock and Incentive Plans (Continued)~~

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

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

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

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

Share-Based Compensation Expense
Year Ended December 31 2009 2008 2007
Millions
Stock Options $0.3 $0.7 $0.8
Performance Shares 1.5 1.1 1.0
Restricted Stock Units 0.3 – –
Total Share-Based Compensation Expense $2.1 $1.8 $1.8
Income Tax Benefit $0.8 $0.7 $0.7



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

ALLETE 2012 Form 10-K

110

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized stock-based compensation costs at December 31, ~~2009, 2008,~~2012, 2011, or ~~2007.~~2010.

As of December 31, ~~2009,~~2012, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our ~~statements~~Consolidated Statements of ~~income~~Income was ~~$1.8~~$1.3 million and ~~$0.5~~$0.6 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years for performance share awards and ~~2.0~~1.7 years ~~respectively.~~ for restricted stock units.

Non-Qualified Stock Options.The following table presents information regarding our outstanding stock options as of December 31, ~~2009.~~2012.

Weighted-Average
Weighted-Average Aggregate Remaining
Number of Exercise Intrinsic Contractual
Options Price Value Term
Millions
Outstanding as of December 31, 2008 672,419 $39.99 $(5.2) 6.9 years
Granted (a)
– –
Exercised 4,508 $18.85
Forfeited 21,676 $42.62
Outstanding as of December 31, 2009 646,235 $40.05 $(4.8) 5.9 years
Exercisable as of December 31, 2009 512,743 $37.34 $(3.7) 5.4 years



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


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

~~(a) Restricted~~Cash received from non-qualified stock ~~units were issued~~options exercised was less than $0.1 million in ~~2009, instead of stock options.~~

~~The weighted-average grant-date fair value of options was $6.18 for 2009 ($6.18 for 2008; $6.92 for 2007)~~2012. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was ~~$0.1~~$0.3 million during ~~2009 ($0.2~~2012 ($0.5 million in ~~2008; $0.4~~2011; $0.3 million in ~~2007)~~2010).

~~ALLETE 2009 Form 10-K~~

~~Note 17.~~

~~Employee Stock and Incentive Plans (Continued)~~

As of December 31, 2009, options outstanding consisted of 0.1 million with exercise prices ranging from $18.85 to $29.79, 0.4 million with exercise prices ranging from $37.76 to $41.35 and 0.2 million with exercise prices ranging from $44.15 to $48.65. The options with exercise prices ranging from $18.85 to $29.79 have an average remaining contractual life of 2.1 years; all were exercisable as of December 31, 2009, at a weighted average price of $27.34. The options with exercise prices ranging from $37.76 to $41.35 have an average remaining contractual life of 6.3 years; 0.2 million were exercisable as of December 31, 2009, at a weighted average price of $39.47. The options with exercise prices ranging from $44.15 to $48.65 have an average remaining contractual life of 6.5 years; less than 0.2 million were exercisable as of December 31, 2009, at a weighted average price of $46.36.



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

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, ~~2009.~~2012.

Weighted-Average
Number of Grant Date
Shares Fair Value
Non-vested as of December 31, 2008 79,238 $47.94
Granted 69,800 $35.06
Unearned Grant Award (24,615) $41.97
Forfeited (2,598) $38.78
Non-vested as of December 31, 2009 121,825 $41.96



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

(a) Shares granted includes accrued dividends.

ALLETE 2012 Form 10-K

111

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

~~Less than 0.1 million~~There were 33,525 and 41,332 performance ~~share were~~shares granted in ~~February 2009~~January 2012 and 2013, for the three-year performance ~~period~~periods ending in ~~2011.~~2014 and 2015, respectively. The ultimate issuance is contingent upon the attainment of certain future ~~performance~~market goals of ALLETE during the performance periods. The grant date fair value of the performance ~~share awards~~shares granted was ~~$2.2 million.~~$1.5 million and $2.2 million, respectively.

NoThere were 41,009 and 18,605 performance shares ~~were~~ awarded in February ~~2010~~2012 and 2013, for the ~~three-year~~three-year performance ~~period~~periods ending in ~~2009, as performance targets were not met. However, in accordance with~~2011 and 2012, respectively. The grant date fair value of the ~~accounting guidance for stock compensation, no compensation expense previously recognized in connection with those grants will be reversed.~~shares awarded was $1.4 million and $0.7 million, respectively.

Restricted Stock Units. The following table presents information regarding our ~~non-vested~~available restricted stock units as of December 31, ~~2009.~~2012.

Weighted-Average
Number of Grant Date
Shares Fair Value
Non-vested as of December 31, 2008 – –
Granted 30,465 $29.41
Forfeited (1,482) $29.41
Non-vested as of December 31, 2009 28,983 $29.41



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

(a) Shares granted includes accrued dividends.

~~Less than 0.1 million~~There were 16,355 and 19,193 restricted stock units ~~were~~ granted in ~~February 2009~~January 2012 and 2013, for the vesting ~~period~~periods ending in ~~2011.~~2014 and 2015, respectively. The grant date fair value of the restricted stock ~~unit awards~~units granted was ~~$0.9 million.~~$0.7 million and $0.8 million, respectively.

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

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

~~ALLETE 2009 Form 10-K~~

~~Note 18.~~

~~Quarterly Financial Data (Unaudited)~~

NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

Quarter Ended Mar. 31 Jun. 30 Sept. 30 Dec. 31
Millions Except Earnings Per Share
2009
Operating Revenue $199.6 $164.7 $178.8 $216.0
Operating Income $31.1 $15.7 $25.4 $33.8
Net Income Attributable to ALLETE $16.9 $9.4 $16.0 $18.7
Earnings Per Share of Common Stock
Basic $0.55 $0.29 $0.49 $0.56
Diluted $0.55 $0.29 $0.49 $0.56
2008
Operating Revenue $213.4 $189.8 $201.7 $196.1
Operating Income $31.3 $17.5 $33.2 $39.8
Net Income Attributable to ALLETE $23.6 $10.7 $24.7 $23.5
Earnings Per Share of Common Stock
Basic $0.82 $0.37 $0.85 $0.78
Diluted $0.82 $0.37 $0.85 $0.78



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

ALLETE ~~2009~~2012 Form 10-K

112

Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves



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

Balance at Additions Deductions Balance at
Beginning Charged Other from End of
Year Ended December 31 of Year to Income Changes
Reserves (a)
Period
Millions
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2007  Trade Accounts Receivable $1.1 $1.0 – $1.1 $1.0
Finance Receivables – Long-Term 0.2 – – – 0.2
2008  Trade Accounts Receivable 1.0 1.0 – 1.3 0.7
Finance Receivables – Long-Term 0.2 – – 0.1 0.1
2009  Trade Accounts Receivable 0.7 1.3 – 1.1 0.9
Finance Receivables – Long-Term 0.1 0.3 – – 0.4
Deferred Asset Valuation Allowance
2007  Deferred Tax Assets 3.6 (0.3) – – 3.3
2008  Deferred Tax Assets 3.3 (2.9) – – 0.4
2009  Deferred Tax Assets 0.4 (0.1) – – 0.3


(a)	Includes uncollectible accounts written off.

ALLETE ~~2009~~2012 Form 10-K

113



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



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

~~Definitions~~
	3
Definitions			4

~~Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995~~ Forward-Looking Statements			5 6

Part I
Item 1.	Business		6 7
	Regulated Operations		6 7
		Electric Sales / Customers	6 7
		Power Supply	9 11
		Transmission and Distribution	11 14
		Investment in ATC	11 14
		Properties	11 15
		Regulatory Matters	12 15
		Regional Organizations	15 18
		Minnesota Legislation	15 18
		Competition	15 19
		Franchises	16 19
	Investments and Other		16 19
		BNI Coal	16 19
		ALLETE Properties	16 20
		~~Non-Rate Base Generation~~ ALLETE Clean Energy	17 20
		~~Other.~~ Non-Rate Base Generation	17 20
	Environmental Matters		17 21
	Employees		21 25
	Availability of Information		21 25
	Executive Officers of the Registrant		22 26
Item 1A.	Risk Factors		23 27
Item 1B.	Unresolved Staff Comments		26 31
Item 2.	Properties		26 31
Item 3.	Legal Proceedings		26 31
Item 4.	~~Submission of Matters to a Vote of Security Holders~~ Mine Safety Disclosures		26 31
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		2732
Item 6.	Selected Financial Data		28 33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29 34
	Overview		29 34
	~~2009~~ 2012 Compared to ~~2008.~~2011		30 35
	~~2008~~ 2011 Compared to ~~2007~~2010		32 37
	Critical Accounting ~~Estimates~~Policies		34 39
	Outlook		35 41
	Liquidity and Capital Resources		42 47
	Capital Requirements		46 50
	Environmental and Other Matters		46 51
	Market Risk		46 51
	~~New~~ Recently Adopted Accounting Standards		48 52
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		48 52
Item 8.	Financial Statements and Supplementary Data		48 52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		48 52
Item 9A.	Controls and Procedures		48 52
Item 9B.	Other Information		49 53



Part III
Item 10.	Directors, Executive Officers and Corporate Governance	50 54
Item 11.	Executive Compensation	50 54
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50 54
Item 13.	Certain Relationships and Related Transactions, and Director Independence	50 55
Item 14.	Principal Accounting Fees and Services	50 55
Part IV
Item 15.	Exhibits and Financial Statement Schedules	51 56

Signatures		55 62

Consolidated Financial Statements		58 65



Abbreviation or Acronym	Term
~~AICPA~~AC	~~American Institute of Certified Public Accountants~~
~~ALLETE~~	~~ALLETE, Inc.~~
~~ALLETE Properties~~	~~ALLETE Properties, LLC and its subsidiaries~~Alternating Current
AFUDC	Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods
~~AREA~~ALLETE	~~Arrowhead Regional Emission Abatement~~ALLETE, Inc.
ALLETE Clean Energy	ALLETE Clean Energy, Inc.
ALLETE Properties	ALLETE Properties, LLC and its subsidiaries
ArcelorMittal	ArcelorMittal USA, Inc.
ARS	Auction Rate Securities
ATC	American Transmission Company LLC
Basin	Basin Electric Power Cooperative
Bison I1	Bison I1 Wind Project
Bison 2	Bison 2 Wind Project
Bison 3	Bison 3 Wind Project
Bison	Bison Wind Energy Center
BNI Coal	BNI Coal, Ltd.
~~BNSF~~	~~Burlington Northern Santa Fe Railway Company~~
Boswell	Boswell Energy Center
~~Boswell NO~~X ~~Reduction Plan~~ CAIR	NOX ~~emission reductions from Boswell Units 1, 2, and 4~~ Clean Air Interstate Rule
CO₂	Carbon Dioxide
Company	ALLETE, Inc. and its subsidiaries
CSAPR	Cross-State Air Pollution Rule
DC	Direct Current
~~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
~~FTR~~	~~Financial Transmission Rights~~
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
~~Heating Degree Days~~Hibbard	~~Measure of the extent to which the average daily temperature is below 65 degrees Fahrenheit, increasing demand for heating~~Hibbard Renewable Energy Center
IBEW ~~Local 31~~	International Brotherhood of Electrical Workers ~~Local 31~~
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
Item___	Item___of this Form 10-K
kV	Kilovolt(s)
Laskin	Laskin Energy Center
LIBOR	London Inter Bank Offered Rate
MACT	Maximum Achievable Control Technology
Magnetation	Magnetation, Inc.
Manitoba Hydro	Manitoba Hydro-Electric Board
MATS	Mercury and Air Toxics Standards
MBtu	Million British thermal units
Medicare Part D	Medicare Part D provision of the Patient Protection and Affordable Care Act of 2010


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


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



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~~NAAQS	~~NextEra Energy Resources, LLC~~National Ambient Air Quality Standards
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
NOL	Net Operating Loss
Non-residential	Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NO₂	Nitrogen Dioxide
NO_X	Nitrogen Oxides
Note ___	Note ___ to the consolidated financial statements in this Form 10-K
NPDES	National Pollutant Discharge Elimination System
NYSE	New York Stock Exchange
~~OES~~	~~Minnesota Office of Energy Security~~
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.~~Corporation
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PSCW	Public Service Commission of Wisconsin
~~PUHCA 2005~~	~~Public Utility Holding Company Act of 2005~~
Rainy River Energy	Rainy River Energy Corporation - Wisconsin
RSOP	Retirement Savings and Stock Ownership Plan
SEC	Securities and Exchange Commission
SO₂	Sulfur Dioxide
Square Butte	Square Butte Electric Cooperative
Standard & Poor’s	Standard & Poor’s Ratings Services ~~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~~U.S.	~~Wisconsin Department~~United States of ~~Natural Resources~~America
USS Corporation	United States Steel Corporation

·	~~our ability to successfully implement our strategic objectives;~~
·	prevailing governmental policies, regulatory actions, and legislation including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, and various local and county regulators, and city administrators, about allowed rates of return, financings, industry and rate structure, acquisition and disposal of assets and facilities, real estate development, operation and construction of plant facilities, recovery of purchased power, capital investments and other expenses, present or prospective wholesale and retail competition (including but not limited to transmission costs), zoning and permitting of land held for resale and environmental matters;
·	~~our ability to manage expansion and integrate acquisitions;~~
·	~~the potential impacts of climate change and future regulation to restrict the emissions of GHG on our Regulated Operations~~;
·	~~effects of restructuring initiatives in the electric industry;~~
·	~~economic and geographic factors, including political and economic risks;~~
·	~~changes in and compliance with laws and regulations;~~
·	~~weather conditions;~~
·	~~natural disasters and pandemic diseases;~~
·	~~war and acts of terrorism;~~
·	~~wholesale power market conditions;~~
·	~~population growth rates and demographic patterns;~~
·	~~effects of competition, including competition for retail and wholesale customers;~~
·	~~changes in the real estate market;~~
·	~~pricing and transportation of commodities;~~
·	~~changes in tax rates or policies or in rates of inflation;~~
·	~~project delays or changes in project costs;~~
·	~~availability and management of construction materials and skilled construction labor for capital projects;~~
·	~~changes in operating expenses~~, ~~capital and land development expenditures;~~
·	~~global and domestic economic conditions affecting us or our customers;~~
·	~~our ability to access capital markets and bank financing;~~
·	~~changes in interest rates and the performance of the financial markets;~~
·	~~our ability to replace a mature workforce and retain qualified, skilled and experienced personnel; and~~
·	~~the outcome of legal and administrative proceedings (whether civil or criminal) and settlements that affect the business and profitability of ALLETE.~~

Regulated Utility Electric Sales
Year Ended December 31	2009	%	2008	%	2007	%
Millions of Kilowatt-hours
Retail and Municipals
Residential	1,164	10	1,172	9	1,141	9
Commercial	1,420	12	1,454	12	1,456	11
Industrial	4,475	37	7,192	57	7,054	55
Municipals (FERC rate regulated)	992	8	1,002	8	1,009	8
Total Retail and Municipals	8,051	67	10,820	86	10,660	83
Other Power Suppliers	4,056	33	1,800	14	2,157	17
Total Regulated Utility Electric Sales	12,107	100	12,620	100	12,817	100


Industrial Customer Electric Sales	Industrial Customer Electric Sales
Year Ended December 31	2009	%	2008	%	2007	%	2012	%	2011	%	2010	%
Millions of Kilowatt-hours
Taconite Producers	2,124	47	4,579	64	4,408	62
Taconite/Iron Concentrate							4,968	66	4,874	66	4,324	64
Paper, Pulp and Wood Products	1,454	33	1,567	22	1,613	23	1,571	21	1,560	21	1,573	23
Pipelines	504	11	582	8	562	8
Other Industrial	393	9	464	6	471	7
	4,475	100	7,192	100	7,054	100
Pipelines and Other Industrial							963	13	931	13	907	13
Total Industrial Customer Electric Sales							7,502	100	7,365	100	6,804	100



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



Customer~~(a)~~	Industry	Location	Ownership	Earliest Termination Date
~~Hibbing Taconite Co.~~	~~Taconite~~	~~Hibbing, MN~~	~~62.3% ArcelorMittal USA Inc.~~ ~~23% Cliffs Natural Resources Inc.~~ ~~14.7% United States Steel Corporation~~	~~December 31, 2015~~
ArcelorMittal ~~USA~~ – Minorca Mine ~~(b)~~(a)	Taconite	Virginia, MN	ArcelorMittal ~~USA Inc.~~	~~February 28, 2014~~January 31, 2017
Hibbing Taconite Co. (a)	Taconite	Hibbing, MN	62.3% ArcelorMittal 23.0% Cliffs Natural Resources Inc. 14.7% USS Corporation	January 31, 2017
United ~~States Steel~~Taconite LLC (a)	Taconite	Eveleth, MN	Cliffs Natural Resources Inc.	January 31, 2017
USS Corporation (USS – Minnesota Ore) ~~(b,c)~~(a,b)	Taconite	Mt. Iron, MN and Keewatin, MN	~~United States Steel~~USS Corporation	~~February 28, 2014~~
~~United Taconite LLC~~	~~Taconite~~	~~Eveleth, MN~~	~~Cliffs Natural Resources Inc.~~	~~December~~January 31, ~~2015~~2017
Mesabi Nugget ~~Delaware, LLC~~	Iron Nugget	Hoyt Lakes, MN	80% Steel Dynamics, ~~Inc (80%)~~Inc. 20% Kobe Steel USA ~~(20%)~~	December 31, 2017
~~UPM, Blandin Paper Mill~~ ~~(b)~~	~~Paper~~	~~Grand Rapids, MN~~	~~UPM-Kymmene Corporation~~	~~February 28, 2014~~
Boise White Paper, LLC	Paper	International Falls, MN	Boise Paper Holdings, LLC	~~December~~January 31, ~~2013~~2015
~~Sappi Cloquet LLC~~ UPM, Blandin Paper Mill (a)	Paper ~~and Pulp~~	~~Cloquet,~~Grand Rapids, MN	~~Sappi Limited~~UPM-Kymmene Corporation	~~February 28, 2014~~January 31, 2017
NewPage Corporation – Duluth ~~Mills~~ Mill ~~(b)~~(c)	Paper and Pulp	Duluth, MN	NewPage Corporation	~~February 28, 2014~~December 31, 2022
Sappi Cloquet LLC (a)	Paper and Pulp	Cloquet, MN	Sappi Limited	January 31, 2017

Regulated Utility Power Supply	Unit No.	Year Installed	Net Winter Capability	Year Ended December 31, 2009 Electric Requirements
			MW	MWh	%
Coal-Fired
Boswell Energy Center	1	1958	68
in Cohasset, MN	2	1960	67
	3	1973	352
	4	1980	429
			916	5,390,131	42.8%
Laskin Energy Center	1	1953	55
in Hoyt Lakes, MN	2	1953	51
			106	510,505	4.1
Taconite Harbor Energy Center	1	1957	75
in Schroeder, MN	2	1957	74
	3	1967	76
			225	1,058,263	8.4
Total Coal			1,247	6,958,899	55.3
Biomass/Coal/Natural Gas
Hibbard Renewable Energy Center
in Duluth, MN	3 & 4	1949, 1951	54	40,703	0.3

Cloquet Energy Center in Cloquet, MN	5	2001	22	19,340	0.2
Total Biomass/Coal/Natural Gas			76	60,043	0.5
Hydro
Group consisting of ten stations in MN	Various		109	434,541	3.5
Wind
Taconite Ridge in Mt. Iron, MN (a)	1-10	2008	4	56,255	0.4
Total Company Generation			1,436	7,509,738	59.7
Long-Term Purchased Power
Square Butte burns lignite coal near Center, ND				1,695,254	13.5
Wind – Oliver County, ND				361,624	2.9
Hydro – Manitoba Hydro in Winnipeg, MB, Canada				433,543	3.4
Total Long-Term Purchased Power				2,490,421	19.8

Other Purchased Power(b)				2,579,408	20.5
Total Purchased Power				5,069,829	40.3
Total			1,436	12,579,567	100.0%


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



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


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


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


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

Summary of Development Projects		Total	Residential	Non-residential

Summary of Development Projects (100% Owned)						Residential	Non-residential
Land Available-for-Sale	Ownership	Acres (a)	Units (b)	Sq. Ft. (b, c)	Acres (a)	Units (b)	Sq. Ft. (b,c)
Current Development Projects
Town Center	80%	854	2,264	2,238,400	965	2,485	2,246,200
Palm Coast Park	100%	3,143	3,154	3,555,000	3,888	3,554	3,096,800
Total Current Development Projects		3,997	5,418	5,793,400	4,853	6,039	5,343,000
Proposed Development Project

Planned Development Project
Ormond Crossings	100%	2,924	(d)	(d)	2,914	2,950	3,215,000
Other
Lake Swamp Wetland Mitigation Project	100%	3,034	(e)	(e)	3,044	(d)	(d)
Total of Development Projects		9,955	5,418	5,793,400	10,811	8,989	8,558,000


(a)	Acreage amounts are approximate and shown on a gross basis, including ~~wetlands and non-controlling interest.~~wetlands.


(b)	~~Estimated~~Units and ~~includes non-controlling interest.~~square footage are estimated. Density at build out may differ from these estimates.


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


(d)	A development order that was approved by the City of Ormond Beach is being replaced by a development agreement to facilitate development of Ormond Crossings as currently planned. At build-out, we expect the project to include 2,950 residential units, 4.87 million square feet of various types of non-residential space and public facilities.

Other Land Available-for-Sale (a)	Total	Mixed Use	Residential	Non-residential	Agricultural
Acres (b)
Other Land	1,277	394	113	267	503

~~Issue Date~~ ~~(on or about)~~	~~Maturity~~	~~Principal Amount~~	~~Coupon~~
~~February 17, 2010~~	~~April 15, 2021~~	~~$15 Million~~	~~4.85%~~
~~February 17, 2010~~	~~April 15, 2025~~	~~$30 Million~~	~~5.10%~~
~~February 17, 2010~~	~~April 15, 2040~~	~~$35 Million~~	~~6.00%~~

	Payments Due by Period
Contractual Obligations		Less than	1 to 3	4 to 5	After
As of December 31, 2009	Total	1 Year	Years	Years	5 Years
Millions
Long-Term Debt (a)	$1,172.1	$41.5	$196.6	$98.2	$835.8
Pension and Other Postretirement Benefit Plans	194.1	36.6	105.4	52.1	–
Operating Lease Obligations	89.1	8.8	26.4	15.8	38.1
Uncertain Tax Positions (b)	–	–	–	–	–
Unconditional Purchase Obligations	394.0	114.1	102.7	30.4	146.8
	$1,849.3	$201.0	$431.1	$196.5	$1,020.7


(a)	~~Includes interest and assumes variable interest rates in effect at December 31, 2009, remains constant through remaining term.~~



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

~~Unsecured Debt~~
~~Collier County Industrial Development Revenue Bonds – Fixed Rate~~	~~BBB~~	–

Capital Expenditures			2010	2011	2012	2013	2014	Total
Regulated Utility Operations
	Base and Other		$156	$82	$81	$82	$89	$490
	Current Cost Recovery (a)
		Environmental	2	–	–	–	–	2
		Renewable	81	66	–	–	–	147
		Transmission	5	21	27	42	13	108
		Generation	–	–	–	–	–	–
	Total Current Cost Recovery		88	87	27	42	13	257
Regulated Utility Capital Expenditures			244	169	108	124	102	747
Other			6	18	24	8	8	64
Total Capital Expenditures			$250	$187	$132	$132	$110	$811


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


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


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