Allete (ALE)

·

Regulated Utility includes retail and wholesale rate regulated electric, natural gas and water services in northeastern Minnesota and northwestern Wisconsin under the jurisdiction of state and federal regulatory authorities.

 

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Nonregulated Energy Operations includes our coal mining activities in North Dakota, approximately 50 MW of nonregulated generation and Minnesota land sales.

 

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Investment in ATC includes our equity ownership interest in ATC.

Real Estate includes our Florida real estate operations.

Other> includes our investments in emerging technologies, and earnings on cash and short-term investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2007, unless otherwise indicated. All subsidiaries are wholly owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

Year Ended December 31	2007	2006	2005
Consolidated Operating Revenue – Millions	$841.7	$767.1	$737.4
Percentage of Consolidated Operating Revenue
Regulated Utility	86	83	78
Nonregulated Energy Operations	8	9	16
Real Estate	6	8	6
	100%	100%	100%

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

Energy – Regulated Utility

Electric Sales / Customers

Minnesota Power provides regulated utility electric service in northeastern Minnesota to 141,000 retail customers and wholesale electric service to 16 municipalities. SWL&P provides regulated electric service, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (see Item 1 - Regulatory Matters.) In addition to serving residential, commercial and municipal electric needs, a high proportion of our electric sales are to large industrial customers.

Regulated Utility Electric Sales Year Ended December 31	2007	%	2006	%	2005	%
Millions of Kilowatthours
Retail and Municipals
Residential	1,141	9	1,100	9	1,102	10
Commercial	1,373	11	1,335	10	1,327	11
Industrial	7,054	55	7,206	56	7,130	61
Municipals and Other	1,092	8	990	8	956	8
	10,660	83	10,631	83	10,515	90
Other Power Suppliers (a)	2,157	17	2,153	17	1,142	10
	12,817	100	12,784	100	11,657	100

(a)	Effective January 1, 2006, Taconite Harbor was redirected from Nonregulated Energy Operations to Regulated Utility.

ALLETE 2007 Form 10-K

 

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Energy-Regulated Utility (Continued)

Industrial Customers

In 2007, our industrial customers represented 55 percent of total regulated utility kilowatthour sales. Our industrial customers are primarily in the taconite, paper, pulp, wood products and pipeline industries.

Industrial Customer Electric Sales Year Ended December 31			2007	%	2006	%	2005	%
Millions of Kilowatthours
Taconite Producers			4,408	62	4,517	63	4,558	64
Paper, Pulp and Wood Products			1,613	23	1,689	23	1,623	23
Pipelines			562	8	550	8	480	7
Other Industrial			471	7	450	6	469	6
			7,054	100	7,206	100	7,130	100

Approximately 60 percent of the ore consumed by integrated steel facilities in the United States originates from six taconite customers of Minnesota Power. Taconite, an iron-bearing rock of relatively low iron content that is abundantly available in Minnesota, is an important domestic source of raw material for the steel industry. Taconite processing plants use large quantities of electric power to grind the iron-bearing rock, and agglomerate and pelletize the iron particles into taconite pellets. Strong worldwide steel demand, driven largely by extensive infrastructure development in China, has resulted in very robust world iron ore demand and steel pricing. This globalization of demand has positively impacted Minnesota taconite producers. With the exception of short-term production curtailments at two taconite plants, our taconite customers operated at maximum production levels in 2007. Annual taconite production in Minnesota was 39 million tons in 2007 (40 million tons in 2006 and 41 million tons in 2005) and it is estimated that it will be 41.5 million tons in 2008. An 800,000 ton per year expansion at Cleveland Cliffs’ Northshore taconite facility is expected to be completed in April 2008, contributing to the expected increased production. It is expected that throughout 2008, Minnesota taconite producers will remain in a strong competitive position due to the strength of the world steel industry and their efficiency of production.

In addition to serving the taconite industry, Minnesota Power also serves a number of customers in the paper, pulp and wood products industry. In total, we serve four major paper and pulp mills directly and one paper mill indirectly by providing wholesale service to the retail provider of the mill. Minnesota Power also serves four wood products manufacturers. In 2007, approximately 90 percent of our revenue from this industry sector came from the paper and pulp producers, and 10 percent came from the wood products customers.

Minnesota Power’s paper and pulp customers ran at, or very near, full capacity in 2007 despite the fact that the industry continued to face high fiber, chemical and energy costs as well as competition from exports in certain grades of paper products. Minnesota Power’s customers benefited from the temporary or permanent idling of capacity both in North America at mills other than those served by Minnesota Power and the idling of capacity in Europe, as well as from the strength of the Canadian dollar and the Euro which has reduced imports both from Canada and Europe. Our wood products customers ran at reduced capacity levels, and two facilities were indefinitely idled due to the decreased number of new housing starts, a resultant declining demand and pricing for their products. One of the idled facilities was down for all of 2007 while another was idled during the last quarter of 2007.

The pipeline industry is the third key industrial segment served by Minnesota Power with services provided to two crude oil pipelines and one refinery. These customers have a common reliance on the importation of Canadian crude oil. After near capacity operation in 2006 and 2007, both pipeline operators are executing expansion plans to transport newly developed Western Canadian crude oil reserves (Alberta Oil Sands) to United States markets. Access to traditional Midwest markets is being expanded to Southern markets as the Canadian supply is displacing domestic production and deliveries imported from the Gulf Coast.

ALLETE 2007 Form 10-K

 

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Energy-Regulated Utility (Continued)

Large Power Customer Contracts.> Minnesota Power has large power customer contracts with 12 customers (Large Power Customers), 11 of which require 10 MW or more of generating capacity and one that requires at least 8 MW of generating capacity. Large Power Customers consist of five taconite producers, four paper and pulp mills, two pipeline companies and one manufacturer.

Large Power Customer contracts require Minnesota Power to have a certain amount of generating capacity available. (See Minimum Revenue and Demand Under Contract table below.) In turn, each Large Power Customer is required to pay a minimum monthly demand charge that covers the fixed costs associated with having this capacity available to serve the customer, including a return on common equity. Most contracts allow customers to establish the level of megawatts subject to a demand charge on a biannual (power pool season) or four-month basis and require that a portion of their megawatt needs be committed on a take-or-pay basis for at least a portion of the agreement. In addition to the demand charge, each Large Power Customer is billed an energy charge for each kilowatthour used that recovers the variable costs incurred in generating electricity. Six of the Large Power Customers have interruptible service for a portion of their needs, which provides a discounted demand rate and energy priced at Minnesota Power’s incremental cost after serving all firm power obligations. Minnesota Power also provides incremental production service for customer demand levels above the contractual take-or-pay levels. There is no demand charge for this service and energy is priced at an increment above Minnesota Power’s cost. Incremental production service is interruptible.

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

Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates. The customers receive estimated bills based on Minnesota Power’s prediction of the customer’s energy usage, forecasted energy prices and fuel clause adjustment estimates. Minnesota Power’s five taconite-producing Large Power Customers have generally predictable energy usage on a week-to-week basis, which makes the variance between the estimated usage and actual usage small. Taconite-producing Large Power Customers subject to weekly billings receive interest on the money paid to Minnesota Power within the billing cycle.

Minimum Revenue and Demand Under Contract As of February 1, 2008	Minimum Annual Demand Revenue (a,b)	Monthly Megawatts
2008	$64.1 million	401
2009	$27.5 million	154
2010	$25.5 million	148
2011	$25.3 million	148
2012	$15.6 million	88

(a)

Based on past experience, we believe revenue from our Large Power Customers will be substantially in excess of the minimum contract amounts. For example, in our 2006 Form 10-K we stated that 2007 minimum annual revenue demand from these Large Power Customers would be $62.5 million. Actual 2007 demand revenue from these Large Power Customers was $118.7 million.

(b)	Although several contracts have a feature that allows demand to go to zero after a two-year advance notice of a permanent closure, this minimum revenue summary does not reflect this occurrence happening in the forecasted period because we believe it is unlikely.

ALLETE 2007 Form 10-K

 

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Energy–Regulated Utility (Continued)

Contract Status for Minnesota Power Large Power Customers

As of February 1, 2008

Customer	Industry	Location	Ownership	Earliest Termination Date
Hibbing Taconite Co. (a)	Taconite	Hibbing, MN	62.3% Mittal Steel USA Inc. 23% Cleveland-Cliffs Inc 14.7% United States Steel (USS)	February 29, 2012
ArcelorMittal USA – Minorca Mine	Taconite	Virginia, MN	ArcelorMittal USA Inc.	December 31, 2013
United States Steel Corporation (USS) Minntac	Taconite	Mt. Iron, MN	USS	October 31, 2014
USS Keewatin Taconite	Taconite	Keewatin, MN	USS	October 31, 2014
United Taconite LLC (a)	Taconite	Eveleth, MN	70% Cleveland-Cliffs Inc 30% Laiwu Steel Group	February 29, 2012
UPM, Blandin Paper Mill (a)	Paper	Grand Rapids, MN	UPM-Kymmene Corporation	February 29, 2012
Boise White Paper, LLC (b)	Paper	International Falls, MN	Madison Dearborn Partnership	February 28, 2009
Sappi Cloquet LLC (a)	Paper	Cloquet, MN	Sappi Limited	February 29, 2012
NewPage Corporation – Duluth Mills	Paper and Pulp	Duluth, MN	NewPage Corporation	August 31, 2013
USG Interiors, Inc. (b)	Manufacturer	Cloquet, MN	USG Corporation	February 28, 2009
Enbridge Energy Company, Limited Partnership (b)	Pipeline	Deer River, MN Floodwood, MN	Enbridge Energy Company, Limited Partnership	February 28, 2009
Minnesota Pipeline Company (b)	Pipeline	Staples, MN Little Falls, MN Park Rapids, MN	60% Koch Pipeline Co. L.P. 40% Marathon Ashland Petroleum LLC	February 28, 2009

(a)	The contract will terminate four years from the date of written notice from either Minnesota Power or the customer. No notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is February 29, 2012.

(b)	The contract will terminate one year from the date of written notice from either Minnesota Power or the customer. No notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is February 28, 2009.

ALLETE 2007 Form 10-K

 

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Energy–Regulated Utility (Continued)

Power Supply

In order to meet our customer’s electric requirements, we utilize a mix of Company generation and purchased power. The Company’s generation is primarily coal fired, but also includes approximately 115 MWs of hydro generation from ten hydro stations in Minnesota. Purchased power is made up of long–term power purchase agreements and market purchases. The following table reflects the Company’s generating capabilities and total electrical requirements as of December 31, 2007. Minnesota Power had an annual net peak load of 1,614 MW on July 30, 2007.

Regulated Utility Power Supply	Unit No.	Year Installed	Net Winter Capability	For the Year Ended December 31, 2007 Electric Requirements
			MW	MWh	%
Coal-Fired
Boswell Energy Center	1	1958	69
in Cohasset, MN	2	1960	69
	3	1973	350
	4	1980	429
			917	6,005,520	45.7%
Laskin Energy Center	1	1953	55
in Hoyt Lakes, MN	2	1953	54
			109	591,499	4.5
Taconite Harbor Energy Center	1, 2 & 3	1957, 1957
in Taconite Harbor, MN		1967	220	1,491,457	11.4
Total Coal			1,246	8,088,476	61.6
Purchased Steam
Hibbard Energy Center in Duluth, MN	3 & 4	1949, 1951	47	53,354	0.4
Hydro
Group consisting of ten stations in MN	Various		115	428,153	3.3
Total Company Generation			1,408	8,569,983	65.3
Long Term Purchased Power
Square Butte burns lignite coal near Center, ND			273	1,533,186	11.7
Wind – Oliver County, ND (a)			20	203,675	1.5
Total Long Term Purchased Power			293	1,736,861	13.2
Other Purchased Power – Net (b)			–	2,819,715	21.5
Total Purchased Power			293	4,556,576	34.7
Total			1,701	13,126,559	100.0%

(a)

The nameplate capacity of Oliver Wind I Energy Center is 50-MWs and 48-MWs for the Oliver Wind II Energy Center. The capacity reflected in the table is actual accredited capacity of the facility. Accredited capacity is the amount of net generating capability associated with the facility for which capacity credit may be obtained under applicable Mid-Continent Area Power Pool (MAPP) rules.

(b)	Includes short term market purchases in the MISO market and from other power suppliers.

Fuel>. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin coal region located in Montana and Wyoming. Coal consumption in 2007 for electric generation at Minnesota Power’s coal-fired generating stations was approximately 4.9 million tons. As of December 31, 2007, Minnesota Power had a coal inventory of about 922,000 tons. Of Minnesota Power’s primary coal supply agreements, one agreement extends through 2011, one extends through 2009, and one has an initial term expiring at the end of 2008. Under these agreements, Minnesota Power has the tonnage flexibility to procure 70 percent to 100 percent of its total coal requirements. In 2008, 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 market price and supply risk and to take advantage of favorable spot market prices. Minnesota Power continues to explore future coal supply options. We believe that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.

 

In 2001, Minnesota Power and Burlington Northern Santa Fe Railway Company (BNSF) entered into a long-term agreement under which BNSF transports all of Minnesota Power’s coal by unit train from the Powder River Basin directly to Minnesota Power’s generating facilities or to a designated interconnection point. Minnesota Power also has agreements with an affiliate of the Canadian National Railway and Midwest Energy Resources Company to transport coal from the BNSF interconnection point to certain Minnesota Power facilities.

 

ALLETE 2007 Form 10-K

 

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Energy–Regulated Utility (Continued)

Power Supply (Continued)

 

On January 24, 2008, we received a letter from BNSF alleging the Company defaulted on a material obligation under the Company’s Coal Transportation Agreement (CTA). In the notice, BNSF claimed Minnesota Power underpaid approximately $1.6 million for coal transportation services in 2006 and that failure to pay such amount plus interest within 60 days may result in BNSF’s termination of the CTA. We believe we do not owe the amount claimed, and that BNSF’s claims are wholly without merit. We intend to vigorously defend our position in this dispute.

 

Coal Delivered to Minnesota Power Year Ended December 31	2007	2006	2005
Average Price per Ton	$21.78	$20.19	$19.76
Average Price per MBtu	$1.20	$1.10	$1.08

The Square Butte generating unit operated by Minnkota Power burns North Dakota lignite coal supplied by BNI Coal in accordance with the terms of a contract that extends through 2026. Square Butte’s cost of lignite burned in 2007 was approximately $1.09 per MBtu. The lignite acreage that has been dedicated to Square Butte by BNI Coal is located on lands essentially all of which are under private control and presently leased by BNI Coal. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit.

Long Term Purchased Power>. Minnesota Power has contracts to purchase capacity and energy from various entities. The largest contract is with Square Butte. Under an agreement with Square Butte expiring at the end of 2026, Minnesota Power is currently entitled to approximately 55 percent (50 percent in 2009 and thereafter) of the output of a 455-MW coal-fired generating unit located near Center, North Dakota. (See Note 8.)

In December 2006, we began purchasing the output from a 50-MW wind facility, Oliver Wind I, located in North Dakota, under a 25-year power purchase agreement with an affiliate of FPL Energy.

In May 2007, the MPUC approved a second 25-year wind power purchase agreement to purchase an additional 48 MW of wind energy from Oliver Wind II, an expansion of Oliver Wind I located in North Dakota. The MPUC also allowed immediate cost recovery for associated transmission upgrades. In November 2007, Oliver Wind II became operational and we began purchasing the output from the 48-MW wind facility.

On May 11, 2007, the MPUC approved a 50-MW power purchase agreement between Minnesota Power and Manitoba Hydro from May 2009 through April 2015.

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 230 kV (605 miles), 161 kV (43 miles), 138 kV (129 miles), 115 kV (1,203 miles) and less than 115 kV (6,347 miles). We own and operate 170 substations with a total capacity of 9,586 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

Properties

We own office and service buildings, an energy control center, repair shops, and lease offices and storerooms in various localities. Substantially all of our electric plant is subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. Generally, we hold fee interest in our real properties subject only to the lien of the mortgages. Most of our electric lines are located on land not owned in fee, but are covered by appropriate easement rights or by necessary permits from governmental authorities. Wisconsin Public Power, Inc. (WPPI) owns 20 percent of Boswell Unit 4. WPPI has the right to use our transmission line facilities to transport its share of Boswell generation. (See Note 4.)

ALLETE 2007 Form 10-K

 

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Energy–Regulated Utility (Continued)

Regulatory Matters

We are subject to the jurisdiction of various regulatory authorities. The MPUC has regulatory authority over Minnesota Power’s service area in Minnesota, retail rates, retail services, issuance of securities and other matters. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for the sale of electricity for resale and transmission of electricity in interstate commerce and certain accounting and record-keeping practices. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas and water by SWL&P. The MPUC, FERC and PSCW had regulatory authority over 58 percent, 10 percent and 8 percent, respectively, of our 2007 consolidated operating revenue.

Electric Rates.> Minnesota Power has historically designed its electric service rates based on cost of service studies under which allocations are made to the various classes of customers. Nearly all retail sales include billing adjustment clauses, which adjust electric service rates for changes in the cost of fuel and purchased energy, recovery of current and deferred conservation improvement program expenditures and recovery of certain environmental and renewable expenditures.

Information published by the Edison Electric Institute (“Typical Bills and Average Rates Report – Summer 2007” and “Rankings – July 1, 2007”) ranked Minnesota Power as having the ninth lowest average retail rates out of 177 investor-owned utilities in the United States. We had the lowest rates in Minnesota and in the region consisting of Iowa, Kansas, Minnesota, Missouri, North Dakota, South Dakota and Wisconsin.

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

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

In August 2005, the Energy Policy Act of 2005 (EPAct 2005) was signed into law, which repealed PUHCA 1935 and enacted PUHCA 2005. PUHCA 2005 gives FERC certain authority over books and records of public utility holding companies and their affiliates. It also addresses FERC review and authorization of the allocation of costs for non-power goods, or administrative or management services when requested by a holding company system or state commission. In addition, EPAct 2005 directs the FERC to issue certain rules addressing electricity reliability, investment in energy infrastructure, fuel diversity for electric generation, promotion of energy efficiency and wise energy use. The FERC is currently in the process of implementing EPAct 2005. These include (among others):

·

rulemaking for long-term transmission rights;

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dockets pertaining to the development and certification of electric reliability organizations, including delegated authority to regional entities for proposing and enforcing reliability standards;

·

rules specifying the form of applications for federal construction permits to be issued in the exercise of federal backstop siting authority for transmission projects;

·

rulemaking requiring unregulated transmitting utilities to provide open access to their transmission systems;

·

various rulemakings regarding the consideration of merger applications under the revised Federal Power Act Section 203;

·

a U.S. Department of Energy study/report on the benefits of economic dispatch and a report on recommendations of regional joint boards that considered economic dispatch;

·

rulemaking to facilitate transmission market transparency; and

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the energy market manipulation rulemaking.

We continue to monitor FERC activity in these and other proceedings.

On December 28, 2007, we submitted a filing with the FERC seeking to increase electric rates for our wholesale customers. On February 8, 2008, the FERC approved our wholesale rate filing. Our wholesale customers consist of 16 municipalities in Minnesota and two private utilities in Wisconsin, including SWL&P. The FERC authorized an average 10 percent increase for wholesale municipal customers, a 12.5 percent increase for SWL&P, and an overall return on equity of 11.25 percent. The rate increase will go into effect on March 1, 2008, and on an annualized basis, the filing will generate approximately $7.5 million in additional revenue.

Municipal and Wholesale Customers. Minnesota Power has contracts with 16 Minnesota municipalities receiving wholesale electric service. One contract expires April 2008 (31,000 MWh purchased in 2007), while the other 15 are for service through at least January 2011. In 2007, these municipal customers purchased 893,000 MWh from Minnesota Power. Minnesota Power also has a contract for wholesale service with Dahlberg Light & Power Company (Dahlberg) in Wisconsin. Dahlberg purchased 115,000 MWh in 2007.

ALLETE 2007 Form 10-K

 

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Energy–Regulated Utility (Continued)

Federal Energy Regulatory Commission (Continued)

Midwest Independent Transmission System Operator, Inc. (MISO). Minnesota Power and SWL&P are members of MISO. Minnesota Power and SWL&P retain ownership of their respective transmission assets and control area functions, but their transmission network is under the regional operational control of MISO, and they take and provide transmission service under MISO open access transmission tariff. MISO continues its efforts to standardize rates, terms and conditions of transmission service over its broad region, encompassing all or parts of 15 states and one Canadian province, and over 100,000 MW of generating capacity.

Mid-Continent Area Power Pool (MAPP). Minnesota Power also participates in MAPP, a power pool operating in parts of eight states in the Upper Midwest and in two Canadian provinces. MAPP functions include a regional transmission committee and a generation reserve-sharing pool. Minnesota Power is also a member of the Midwest Reliability Organization that was established as a regional reliability council within the North American Electric Reliability Council on January 1, 2005.

Minnesota Public Utilities Commission.> Minnesota Power’s retail rates are based on a 1994 MPUC retail rate order that allows for an 11.6 percent return on common equity dedicated to utility plant. Minnesota Power may file a request to increase rates for its retail utility operations in mid-2008. Retail rates are being adjusted without a rate proceeding to reflect recovery of costs related to the AREA Plan, the Boswell 3 Environmental Improvement Plan (see AREA and Boswell Unit 3 Emission Reduction Plans), transmission investments and renewable investments.

Integrated Resource Plan. On October 31, 2007, Minnesota Power filed its Integrated Resource Plan (IRP), a comprehensive estimate of future capacity needs within the Minnesota Power service territory. Minnesota Power believes it can meet the estimated future customer demand for the next decade while achieving real reductions in the emission of greenhouse gases (primarily carbon dioxide).

 

Minnesota Power plans to meet expected loads through approximately 2020 by adding a significant amount of renewable generation and some supporting peaking generation. We do not plan to add new coal generation or enter into long-term power purchase agreements from coal-based generation resources without a greenhouse gas solution. We plan to add 300 to 500 megawatts of carbon-minimizing renewable energy to our generation mix. Besides the additional generation from renewable sources, Minnesota Power anticipates future supply will come from a combination of sources, including:

 

·

"As-needed" peaking and intermediate generation facilities;

·

Expiration of wholesale contracts presently in place;

·

Short-term market purchases;

·

Improved efficiency of existing generation and power delivery assets; and

·

Expanded conservation and demand-side management initiatives.

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

Large Power Contracts. In 2006, a contract for approximately 70 MW was executed with PolyMet Mining, a new customer planning to start a copper, nickel and precious metals (non-ferrous) mining operation in late 2008. If PolyMet Mining receives all necessary environmental permits and achieves start-up, the contract will be fully implemented and would run through at least 2018. In April 2007, the MPUC approved our contract with PolyMet Mining.

In June 2007, a contract was executed with Mesabi Nugget, a company currently constructing an iron nugget facility near Hoyt Lakes, Minnesota. Iron nuggets, which typically consist of more than 94 percent iron (compared to taconite pellets at 63-65 percent iron), are ideal in meeting the requirements of electric-arc furnaces producing steel. On February 7, 2008, the MPUC held a hearing on the contract and adopted a motion approving the contract, subject to the issuance of a written order. Mesabi Nugget has received all necessary permits to begin construction and operations in 2008 and would be a 15 MW customer with the potential for further load growth. The Mesabi Nugget contract would run through at least 2017.

A new contract with Blandin Paper was approved by the MPUC on February 4, 2008. The new contract carries forward the same contract term, cancellation provision and take-or-pay provisions of the prior contract and only changed the demand nomination feature.

In February 2008, United States Steel announced its intent to restart a pellet line at its Keewatin Taconite processing facility. This pellet line, which has been idled since 1980, would be restarted and updated as part of a $300 million investment. It is anticipated that this will bring approximately 3.6 million tons of additional pellet making capability to Northeastern Minnesota by 2011, pending successful approval of environmental permitting.

ALLETE 2007 Form 10-K

 

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Energy–Regulated Utility (Continued)

Minnesota Public Utilities Commission (Continued)

AREA and Boswell Unit 3 Emission Reduction Plans. In May 2006, the MPUC approved our filing for current cost recovery of expenditures to reduce emissions to meet pending federal requirements at Taconite Harbor and Laskin under the AREA Plan. The AREA Plan approval allows Minnesota Power to recover Minnesota jurisdictional costs for SO2, NOX and mercury emission reductions made at these facilities without a rate proceeding. Current cost recovery from retail customers which include a return on investment and recovery of incremental expense. The AREA Plan is expected to significantly reduce emissions from Taconite Harbor and Laskin, while maintaining a reliable and reasonably-priced energy supply to meet the needs of our customers. We believe that control and abatement technologies applicable to these plants have matured to the point where further significant air emission reductions can be attained in a relatively cost-effective manner. Cost recovery filings are required to be made 90 days prior to the anticipated in-service date for the equipment at each unit, with rate recovery beginning the month following the in-service date.

Minnesota Power has completed installation of new equipment at Laskin and current cost recovery of AREA Plan costs has begun. The first of three Taconite Harbor unit installations was completed and placed back in-service in June 2007, with current cost recovery began in July 2007. We anticipate cost recovery on the other Taconite Harbor units once work is completed and the units have been placed back in service, which is expected in late 2008. As of December 31, 2007, we have spent $36 million of the anticipated $60 million in AREA Plan expenditures.

In May 2006, Minnesota Power announced plans to make emission reduction investments at our Boswell Unit 3 generating unit. Plans include reductions of particulate, SO2, NOX and mercury emissions to meet pending federal and state requirements. In late March 2007, the Boswell Unit 3 project received the necessary construction permits. On October 26, 2007, the MPUC issued a written order approving Minnesota Power’s petition for current cost recovery for the Boswell Unit 3 emission reduction plan with some minor modifications and additional reporting requirements. MPUC approval authorized a cash return on construction work in progress during the construction phase in lieu of AFUDC-Equity and allows for a return on investment and current cost recovery of incremental expenses once the unit is placed into service in late 2009. On December 26, 2007, the MPUC approved Boswell Unit 3’s rate adjustment for 2008. As of December 31, 2007, we have spent $89 million of the anticipated $200 million in Boswell Unit 3 emission reduction plan expenditures.

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 CIP’s each year. These investments are recovered from retail customers through a billing adjustment and amounts included in retail base rates. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, as well as a carrying charge on the deferred account balance. The Next Generation Energy Act of 2007 introduced, in addition to minimum spending requirements, an energy-saving goal of 1.5 percent of gross annual retail electric energy sales by 2010. In May 2007, an abbreviated filing was submitted and subsequently approved by the MPUC, allowing the continuation of Minnesota Power’s 2006-2007 CIP biennial and related goals for one additional year, through 2008. For future program years, Minnesota Power will build upon current successful CIP’s in an effort to meet the newly established 1.5 percent energy-saving goal. Minnesota Power’s CIP investment goal was $3.2 million for 2007 ($3.2 million for 2006 and 2005), with actual spending of $3.9 million in 2007 ($3.8 million in 2006; $3.6 million in 2005).

Public Service Commission of Wisconsin>. SWL&P’s current retail rates are based on a December 2006 PSCW retail rate order that became effective January 1, 2007, and allows for an 11.1 percent return on common equity. Current rates reflect a 2.8 percent average increase in retail utility rates for SWL&P customers (a 2.8 percent increase in electric rates, a 1.4 percent increase in natural gas rates and an 8.6 percent increase in water rates). SWL&P originally requested an average increase in retail utility rates of 5.2 percent in its 2006 application. The approved rates were lower than originally requested due to the subsequent removal of costs for a new water tower and electric substation from the original request. Both of these projects are now estimated to be in service in late 2008 because of delays in obtaining all the necessary construction approvals. SWL&P anticipates filing for another rate increase request in 2008 that would go into effect in 2009. Previously, SWL&P’s retail rates were based on a 2005 PSCW retail order that allowed for an 11.7 percent return on common equity.

Minnesota Legislation

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

ALLETE 2007 Form 10-K

 

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Energy–Regulated Utility (Continued)

Minnesota Legislation (Continued)

Greenhouse Gas Reduction. In 2007, Minnesota passed legislation establishing non-binding targets for carbon dioxide reductions. This legislation establishes a goal of reducing statewide greenhouse gas (GHG) emissions across all sectors reducing those emissions to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025, and at least 80 percent below 2005 levels by 2050. Minnesota is also participating in the Midwestern Greenhouse Gas Accord, a regional effort to develop a multi-state approach to GHG emission reductions.

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

Competition

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. The PUHCA 1935 repeal may also allow an acceleration of merger activity, as well as spawn moves by state regulators to adopt PUHCA-like regulations, although both events are speculative and difficult to predict. We cannot predict the timing or substance of any future legislation or regulation.

Franchises

Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 91 cities and towns located within its electric service territory. SWL&P holds similar franchises for electric, natural gas and/or water systems in 15 cities and towns within its service territory. The remaining cities and towns served do not require a franchise to operate within their boundaries. Our exclusive service territories are established by state regulatory agencies.

Energy – Nonregulated Energy Operations

ALLETE’s nonregulated energy operations include our coal mining activities in North Dakota, approximately 50 MW of nonregulated generation and Minnesota land sales.

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 fixed-fee coal supply agreements extending through 2026. (See Item 1 - Fuel and Note 8.) The mining process disturbs and reclaims approximately 210 acres per year. Laws require that the reclaimed land be at least as productive as it was prior to mining. The average cost to reclaim one acre of land is about $15,000, however, it could be as high as $30,000. Reclamation costs are included in the cost of coal passed through to customers. With lignite reserves of an estimated 600 million tons, BNI Coal has ample capacity to expand production.

Nonregulated generation >consists of approximately 50 MW of generation. In 2007, we sold 0.2 million MWh of nonregulated generation (0.2 million in 2006; 1.5 million in 2005). Effective January 1, 2006, Taconite Harbor was redirected from our Nonregulated Energy Operations segment to our Regulated Utility segment in accordance with an update to the Company’s 2004 Resource Plan, as approved by the MPUC.

Nonregulated Power Supply	Unit No.	Year Installed	Year Acquired	Net Capability
				MW
Steam
Wood-Fired (a)
Cloquet Energy Center	5	2001	2001	22
in Cloquet, MN
Rapids Energy Center (b)	6 & 7	1969, 1980	2000	29
in Grand Rapids, MN
Hydro
Conventional Run-of-River
Rapids Energy Center (b)	4 & 5	1917	2000	1
in Grand Rapids, MN

(a)	Supplemented by coal.

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

ALLETE 2007 Form 10-K

 

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Energy – Nonregulated Energy Operations (Continued)

Taconite Harbor>. Taconite Harbor facility has operated as a rate-based asset within the Minnesota retail jurisdiction since January 1, 2006. Prior to January 1, 2006, the Taconite Harbor facility was operated as nonregulated generation facility. (See Energy – Regulated Utility – Minnesota Public Utilities Commission.)

Rainy River Energy> has been engaged in the acquisition and development of nonregulated generation and wholesale power marketing. (See Note 10.)

Rainy River Energy Corporation - Wisconsin> continues to study the feasibility of the construction of a natural gas-fired electric generating facility in northwestern Wisconsin.

Minnesota Land>. We have about 15,000 acres of land in northern Minnesota, available for sale. We acquired the land in 2001 when we purchased Taconite Harbor from LTV Steel Mining Co.

Energy – Investment in ATC

At December 31, 2007, we had an approximate 8 percent ownership interest in ATC. ATC is a Wisconsin-based public utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATC provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of establishing the independent operation and ownership of, and investment in, transmission facilities. (See Note 6.) Our Wisconsin subsidiary, Rainy River Energy Corporation - Wisconsin, has invested $60 million in ATC.

Real Estate

ALLETE Properties is our real estate business that has operated in Florida since 1991. ALLETE Properties acquires real estate portfolios and large land tracts at bulk prices, adds value through entitlements and/or infrastructure improvements, and resells the property over time to developers, end-users and investors. ALLETE Properties is focused on acquiring vacant land in Florida and other parts of the southeast United States. Management at ALLETE Properties uses their business relationships, understanding of real estate markets and expertise in the land development and sales processes to provide revenue and earnings growth opportunities to ALLETE.

ALLETE Properties is headquartered in Fort Myers, Florida, the location of its southwest Florida regional office. We also have a regional office in Palm Coast, Florida, which oversees northeast Florida operations.

Southwest Florida operations consist of land sales and a third-party brokerage business, with limited land development activities. Inventory includes residential and non-residential land located in Lehigh Acres and Cape Coral. The inventory represents the remaining properties acquired in 1991 from the Resolution Trust Corporation and in 1999 from Avatar Properties, Inc. The operation also generates rental income from a 186,000 square foot retail shopping center located in Winter Haven, Florida. The center is anchored by Macy’s and Belk’s department stores, along with Staples.

Northeast Florida operations focus on land sales and development activities. Development activities involve mainly zoning, permitting, platting and master infrastructure construction. Development costs are financed through a combination of community development district bonds, bank loans and internally-generated funds. Our three major development projects include Town Center at Palm Coast, Palm Coast Park and 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. Surrounded by major arterial roads, including Interstate 95, Town Center is adjacent to the Florida Hospital-Flagler, the Flagler County Airport and the Flagler Palm Coast High School. Sites have also been set aside for a new city hall, a community center, an arts and entertainment center, and other public uses. At build-out, Town Center is expected to include approximately 3,200 residential units including lodging rooms and assisted living units, and 3.8 million square feet of various types of non-residential space. Market conditions will determine how quickly Town Center builds out.

Construction of the major infrastructure improvements at Town Center was substantially complete at the end of 2006. Improvements include 3.6 miles of roads, a master storm water management system, underground utilities, street lights, sidewalks, bike paths, and extensive landscaping. To date, our marketing program has targeted a blend of office, retail commercial, residential, mixed-use and institutional project developers. In April 2007, Palm Coast Center, LLC and Target Corporation closed on a 52 acre commercial site and immediately began construction of a 424,000 square foot retail power center. An 85,000 square foot retail center anchored by a Publix grocery store opened in 2007.

ALLETE 2007 Form 10-K

 

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Real Estate (Continued)

Pending land sales under contract for properties at Town Center totaled $18.9 million at December 31, 2007. We have the opportunity to receive participation revenue as part of one of these sales contracts.

In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6% Capital Improvement Revenue Bonds, Series 2005, which are payable through property tax assessments on the land owners over 31 years (by May 1, 2036). The bonds were primarily used to pay for the construction of a portion of the major infrastructure improvements at Town Center. (See Note 8.)

Palm Coast Park>. Palm Coast Park, which is located in the city of Palm Coast, is a 4,700-acre mixed-use development bisected by a six-mile segment of U.S. Highway 1 about one mile from an existing Interstate 95 interchange and bounded on the west by a Florida East Coast Railroad line. Major infrastructure construction at Palm Coast Park was substantially complete by the end of 2007. At build-out, Palm Coast Park is expected to include approximately 4,000 residential units, 3.2 million square feet of various types of non-residential space and certain public facilities. Market conditions will determine how quickly Palm Coast Park builds out. Land sales at Palm Coast Park commenced in August 2006, and in June 2007, LRCF Palm Coast, LLC (a subsidiary of Lowe Enterprises) closed on the first phase of its Sawmill Creek project.

Pending land sales under contract for properties at Palm Coast Park totaled $31.9 million at December 31, 2007. We have the opportunity to receive participation revenue as part of these sales contracts.

In May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7% Special Assessment Bonds, Series 2006, which are payable through property tax assessments on the land owners over 31 years (by May 1, 2037). The bonds were primarily used to pay for the construction of the major infrastructure improvements at Palm Coast Park and to mitigate traffic and environmental impacts. (See Note 8.)

ALLETE Properties is funding certain platting and permitting costs; however, the majority of ongoing and future development costs may be funded by Palm Coast Park District bond proceeds. We anticipate that the Palm Coast Park District will need to issue additional bonds to pay for the development of retail commercial, office and industrial lots.

Ormond Crossings.> Ormond Crossings is an approximately 6,000-acre mixed-use development that is located in both the city of Ormond Beach in Volusia County and unincorporated Flagler County. The site is bisected by Interstate 95 and a Florida East Coast Railroad line and is adjacent to the city of Ormond Beach airport. Ormond Crossings has three miles of frontage on the east and west sides of Interstate 95 and will have two main entrances each within a mile from an existing U.S. Highway 1 and Interstate 95 interchange.

Planning, engineering design and permitting of the master infrastructure are ongoing. Density of the residential and non-residential components of the project will be determined based on market and traffic mitigation cost considerations. We estimate the first two phases of Ormond Crossings will include 2,500–3,200 residential units and 2.5–3.5 million square feet of various types of non-residential space.

Ormond Crossings will also include an approximately 2,000 acre regionally significant wetlands mitigation bank that is expected to be fully permitted by the St. Johns River Water Management District and the U.S. Army Corps of Engineers by mid-2009. Wetland mitigation credits will be used at Ormond Crossings and will be available for sale to other developers. Market conditions will determine how quickly Ormond Crossings builds out.

Other Land>. In addition to the major development projects, land inventories in Florida include approximately 1,600 acres of other property. Several smaller development projects are under way to plat these properties, add infrastructure, modify and enhance existing entitlements.

Property sale prices may vary depending on location; physical characteristics; parcel size; whether parcels are sold as raw land, partially developed land or individually developed lots; degree and status of entitlement; and whether the land is ultimately purchased for residential or non-residential development. Certain contracts allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

Seller Financing

ALLETE Properties sometimes provides seller financing. At December 31, 2007, outstanding finance receivables were $15.3 million, with maturities up to 5 years. These finance receivables accrue interest at market-based rates and are collateralized by the financed properties.

ALLETE 2007 Form 10-K

 

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Real Estate (Continued)

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.

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), which requires counties and cities to adopt comprehensive plans guiding and controlling future real property development in their respective jurisdictions. In addition, development projects that exceed certain specified regulatory thresholds require approval of a comprehensive DRI application. The DRI review process includes an evaluation of a project’s impact on the environment, infrastructure and government services, and requires the involvement of numerous state and local environmental, zoning and community development agencies. Compliance with the Growth Management Act and the DRI process is usually lengthy and costly.

Competition

The real estate industry is very competitive. Our properties are located in Florida. We are focused on acquiring additional vacant land in Florida and other parts of the southeast United States. This region continues to attract competitive real estate operations at many different levels in the land development pipeline. Competitors include local and out-of-state institutional investors, real estate investment trusts and real estate operators, among others. These competitors, both public and private, compete with us in seeking real estate for acquisition, resources for development and sales to prospective buyers. Consequently, competitive market conditions may influence the timing and profitability of our real estate transactions.

Other

Our Other segment consists of investments in emerging technologies related to the electric utility industry, and earnings on cash and short-term investments.

Emerging Technology Portfolio. >As part of our emerging technology portfolio, we have several minority investments in venture capital funds and direct investments in privately-held, start-up companies. Since 1985, we have invested in start-up companies, developing technologies that may be utilized by the electric utility industry. We are committed to invest up to an additional $1.0 million in 2008 and do not have plans to make any additional investments. The investments were first made through emerging technology funds (Funds) initiated by other electric utilities and us. Due to the distribution of investments from matured venture capital funds, we also have direct investments in privately-held companies. Companies in the Funds’ portfolios may complete IPOs, and the Funds may, in some instances, distribute publicly tradable shares to us. Some restrictions on sales may apply, including, but not limited to, underwriter lock-up periods that typically extend for 180 days following an IPO. (See Note 6.)

Discontinued Operations. In the past three years, we also had business operations in the water and telecommunications industries. (See Note 13.)

Sale of Water Services Businesses. In early 2005, we completed the exit from our Water Services businesses with the sale of our wastewater assets in Georgia.

Sale of Enventis Telecom. In December 2005, we sold all the stock of our telecommunications subsidiary, Enventis Telecom for $35.5 million. The transaction resulted in an after-tax loss of $3.6 million, which was reported in our 2005 loss from discontinued operations. Net cash proceeds realized from the sale were approximately $29 million after transaction costs, repayment of debt and payment of income taxes.

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to future stricter environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. (See Item 7 – Capital Requirements.) We are unable to predict if and when any such stricter environmental requirements will be imposed and the impact they will have on the Company. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the balance sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.

ALLETE 2007 Form 10-K

 

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Environmental Matters (Continued)

Air. >Clean Air Act. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of these facilities are equipped with pollution control equipment such as scrubbers, bag houses or electrostatic precipitators. Permitted emission requirements are currently being met. The federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2 and system wide averaging NOX limits. Each allowance is currently an authorization to emit one ton of SO2, and each utility must have sufficient allowances to cover its annual emissions. Minnesota Power has adequate SO2 allowances for its operations and is in compliance with applicable NOX limits. Square Butte is meeting its SO2 emission allowance requirements through increased use of its existing scrubber.

EPA Clean Air Interstate Rule. In March 2005, the EPA announced the final Clean Air Interstate Rule (CAIR) that reduces and permanently caps emissions of SO2, NOX and particulates in the eastern United States. The CAIR includes Minnesota as one of the 28 states it considers as “significantly contributing” to air quality standards non-attainment in other downwind states. The CAIR has been challenged in the court system, which may delay implementation or modify provisions in the rules. Minnesota Power is participating in the legal challenge to the CAIR. However, if the CAIR does go into effect, Minnesota Power expects to be required to:

(1)	make emissions reductions (See AREA and Boswell Unit 3 Emission Reduction Plans for discussion of current emission reduction initiatives);

(2)	purchase SO2 and NOX allowances through the EPA’s cap-and-trade system (See CAIR Phase I NOX Allowance Purchases below); and/or

(3)	use a combination of both (1) and (2).

CAIR will be implemented over two phases. Phase I begins in 2009 and Phase II in 2015. The EPA will allocate an emissions budget to each CAIR-affected state for SO2 and NOX that will result in significant emission reductions. The emissions budgets are reduced from Phase I to Phase II. States can choose to implement the EPA’s proposed model program or develop their own subject to EPA approval. The MPCA has indicated that it plans to adopt the EPA’s Federal Implementation Plan. Minnesota Power is implementing a balanced environmental plan making significant capital investments with the AREA and Boswell Unit 3 emission reduction retrofits in efforts to comply with CAIR Phase I and purchasing emission allowances as necessary. In spite of these efforts, Minnesota Power expects to be in a short position relative to NOX allowances beginning in 2009, and is anticipating purchasing NOX allowances as needed during Phase I of CAIR.

EPA Clean Air Mercury Rule. In March 2005, the EPA also announced the final Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped emissions of electric utility mercury emissions in the continental United States. On February 8, 2008 the United States Court of Appeals for the District of Columbia Circuit overturned the CAMR and remanded the rulemaking to the EPA for reconsideration. The Court’s decision is subject to appeal. It is uncertain how the EPA will respond; and therefore it is also uncertain whether mercury emission reductions expected as a result of implementing AREA Plan expenditures at Taconite Harbor, and implementation of the 2006 Minnesota Mercury Emission Reduction Law which applies to Boswell Units 3 and 4, will meet the EPA’s reformed mercury regulations. (See Minnesota Mercury Emission Law.) Cost estimates for complying with future mercury regulations under the Clean Air Act are therefore premature at this time.

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

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

Solid and Hazardous Waste.> The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid wastes and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA. The Toxic Substances Control Act regulates the management and disposal of materials containing polychlorinated biphenyl (PCB). In response to the EPA Region V’s request for utilities to participate in the Great Lakes Initiative by voluntarily removing remaining PCB inventories, Minnesota Power replaced its PCB capacitor banks by 2005. PCB-contaminated oil in substation equipment was replaced by June 2007. We are in material compliance with these rules.

ALLETE 2007 Form 10-K

 

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Environmental Matters (Continued)

SWL&P Manufactured Gas Plant. In May 2001, SWL&P received notice from the WDNR that the City of Superior had found soil contamination on property adjoining a former Manufactured Gas Plant (MGP) site owned and operated by SWL&P from 1889 to 1904. A report submitted in 2003 identified some MGP-like chemicals that were found in the soil near the former plant site. The final Phase II report was issued on June 7, 2007, confirming our understanding of the issues involved. The final Phase II Report and Risk Assessment were sent to the WDNR for review on June 18, 2007. A remediation plan was developed during the last quarter of 2007 and will be submitted to the WDNR during the first quarter of 2008. Although it is not possible to fully quantify the potential clean-up cost until the WDNR’s review is completed, a $0.5 million liability was recorded in December 2003 to address the known areas of contamination. The Company has recorded a corresponding dollar amount as a regulatory asset to offset this liability. The PSCW approved the collection through rates of $0.3 million of site investigation costs that had been incurred through 2005. ALLETE maintains pollution liability insurance coverage that includes coverage for SWL&P. A claim has been filed with respect to this matter. The insurance carrier has issued a reservation of rights letter and the Company continues to work with the insurer to determine the availability of insurance coverage.

Employees

At December 31, 2007, ALLETE had approximately 1,500 employees, of which 1,400 were full-time.

Minnesota Power and SWL&P have an aggregate 622 employees who are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. The labor agreement with IBEW Local 31 expires on January 31, 2009.

BNI Coal has 97 employees who are members of the IBEW Local 1593. BNI Coal and IBEW Local 1593 have a labor agreement which expires on March 31, 2008. BNI expects to have a new labor agreement in place on, or before, the expiration of the existing contract.

Availability of Information

ALLETE makes its SEC filings, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, available free of charge on ALLETE’s Website www.allete.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC.

ALLETE 2007 Form 10-K

 

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Executive Officers of the Registrant

Executive Officers	Initial Effective Date
Donald J. Shippar, Age 58
Chairman, President and Chief Executive Officer	January 1, 2006
President and Chief Executive Officer	January 21, 2004
Executive Vice President – ALLETE and President – Minnesota Power	May 13, 2003
President and Chief Operating Officer – Minnesota Power	January 1, 2002
Deborah A. Amberg, Age 42
Senior Vice President, General Counsel and Secretary	January 1, 2006
Vice President, General Counsel and Secretary	March 8, 2004
Steven Q. DeVinck, Age 48
Controller	July 12, 2006
Laura A. Holquist, Age 46
President – ALLETE Properties, LLC	September 6, 2001
Mark A. Schober, Age 52
Senior Vice President and Chief Financial Officer	July 1, 2006
Senior Vice President and Controller	February 1, 2004
Vice President and Controller	April 18, 2001
Donald W. Stellmaker, Age 50
Treasurer	July 24, 2004
Claudia Scott Welty, Age 55
Senior Vice President and Chief Administrative Officer	February 1, 2004

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

Ms. Amberg was a Senior Attorney.

 

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

 

Mr. Stellmaker was Director of Financial Planning.

 

Ms. Welty was Vice President Strategy and Technology Development.

 

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 13, 2008.

ALLETE 2007 Form 10-K

 

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Item 1A.                      Risk Factors

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

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

Our 12 Large Power Customers accounted for approximately 34 percent of our 2007 consolidated operating revenue (one of these customers accounted for 12 percent of consolidated revenue). These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the global marketplace. An economic downturn or failure to compete effectively in the global economy could have a material adverse effect on their operations and, consequently, could negatively impact our results of operations.

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

We are subject to prevailing governmental policies and regulatory actions, including those of the United States Congress, state legislatures, the FERC, the MPUC and the PSCW. These governmental regulations relate to allowed rates of return, financings, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and capital investments, and present or prospective wholesale and retail competition (including but not limited to transmission costs). These governmental regulations significantly influence our operating environment and may affect our ability to recover costs from our customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.

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

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

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

We cannot be certain whether new laws or regulations will be adopted to reduce GHGs and what affect any such laws or regulations would have on us. If any new laws or regulations are implemented, they could have a material effect on our results of operations, particularly if implementation costs are not fully recoverable from customers.

Our Regulated Utility has established a goal to reduce overall GHG emissions associated with electric generation and delivery. We plan to expand our renewable energy production, expand customer conservation and process efficiency improvements, select low GHG emitting resources to meet new generation needs, and expand the use of renewable generation resources through dispatching those units based on their environmental performance.

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

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Risk Factors (Continued)

The cost of environmental emission allowances could have a negative financial impact on our Regulated Utility Operations.

Minnesota Power is subject to numerous environmental laws and regulations which require us to purchase environmental emissions allowances which could increase our cost of operations and expose us to emission price fluctuations. We are unable to predict emission allowance pricing or regulatory recovery of these costs. We will be pursuing a current cost recovery mechanism with the MPUC and FERC.

Our Regulated Utility and Nonregulated Energy Operations pose certain environmental risks which could adversely affect our results of operations and financial condition.

We are subject to extensive environmental laws and regulations affecting many aspects of our present and future operations, including air quality, water quality, waste management, reclamation and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the financial or operational outcome of any related litigation that may arise.

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

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

The operation and maintenance of our generating facilities in our Regulated Utility and Nonregulated Energy Operations involve risks that could significantly increase the cost of doing business.

The operation of generating facilities involves many risks, including start-up risks, breakdown or failure of facilities, the dependence on a specific fuel source, or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency, the occurrence of any of which could result in lost revenue, increased expenses or both. A significant portion of Minnesota Power’s facilities were constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency. This equipment is also likely to require periodic upgrading and improvements due to changing environmental standards and technological advances. (See Item I – Environmental Matters.) 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 Regulated Utility and Nonregulated Energy Operations must have adequate and reliable transmission and distribution facilities to deliver electricity to its customers.

Minnesota Power depends on transmission and distribution facilities owned by other utilities, and transmission facilities primarily operated by MISO, as well as its own such facilities, to deliver the electricity we produce and sell to our customers, and to other energy suppliers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered, we may have to forego sales or we may have to buy more expensive wholesale electricity that is available in the capacity-constrained area. The cost to acquire or provide service may exceed the cost to serve other customers, resulting in lower gross margins. 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.

ALLETE 2007 Form 10-K

 

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Risk Factors (Continued)

In our Regulated Utility and Nonregulated Energy 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 nonregulated operations at this time.

We are dependent on good labor relations.

We believe our relations to be good with our approximately 1,500 employees. Failure to successfully renegotiate labor agreements could adversely affect the services we provide and our results of operations. Approximately 600 of our employees are members of either the International Brotherhood of Electrical Workers Local 31 or Local 1593. The labor agreement with Local 31 at Minnesota Power and SWL&P expires on January 31, 2009, and the labor agreement with Local 1593 at BNI Coal expires on March 31, 2008.

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

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

We are exposed to risks associated with real estate development.

Our real estate development activities entail risks that include construction delays or cost overruns, which may increase project development costs. In addition, the effects of the rebuilding efforts due to destructive weather, including hurricanes, could cause increased prices for construction materials and create labor shortages which could increase our development costs.

Our real estate development activities require significant expenditures. We obtain funds for our expenditures through cash flow from operations and financings, including the financings of the community development districts in which our development projects are located. We cannot be certain that the funds available from these sources will be sufficient to fund our required or desired expenditures for development. If we are unable to obtain sufficient funds, we may have to defer or otherwise limit our development activities.

ALLETE 2007 Form 10-K

 

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Risk Factors (Continued)

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

Development of real property in Florida entails an extensive approval process involving overlapping regulatory jurisdictions. Real estate projects must generally comply with the provisions of the Local Government Comprehensive Planning and Land Development Regulation Act (Growth Management Act). In addition, development projects that exceed certain specified regulatory thresholds require approval of a comprehensive DRI application.

The Growth Management Act requires counties and cities to adopt comprehensive plans guiding and controlling future real property development in their respective jurisdictions. After a local government adopts its comprehensive plan, all development orders and development permits must be consistent with the plan. Each plan must address such topics as future land use, capital improvements, traffic circulation, sanitation, sewage, potable water, drainage and solid waste disposal.

The Growth Management Act, in some instances, can significantly affect the ability of developers to obtain local government approval in Florida. In many areas, infrastructure funding has not kept pace with growth. As a result, substandard facilities and services can delay or prevent the issuance of permits. Consequently, the Growth Management Act could adversely affect the cost and our ability to develop future real estate projects.

The DRI review process includes an evaluation of a project’s impact on the environment, infrastructure and government services, and requires the involvement of numerous state and local environmental, zoning and community development agencies. The DRI approval process is usually lengthy and costly, and conditions, standards or requirements may be imposed on a developer with respect to a particular project, which may materially increase the cost of the project.

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.

Competition could adversely affect our real estate business.

Over the past few years, we have experienced an increase in competition for suitable land in the southeast United States real estate market. The availability of undeveloped land for purchase that meets our internal criteria depends on a number of factors outside our control, including land availability in general, competition with other developers and land buyers for desirable property, inflation in land prices, zoning, allowable development density and other regulatory requirements. Our long-term ability to acquire land suitable for development at reasonable prices in locations where we feel there is a viable market is crucial in maintaining our business success.

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.

ALLETE 2007 Form 10-K

 

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Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

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

Item 3.

Legal Proceedings

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

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

Item 4.

Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

Part II

Item 5.

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

Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends without interruption on our common stock since 1948. A quarterly dividend of $0.43 per share on our common stock will be paid on March 1, 2008, to the holders of record on February 15, 2008.

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

	2007			2006
	Price Range		Dividends	Price Range		Dividends
Quarter	High	Low	Declared	High	Low	Declared
First	$49.69	$44.93	$0.4100	$47.81	$42.99	$0.3625
Second	51.30	45.39	0.4100	48.55	44.34	0.3625
Third	50.05	38.60	0.4100	49.30	43.26	0.3625
Fourth	46.48	38.17	0.4100	47.84	42.55	0.3625
Annual Total			$1.640			$1.450
Dividend Payout Ratio			53%			53%

At February 1, 2008, there were approximately 31,000 common stock shareholders of record.

Common Stock Repurchases.> We did not repurchase any ALLETE common stock during the fourth quarter of 2007.

ALLETE 2007 Form 10-K

 

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Item 6.                      Selected Financial Data

Financial results by segment for the periods presented were impacted by the integration of our Taconite Harbor facility into the Regulated Utility segment effective January 1, 2006. We have operated the Taconite Harbor facility as a rate-based asset within the Minnesota retail jurisdiction since January 1, 2006. Prior to January 1, 2006, we operated our Taconite Harbor facility as nonregulated generation (non-rate base generation sold at market-based rates primarily to the wholesale market). Historical financial results of Taconite Harbor for periods prior to the 2006 redirection are included in our Nonregulated Energy Operations segment.

Operating results of our Water Services businesses and our telecommunications business are included in discontinued operations, and accordingly, amounts have been restated for all periods presented. (See Note 13.) Common share and per share amounts have also been adjusted for all periods to reflect our September 20, 2004, one-for-three common stock reverse split.

	2007		2006		2005		2004		2003
Operating Revenue	$841.7		$767.1		$737.4		$704.1		$659.6
Operating Expenses	708.0		626.4		692.3	(d)	603.2		561.9
Income from Continuing Operations Before Change in Accounting Principle	87.6		77.3		17.6	(d)	38.5		29.2
Income (Loss) from Discontinued Operations – Net of Tax	–		(0.9)		(4.3)		73.7		207.2	(f)
Change in Accounting Principle – Net of Tax	–		–		–		(7.8)	(b)	–
Net Income	87.6		76.4		13.3		104.4		236.4
Common Stock Dividends	44.3		40.7		34.4		79.7		93.2
Earnings Retained in (Distributed from) Business	$43.3		$35.7		$(21.1)		$24.7		$143.2
Shares Outstanding – Millions
Year-End	30.8		30.4		30.1		29.7		29.1
Average (c)
Basic	28.3		27.8		27.3		28.3		27.6
Diluted	28.4		27.9		27.4		28.4		27.8
Diluted Earnings (Loss) Per Share
Continuing Operations	$3.08		$2.77		$0.64	(d)	$1.35	(e)	$1.05
Discontinued Operations	–		(0.03)		(0.16)		2.59		7.47	(f)
Change in Accounting Principle	–		–		–		(0.27)		–
	$3.08		$2.74		$0.48		$3.67		$8.52
Total Assets	$1,644.2		$1,533.4	(a)	$1,398.8		$1,431.4		$3,101.3
Long-Term Debt	410.9		359.8		387.8		389.4		513.9
Return on Common Equity	12.4%		12.1%		2.2%	(d)	8.3%		17.7%
Common Equity Ratio	63.7%		63.1%		60.7%		61.7%		64.4%
Dividends Declared per Common Share	$1.6400		$1.4500		$1.2450		$2.8425		$3.3900
Dividend Payout Ratio	53%		53%		259%	(d)	77%		40%
Book Value Per Share at Year-End	$24.11		$21.90		$20.03		$21.23		$50.18
Capital Expenditures by Segment
Regulated Utility Operations	$220.6		$107.5		$46.5		$41.7		$42.2
Non Regulated Utility	3.3		1.9		12.1		15.7		26.5
Real Estate (h)	–		–		–		–		–
Other	–		–		–		0.4		–
Discontinued Operations	–		–		4.5		21.4		67.6
Total Capital Expenditures	$223.9		$109.4		$63.1		$79.2		$136.3
Current Cost Recovery (g)	$145		$27		–		–		–

(a)	Included $86.1 million of assets and $107.6 million of liabilities reflecting the adoption of SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” (See Notes 2 and 16.)

(b)	Reflected the cumulative effect on prior years (to December 2003) of changing to the equity method of accounting for investments in limited liability companies included in our emerging technology portfolio. (See Note 6.)

(c)	Excludes unallocated ESOP shares.

(d)

Impacted by a $50.4 million, or $1.84 per share, charge related to the assignment of the Kendall County power purchase agreement (See Note 10.), a $2.5 million, or $0.09 per share, deferred tax benefit due to comprehensive state tax planning initiatives, and a $3.7 million, or $0.13 per share, current tax benefit due to a positive resolution of income tax audit issues.

(e)

Included a $10.9 million, or $0.38 per share, after-tax debt prepayment cost incurred as part of ALLETE’s financial restructuring in preparation for the spin-off of the Automotive Services business and an $11.5 million, or $0.41 per share, gain on the sale of ADESA shares related to the Company’s ESOP (see Note 16).

(f)	Included a $71.6 million, or $2.59 per share, gain on the sale of the Water Services businesses.

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

(h)	Excludes capitalized improvements on our development projects, which are included in inventory. (See Note 6.)

ALLETE 2007 Form 10-K

 

27

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

The following discussion should be read in conjunction with our consolidated financial statements and notes to those statements and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this report contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-K under the headings: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” located on page 5 and “Risk Factors” located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only ones facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the concerns set forth in this Form 10-K are realized.

Overview

ALLETE is a diversified company that has provided fundamental products and services since 1906. These include our former operations in the water, paper, telecommunications and automotive industries and the core Energy and Real Estate businesses we operate today.

Energy> is comprised of Regulated Utility, Nonregulated Energy Operations and Investment in ATC.

·

Regulated Utility includes retail and wholesale rate regulated electric, natural gas and water services in northeastern Minnesota and northwestern Wisconsin under the jurisdiction of state and federal regulatory authorities.

 

·

Nonregulated Energy Operations includes our coal mining activities in North Dakota, approximately 50 MW of nonregulated generation and Minnesota land sales.

 

·

Investment in ATC includes our equity ownership interest in ATC.

Real Estate includes our Florida real estate operations.

Other> includes our investments in emerging technologies, and earnings on cash and short-term investments.

We are committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses, and sustains our growth. We strive to grow earnings and dividends that will result in a total shareholder return that is superior to that of similar companies. Our goal is to earn a financial return that will allow us to provide dividend increases while at the same time fund our growth initiatives.

2007 Financial Overview

(See Note 1. Business Segments for financial results by segment.)

Net income for 2007 was $87.6 million, or $3.08 per diluted share ($76.4 million, or $2.74 per diluted share for 2006; $13.3 million, or $0.48 per diluted share for 2005). Net income for 2007 was up $11.2 million from 2006 reflecting:

Regulated Utility> contributed income of $54.9 million in 2007 ($46.8 million in 2006; $45.7 million in 2005). The increase in earnings for 2007 reflects:

·

increased electric sales to residential, commercial and municipal customers;

·

continued strong demand from our industrial customers;

·

rate increases, effective January 1, 2007, at SWL&P;

·

commencement of current cost recovery on AREA project environmental capital expenditures;

·

higher AFUDC related to increased capital expenditures;

·

increased operations and maintenance expense, relating to outages and salary and wage increases; and

·

a lower effective tax rate.

Nonregulated Energy Operations> reported income of $3.5 million in 2007 ($3.7 million in 2006; a loss of $48.5 million in 2005), reflecting a $1.2 million after tax gain on land sold that was part of our purchase of Taconite Harbor and higher lease lot revenue due to newly developed lots. The increases were partially offset by lower income from BNI Coal, reflecting lower coal sales in 2007.

Investment in ATC> contributed income of $7.5 million in 2007 ($1.9 million in 2006). Our initial investment in ATC began in May 2006. We reached our approximate 8 percent ownership in February 2007.

Real Estate contributed income of $17.7 million in 2007 ($22.8 million in 2006; $17.5 million in 2005). Income was lower in 2007 than in 2006 due to a weaker real estate market in 2007.

Other> reflected net income of $4.0 million in 2007 ($2.1 million in 2006; $2.9 million in 2005). The increase in 2007 included a state tax audit settlement for $1.5 million and the release from a loan guarantee for Northwest Airlines of $0.6 million after tax.

ALLETE 2007 Form 10-K

 

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Overview (Continued)

 

Financial results for continuing operations in 2005 were significantly impacted by a $77.9 million ($50.4 million after tax, or $1.84 per share) charge due to the assignment of the Kendall County power purchase agreement to Constellation Energy Commodities (Kendall County Charge). (See Note 10.)

 

Financial results by segment from 2005 and 2006 presented and discussed in this Form 10-K were impacted by the integration of our Taconite Harbor facility into the Regulated Utility segment effective January 1, 2006. We have operated the Taconite Harbor facility as a rate-based asset within the Minnesota retail jurisdiction since January 1, 2006. Prior to January 1, 2006, we operated our Taconite Harbor facility as nonregulated generation. Historical financial results of Taconite Harbor for periods prior to the 2006 redirection are included in our Nonregulated Energy Operations segment.

Kilowatthours Sold	2007	2006	2005
Millions
Regulated Utility
Retail and Municipals
Residential	1,141	1,100	1,102
Commercial	1,373	1,335	1,327
Industrial	7,054	7,206	7,130
Municipals	1,008	911	877
Other	84	79	79
Total Retail and Municipals	10,660	10,631	10,515
Other Power Suppliers	2,157	2,153	1,142
Total Regulated Utility	12,817	12,784	11,657
Nonregulated Energy Operations	249	240	1,521
Total Kilowatthours Sold	13,066	13,024	13,178

Real Estate	2007		2006		2005
Revenue and Sales Activity (a)	Quantity	Amount	Quantity	Amount	Quantity	Amount
Dollars in Millions
Revenue from Land Sales
Town Center Sales
Non-residential Sq. Ft.	540,059	$15.0	401,971	$10.8	643,000	$15.2
Residential Units	130	1.6	773	12.9	–	–
Palm Coast Park
Non-residential Sq. Ft.	40,000	2.0	–	–	–	–
Residential Unit	606	13.2	200	3.0	–	–
Other Land Sales
Acres (b)	483	10.6	732	24.4	1,102	38.1
Lots	–	–	–	–	7	0.4
Contract Sales Price (c)		42.4		51.1		53.7
Revenue Recognized from
Previously Deferred Sales		3.1		9.7		–
Deferred Revenue		(1.2)		(3.8)		(10.0)
Adjustments (d)		–		(0.9)		(1.7)
Revenue from Land Sales		44.3		56.1		42.0
Other Revenue		6.2		6.5		5.5
		$50.5		$62.6		$47.5

(a)	Quantity amounts are approximate until final build-out.

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

(c)	Reflected total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-completion method. (See Critical Accounting Estimates and Note 2.)

(d)	Contributed development dollars, which are credited to cost of real estate sold.

ALLETE 2007 Form 10-K

 

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2007 Compared to 2006

(See Note 1. Business Segments for financial results by segment.)

Regulated Utility

Operating revenue> increased $84.6 million, or 13.2 percent, from 2006, primarily due to increased fuel clause recoveries, increased kilowatthour sales to residential, commercial and municipal customers, increased power marketing prices, and rate increases at SWL&P.

Fuel clause recoveries increased $63.3 million in 2007 as a result of increased purchased power expenses (see Fuel and Purchased Power Expense discussion below).

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

Revenue from sales to other power suppliers increased $3.6 million, or 3.8 percent, from 2006, primarily due to a 3.6 percent increase in the price per kilowatthour.

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

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

Overall, kilowatthour sales were flat in 2007. Combined residential, commercial and municipal kilowatthour sales increased 181.0 million, or 5.3 percent, from 2006, while industrial kilowatthour sales decreased by 152.1 million, or 2.1 percent. The increase in residential, commercial and municipal kilowatthour sales was primarily because of two existing municipal customers converting to full-energy requirements and a 9.2 percent increase in Heating Degree Days (primarily in February). The reduction in industrial kilowatthour sales was primarily due to an idle production line and production delays at one of our taconite customers. In September 2007, the affected taconite customer resumed production on the idle line. Minor fluctuations in industrial kilowatthour sales generally do not have a large impact on revenue due to a fixed demand component of revenue that is less sensitive to changes in kilowatthours sales.

Operating expenses increased $76.9 million, or 14.1 percent, from 2006.

Fuel and Purchased Power Expense increased $65.9 million, or 23.4 percent, from 2006 primarily due to a $61.4 million increase in purchased power reflecting a 45.1 percent increase in market purchases and an 11.0 percent increase in market prices. The increase in purchased power was primarily due to the following outages at our generating facilities:

·

scheduled outage at Boswell Unit 3;

·

scheduled outages at Laskin Unit 1 and Taconite Harbor Unit 2 relating to AREA Plan environmental upgrades; and

·

unscheduled outages at Boswell Unit 4.

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

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

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

Operating and Maintenance Expense increased $11.4 million, or 5.2 percent, from 2006, due to a $9.0 million increase in plant maintenance primarily due to planned and unscheduled outages and salary and wage increases.

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

Interest Expense >increased $0.8 million, or 4.0 percent, from 2006, primarily due to higher debt balances reflecting increased construction activity. The increase was partially offset by the capitalization of more AFUDC-Debt.

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

ALLETE 2007 Form 10-K

 

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2007 Compared to 2006 (Continued)

Nonregulated Energy Operations

Operating revenue> increased $2.0 million, or 3.1 percent, from 2006, primarily due to higher coal revenue realized under a cost-plus contract. This increase reflects a 12.2 percent increase in the delivered price per ton due to higher coal production expenses (see Operating expenses below), partially offset by lower sales volume.

Operating expenses increased $4.3 million, or 7.0 percent, from 2006, reflecting higher coal production expense and higher property taxes. The increase in property taxes is primarily due to higher assessed market values on our Minnesota land, while the increase in coal operating expenses is due to higher fuel costs, tire and dragline repairs.

Interest Expense >decreased $1.3 million from 2006, reflecting lower interest on income tax accruals.

Other income >increased $1.7 million from 2006, reflecting higher gains on Minnesota land sales and higher lease lot revenue due to leasing newly developed lots.

Investment in ATC

Equity Earnings> increased $9.6 million in 2007, resulting from our pro-rata share of ATC’s earnings as discussed in Note 3. Our initial investment in ATC began in May 2006. We reached our approximate 8 percent ownership in February 2007.

Real Estate

Operating revenue> decreased $12.1 million, or 19.3 percent, from 2006, due to a weaker real estate market in 2007, and less recognition of deferred revenue, accounted for under the percentage-of-completion method, as major infrastructure reached substantial completion at Town Center in 2006 and at Palm Coast Park in 2007. Revenue from land sales in 2007 was $44.3 million, which included $3.1 million in previously deferred revenue. In 2006, revenue from land sales was $56.1 million which included $9.7 million in previously deferred revenue. At December 31, 2007, revenue of $3.7 million ($5.6 million at December 31, 2006) was deferred and will be recognized on a percentage-of-completion basis.

Sales at Town Center consisted of 540,059 non-residential square feet (401,971 square feet in 2006), and 130 residential units (773 units in 2006). Palm Coast Park sales included 40,000 non-residential square feet (none in 2006) and 606 residential units (200 units in 2006). In 2007, 483 acres of other land were sold (732 acres in 2006).

Operating expenses increased $0.6 million, or 3.1 percent from 2006, reflecting community development district property tax assessments previously capitalized at Town Center during major infrastructure construction partially offset by lower cost of sales due to the decrease in land sales.

Interest expense> increased $0.5 million from 2006. Interest capitalization was reduced in 2007 as the major infrastructure construction at Town Center was substantially completed at the end of 2006.

Minority Interest participation was down due to lower earnings.

Other

Interest expense> decreased $2.8 million from 2006, primarily due to more interest charged to the regulated utility in 2007 as a result of increased capital expenditures and interest on additional taxes owed on the gain on sale of our Florida Water assets in 2006.

Other income >decreased $1.4 million from 2006, reflecting lower investment income as a result of lower average balances in 2007, partially offset by the release from a loan guarantee for Northwest Airlines of $1.0 million.

Income Taxes

For the year ended December 31, 2007, the effective tax rate on income from continuing operations before minority interest was 34.8 percent (36.1 percent for December 31, 2006). The decrease in the effective rate compared to last year was primarily due to a tax benefit realized as a result of a state income tax audit settlement ($1.5 million), higher AFUDC-Equity, and a larger domestic manufacturing deduction taken in 2007 compared to 2006. The effective rate of 34.8 percent for the year ended December 31, 2007, deviated from the statutory rate (approximately 40 percent) due to the state income tax audit settlement, deductions for Medicare health subsidies and domestic manufacturing production, AFUDC-Equity and investment tax credits.

ALLETE 2007 Form 10-K

 

31

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2006 Compared to 2005

Regulated Utility

Operating revenue> was up $63.6 million, or 11 percent, from 2005, reflecting increased kilowatthour sales and increased fuel clause recoveries. Electric sales increased 1,127 million kilowatthours, or 10 percent, mostly due to the addition of Taconite Harbor wholesale power obligations to the Regulated Utility segment effective January 1, 2006. In 2006, the majority of Taconite Harbor sales are reflected in sales to other power suppliers. Sales to other power suppliers were 2,153 million kilowatthours and $94.3 million (1,142 million kilowatthours and $52.8 million in 2005). Absent the inclusion of pre-existing Taconite Harbor wholesale energy sales obligations, sales to other power suppliers were down reflecting less excess energy available for sale due to more planned outages at Company generating facilities in 2006 than 2005. Electric sales to retail and municipal customers increased 116 million kilowatthours, or 1 percent, and $23.5 million, mainly due to strong demand from industrial customers. Fuel clause recoveries were higher in 2006 as a result of increased fuel and purchased power expenses in 2006. Natural gas revenue was down $2.8 million from 2005 reflecting decreased usage due to warmer weather in 2006.

Operating expenses were up $57.8 million, or 12 percent, from 2005.

Fuel and Purchased Power Expense. Fuel and purchased power expense was up $38.0 million from 2005, reflecting the inclusion of Taconite Harbor operations beginning in 2006 ($22.8 million) and increased purchased power expense due to higher prices paid for purchased power, less Company hydro generation available as a result of below normal precipitation levels, and planned maintenance at Company generating facilities in 2006.

Other Operating Expenses. Other operating expenses were up $19.8 million from 2005. Employee compensation was up $7.3 million primarily due to the inclusion of Taconite Harbor, annual wage increases and the inclusion of union employees in our results sharing compensation awards program. Depreciation expense increased $4.8 million primarily due to the inclusion of Taconite Harbor and a full year of depreciation of projects capitalized in 2005. Plant maintenance expense increased $4.7 million reflecting the inclusion of Taconite Harbor maintenance in 2006 ($4.0 million), increased planned maintenance expense at Boswell Unit 4 ($1.6 million) and increased equipment fuel expenses ($0.9 million) partially offset by a decrease in maintenance expense at Boswell Unit 3 ($1.8 million). In 2005, planned maintenance was performed at Boswell Unit 3 while the unit was down due to a cooling tower failure. Pension expense increased $2.2 million primarily due to a reduction in the discount rate (5.50 percent in 2006; 5.75 percent in 2005). Insurance expense was up $1.0 million due to increased premiums. Vegetation management expense was up $0.7 million due to more completed in 2006. Property taxes were up $0.7 million due to higher mill rates in 2006. Purchased natural gas expense was down $2.7 million due to decreased natural gas sales.

Interest expense >was up $2.8 million, or 16 percent, from 2005, reflecting the inclusion of Taconite Harbor in 2006 partially offset by lower effective interest rates (5.92 percent in 2006; 6.07 percent in 2005).

Nonregulated Energy Operations

Operating revenue> was down $48.9 million, or 43 percent, from 2005 due to the absence of revenue from Taconite Harbor ($55.1 million in 2005) and Kendall County ($3.1 million in 2005). Effective January 1, 2006, Taconite Harbor is reported as part of Regulated Utility. Kendall County operations ceased to be included with our operations effective April 1, 2005, when the Company assigned the power purchase agreement to Constellation Energy Commodities. Coal revenue, realized under cost plus a fixed fee agreements, was up $3.7 million from 2005 reflecting a 16 percent increase in the delivery price per ton due to higher reimbursable coal production expenses (see Operating expenses below). In 2006, tons of coal sold were down 7 percent from 2005 in part due to an outage at Minnkota Power’s Unit 1 in 2006.

Operating expenses were down $125.2 million, or 67 percent, from 2005 reflecting the absence of a $77.9 million charge related to the assignment of the Kendall County power purchase agreement to Constellation Energy Commodities on April 1, 2005, expenses related to Taconite Harbor ($49.3 million in 2005) and other expenses related to Kendall County ($6.3 million in 2005) that were incurred prior to April 1, 2005. Expenses related to coal operations were up $3.4 million reflecting increased equipment lease costs ($1.3 million), higher fuel expenses ($0.6 million) and increased parts and supplies ($0.9 million).

Interest expense> was down $3.3 million, or 50 percent, primarily due to the absence of Taconite Harbor in 2006.

Other income (expense)> reflected $0.5 million more income in 2006 due to increased Minnesota land sales.

Investment in ATC

Other income (expense)> reflected $3.0 million of income in 2006 from our equity investment in ATC, resulting from our share of ATC’s earnings.

ALLETE 2007 Form 10-K

 

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2006 Compared to 2005 (Continued)

Real Estate

Operating revenue> was up $15.1 million, or 32 percent, from 2005, due to the recognition of revenue from prior land sales at our Town Center development project, which are accounted for under the percentage-of-completion method. Revenue from land sales was $56.1 million in 2006 which included $9.7 million of previously deferred revenue. In 2005, revenue from land sales was $42.0 million. Sales at Town Center represented 773 residential units and the rights to build up to 401,971 square feet of non-residential space in 2006 (643,000 non-residential square feet in 2005). Sales at Palm Coast Park represented 200 residential units in 2006. In 2006, 732 acres of other land were sold (1,102 acres and 7 lots in 2005). The first land sales for Town Center were recorded in June 2005 and the first land sales at Palm Coast Park were recorded in August 2006. At December 31, 2006, revenue of $5.6 million ($11.5 million at December 31, 2005) was deferred and will be recognized on a percentage-of-completion basis as development obligations are completed.

Operating expenses were up $2.9 million, or 17 percent, from 2005 reflecting a $1.6 million increase in the cost of real estate sold ($10.2 million in 2006; $8.6 million in 2005) due to the recognition of the cost of real estate sold at our Town Center development project which were previously deferred under the percentage-of-completion method. Selling expenses increased $0.6 million due to higher broker commission in 2006 and recognition of prior year’s selling expenses at our Town Center development project which were previously deferred under the percentage-of-completion method. Property tax expense was $0.2 million higher in 2006 due to increased assessment values and higher rates. At December 31, 2006, cost of real estate sold totaling $1.3 million ($2.2 million at December 31, 2005) and selling expenses of $0.2 million ($0.3 million at December 31, 2005), primarily related to Town Center land sales, were deferred until development obligations are completed.

Other

Operating expenses were down $1.4 million, or 29 percent, from 2005, reflecting lower general and administrative expenses in 2006.

Interest expense >was up $1.6 million, or 70 percent, from 2005, reflecting interest on additional taxes owed on the gain on the sale of our Florida Water assets and state tax audits, and higher variable rates in 2006.

Other income (expense)> reflected $9.9 million more income in 2006 due to a $4.4 million increase in earnings on cash and short-term investments due to higher rates and higher average balances in 2006, the absence of $5.1 million of impairments related to certain investments in our emerging technology portfolio recorded in 2005 and the absence of a $1.0 million charge recognized in 2005 for the probable payment under our guarantee of Northwest Airlines debt.

Discontinued Operations

Discontinued operations includes our Water Services businesses that we sold over a three-year period from 2003 to 2005 and our telecommunications business, which we sold in December 2005. There were no losses recognized in discontinued operations in 2007 (a $0.9 million loss in 2006; $4.3 million loss in 2005).

In 2006, discontinued operations reflected a $0.9 million loss resulting from additional legal and administrative expenses related to exiting the Water Services businesses (a $2.5 million loss in 2005). In 2005, administrative and other expenses were incurred to support Florida Water transfer proceedings. A $1.0 million rate-base settlement charge related to the sale of 63 of Florida Water systems to Aqua Utilities Florida, Inc. was also recorded in 2005. Our wastewater assets in Georgia were sold in February 2005.

Financial results for our telecommunications business reflected a loss of $1.8 million in 2005. In 2005, we recorded a $3.6 million loss on the sale of this business.

Income Taxes

For the year ended December 31, 2006, the effective tax rate from continuing operations before minority interest was 36.1 percent (2.5 percent benefit for the year ended December 31, 2005). The increase in the effective rate compared to 2005 was primarily due to the lower income from continuing operations in 2005 as a result of the Kendall County Charge, and one-time tax benefits realized in 2005 for adjustments to our deferred tax assets and liabilities as a result of comprehensive state tax planning initiatives, and positive resolution of audit issues. The effective rate of 36.1 percent for the year ended December 31, 2006, was less than the combined state and federal statutory rate because of investment tax credits, deductions for Medicare health subsidies, depletion and the expected use of state capital loss carryforwards.

ALLETE 2007 Form 10-K

 

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Critical Accounting Estimates

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

Real Estate Revenue and Expense Recognition.> We account for sales of real estate in accordance with SFAS 66, “Accounting for Sales of Real Estate.” Revenue from residential and non-residential properties is recorded at the time of closing using the full profit recognition method, provided that cash collections are at least 20 percent of the contract price and the other requirements of SFAS 66 are met. However, if we are obligated to perform significant development activities subsequent to the date of the sale, we recognize revenue using the percentage-of-completion method. This method of accounting requires that we recognize gross profit based upon the relationship of development costs incurred to the total estimated development costs of the parcels. During each reporting period, we must estimate the total costs to be incurred until project completion, including development overhead and interest capitalization costs. These total cost estimates will impact the recognition of profit on sales. The costs are allocated to each lot or parcel based on the relative sales value method. These estimates affect the amount of costs relieved as each lot is sold and incorrect estimates may result in a misstatement of the cost of real estate sold. Additionally, we must estimate the selling price of each individual lot or parcel that is included in inventory for inclusion in the inventory cost model. If the estimated selling prices of the lots are inaccurate, a material difference in the timing of recording cost of real estate sold for the lots sold could occur.

We record land held for sale at the lower of cost or fair value, which is determined by the evaluation of individual land parcels. 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. Based on the relative sales value of the parcels within each development project, we capitalize the real estate costs incurred to the cost of real estate parcels in accordance with SFAS 67, “Accounting for Costs and Initial Rental Operations of Real Estate Projects.” When real estate is sold, we include the actual costs incurred and the estimate of future completion costs allocated to the parcel(s) sold, based upon the relative sales value method in the cost of real estate sold. We include land held for sale in Investments on our consolidated balance sheet (See Note 6). 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. Certain contracts allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved. We recognize participation revenue when there is a contractual obligation to receive this revenue.

Pension and Postretirement Health and Life Actuarial Assumptions.> We account for our pension and postretirement benefit obligations in accordance with the provisions of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” SFAS 87, “Employers’ Accounting for Pensions,” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” These standards require the use of assumptions in determining our obligations and annual cost of our pension and postretirement benefits. An important actuarial assumption for pension and other postretirement benefit plans is the expected long-term rate of return on plan assets. In establishing this assumption, we consider the diversification and allocation of plan assets, the actual long-term historical performance for the type of securities invested in, the actual long-term historical performance of plan assets and the impact of current economic conditions, if any, on long-term historical returns. Our pension asset allocation is approximately 61 percent equity, 25 percent debt, 9 percent private equity, 2 percent real estate and 3 percent other securities. Equity securities consist of a mix of market capitalization sizes and both domestic and international securities. We currently use an expected long-term rate of return of 9 percent in our actuarial determination of our pension and other postretirement expense. We annually review our expected long-term rate of return assumption and will adjust it to respond to any changing market conditions. A one-quarter percent decrease in the expected long-term rate of return would increase the annual expense for pension and other postretirement benefits by approximately $1.5 million, pre-tax; conversely, a one-quarter percent increase in the expected long-term rate of return would decrease the annual expense by approximately $1.5 million, pre-tax.

For plan valuation purposes, we currently use a discount rate of 6.25 percent. The discount rate is determined considering high-quality long-term corporate bond rates at the valuation date. The discount rate is compared to the Citigroup Pension Discount Curve adjusted for ALLETE’s specific cash flows. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows for our pension obligation. The Audit Committee of the Board of Directors annually reviews and approves the rate of return and discount rate estimates used for pension valuation and accounting purposes. (See Note 15.)

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Critical Accounting Estimates (Continued)

Regulatory Accounting. >Our regulated utility operations are subject to the provisions of SFAS 71, “Accounting for the Effects of Certain Types of Regulation”. SFAS 71 requires us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets or liabilities arise as a result of a difference between GAAP. and the accounting principles imposed by the regulatory agencies. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred.

We recognize regulatory assets and liabilities in accordance with applicable state and federal regulatory rulings. The recoverability of regulatory assets is periodically assessed by considering factors such as, but not limited to, changes in regulatory rules and rate orders issued by applicable regulatory agencies. The assumptions and judgments used by regulatory authorities may have an impact on the recovery of costs, the rate of return on invested capital, and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material impact on our results of operations. (See Note 5.)

Valuation of Investments.> As part of our emerging technology portfolio, we have several minority investments in venture capital funds and direct investments in privately-held, start-up companies. We account for our investment in venture capital funds under the equity method and account for our direct investments in privately-held companies under the cost method because of our ownership percentage. These investments are included in Investments on our consolidated balance sheet. Our policy is to review these investments for impairment on a quarterly basis by assessing such factors as continued commercial viability of products, cash flow and earnings. Any impairment would reduce the carrying value of the investment and be recognized as a loss. In 2007, we recorded an impairment loss on these investments of $0.5 million pretax (none in 2006). (See Note 6.)

Taxation.> We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate and use taxes. Judgments related to income taxes require the recognition in our financial statements of the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit. Tax positions that do not meet the “more-likely-than-not” criteria are reflected as a tax liability. These judgments include reserves for potential adverse outcomes regarding tax positions that we have taken. We must also assess our ability to generate capital gains to realize tax benefits associated with capital losses expected to be generated in future periods. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the three prior or five succeeding years for federal purposes, and fifteen succeeding years for Minnesota purposes. As of December 31, 2007, we have, where appropriate, recorded a valuation allowance against our deferred tax assets associated with realized capital losses and impairments to reduce the deferred tax assets to the amount we estimate is more likely than not to be realized in accordance with FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109”. While we believe the resulting tax reserve balances as of December 31, 2007, reflect the most likely outcome of these tax matters in accordance with SFAS 109, “Accounting for Income Taxes,” the ultimate amount of capital losses resulting in tax benefits could differ from the net amount of deferred tax assets at December 31, 2007.

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Outlook

ALLETE is committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. New opportunities have arisen which we believe will allow us to achieve our long term earnings growth goals through our existing businesses. Our Regulated Utility expects to make significant investments to comply with renewable and environmental requirements, maintain its existing low-cost generation fleet and strengthen and enhance the regional transmission grid. In addition, we expect kilowatt-hour sales growth from existing and potential new customers. Earnings from our ATC investment are expected to grow as we anticipate making additional investments to fund our pro-rata share of ATC’s capital expansion program. We expect net income from Real Estate to be approximately 10 percent to 20 percent of total ALLETE consolidated net income over the next several years.

We will focus our business development activities on growth opportunities in, or complementary to, our core businesses. We believe that current weak market conditions will present an opportunity to add to our portfolio of properties for sale at our Real Estate operations. We anticipate that we will have ready access to sufficient funds for capital investments and acquisitions.

Earnings Guidance. >In 2008, we expect ALLETE’s diluted earnings per share from continuing operations to be in the range of $2.70 to $2.90. This guidance reflects:

Regulated Utility

·

New FERC-approved wholesale rates effective March 1, 2008;

 

·

Minnesota Power’s intention to file a retail rate case with the MPUC in mid-2008, with interim rates in effect 60 days later;

 

·

Minnesota Power’s expectation that electricity sales to industrial customers will continue at the current high levels during 2008;

 

·

increased revenue from current cost recovery riders related to the Company’s investments in environmental and renewable energy initiatives;

 

·

increased operation and maintenance expenses, including labor and benefit costs;

 

·

increased financing costs associated with the 2008 capital expenditure program;

 

·

anticipation of approximately $316 million in capital expenditures in 2008, about half of which will be invested in environmental and renewable energy initiatives;

 

Investment in ATC

·

the expectation of ALLETE investing an additional $5 to $7 million in ATC in 2008;

 

Real Estate

·

a continuation of the difficult market conditions; and

·

an expectation that net income in 2008 will be less than in 2007.

Energy. >As part of our strategy, we will leverage the strengths of our Regulated Utility business to improve our strategic and financial outlook and seek growth opportunities in close proximity to existing operations in the Midwest. We believe electric industry deregulation is unlikely in Minnesota and Wisconsin in the next five years.

Minnesota Power expects significant rate base growth over the next several years as it makes capital expenditures to comply with renewable energy requirements and environmental mandates. In addition, significant investment will be made in our existing low-cost generation fleet to provide for continued future operations as we continue to believe ownership of low-cost generation is a competitive advantage. Minnesota Power will also look for transmission opportunities which strengthen and enhance the regional transmission grid and take advantage of our geographic location between sources of renewable energy and growing energy markets. Our capital investments will be recovered through a combination of current cost recovery riders and anticipated increased base electric rates. We also expect an average annual kilowatt-hour growth of approximately one percent from our existing customers, as well as up to 400 MW of additional growth from several potential new industrial customers planning projects in our service territory.

Our energy strategy is to be a leader in the movement toward renewable energy and cleaner power plants. We believe we can meet our customers’ electric energy needs for the next decade while achieving real reductions in total carbon emissions. We intend to aggressively pursue renewable energy resources and expect to comply with Minnesota’s 25 percent renewable energy mandate prior to the 2025 deadline.

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Outlook (Continued)

Energy (Continued)

Integrated Resource Plan. On October 31, 2007, Minnesota Power filed its Integrated Resource Plan (IRP), a comprehensive estimate of future capacity needs within the Minnesota Power service territory. Minnesota Power believes it can meet the estimated future customer demand for the next decade while achieving real reductions in the emission of GHGs (primarily carbon dioxide).

 

Minnesota Power plans to meet expected loads through approximately 2020 by adding a significant amount of renewable generation and some supporting peaking generation. We do not plan to add new coal generation or enter into long-term power purchase agreements from coal-based generation resources without a GHG solution. We plan to add 300 to 500 megawatts of carbon-minimizing renewable energy to our generation mix. Besides the additional generation from renewable sources, Minnesota Power anticipates future supply will come from a combination of sources, including:

 

·

"As-needed" peaking and intermediate generation facilities;

·

Expiration of wholesale contracts presently in place;

·

Short-term market purchases;

·

Improved efficiency of existing generation and power delivery assets; and

·

Expanded conservation and demand-side management initiatives.

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

Mesaba Energy Project. On August 30, 2007, the MPUC issued an order denying Excelsior Energy Inc.’s request for a power purchase agreement with Xcel Energy to sell power from the Mesaba Energy Project (Mesaba Project). We participated in the MPUC proceeding to demonstrate the unnecessary costs the Mesaba Project would cause for our ratepayers and the negative energy policy impacts of a forced resource addition. The MPUC’s August 30, 2007, order states that the MPUC will explore in IRPs and resource acquisition proceedings whether all Minnesota utilities should participate in the Mesaba Project. Beyond the fact that we forecast no need for base load energy supply additions until late in the next decade, we object to the Mesaba Project because it does not include a GHG solution.

Climate Change. A key component of our energy strategy is a goal to reduce overall GHG emissions. While there continues to be debate about the causes and extent of global warming, certain scientific evidence suggests that emissions from fossil fuel generation facilities are a contributing factor. Minnesota Power has a long history of environmental stewardship.

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

In 2007, Minnesota passed legislation establishing non-binding targets for GHG reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors producing those emissions to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025, and at least 80 percent below 2005 levels by 2050. Minnesota is also participating in the Midwestern Greenhouse Gas Accord, a regional effort to develop a multi-state approach to GHG emission reductions. We are proactively taking steps to strategically engage the GHG emission issue and the impact of climate change regulation on our business.

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

·

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

·

We will aggressively pursue Minnesota’s Renewable Energy Standard by adding significant renewable resources to our portfolio of generation facilities and power supply agreements.

·

We will continue to improve the efficiency of coal-based generation facilities.

·

We plan to implement aggressive demand side conservation efforts.

·

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

·

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

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Outlook (Continued)

Energy (Continued)

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

We have already begun executing this strategy. For more than a century, we have been Minnesota’s leading producer of renewable hydroelectric energy. By the second quarter of this year, we will have doubled our renewable generation capacity with wind additions in North Dakota and Minnesota. We will also continue to support research and development activity in carbon capture and storage technologies that will enable our industry to better manage GHG emissions associated with existing and future coal based generating assets.

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

In December 2006, we began purchasing the output from a 50-MW wind facility, Oliver Wind I, located in North Dakota, under a 25-year power purchase agreement with an affiliate of FPL Energy.

In May 2007, the MPUC approved a second 25-year wind power purchase agreement to purchase an additional 48-MW of wind energy from Oliver Wind II, an expansion of Oliver Wind I located in North Dakota. The MPUC also allowed current cost recovery for associated transmission upgrades. In November 2007, Oliver Wind II became operational and we began purchasing the output from the wind facility.

In May 2007, the MPUC approved a 20-year Community-Based Energy Development Project power purchase agreement. The 2.5-MW Wing River Wind project, with Wing River Wind, LLC, became operational July 2007.

In September 2007, the MPUC approved our site permit application and we began construction of the $50 million, 25-MW Taconite Ridge Wind I Facility, located in northeastern Minnesota. Minnesota Power filed a petition for current cost recovery on the Taconite Ridge Wind I Facility with the MPUC in August 2007. In October 2007, the DOC recommended approval of Minnesota Power’s current cost recovery filing. The MPUC hearing regarding Minnesota Power’s current cost recovery filing is currently waiting scheduling. The Taconite Ridge Wind I Facility is expected to become operational in mid-2008.

We continue to investigate additional renewable energy resources including biomass, hydroelectric and wind generation that will help us meet the Minnesota 25 percent renewable energy standard. In particular, we are conducting a feasibility study for construction of a 25-MW biomass generating unit at Laskin, as well as looking at opportunities to expand biomass energy production at existing facilities. Additionally, we are pursuing a potential 10-MW expansion of our Fond du Lac hydroelectric station. We will make specific renewable project filings for regulatory approval as needed.

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Outlook (Continued)

Energy (Continued)

 

In January 2008, Minnesota Power and Manitoba Hydro executed a term sheet for the purchase of surplus energy beginning in 2008 and an anticipated 250-MW capacity purchase to begin in about 2020. Minnesota Power anticipates the initial purchase of surplus energy will be about 100 MWs during high hydro production periods in the spring and fall. The 250-MW long-term purchase will require construction of hydroelectric facilities in Manitoba and major new transmission facilities between Canada and the United States. Minnesota Power and Manitoba Hydro have one year to complete negotiations and sign a definitive agreement. Each purchase is expected to require MPUC approval.

CapX 2020. Minnesota Power is a participant in the CapX 2020 project which represents an effort to ensure the electricity reliability of Minnesota and the surrounding region for the future. CapX 2020 started with the state's largest transmission owners, including electric cooperatives, municipals and investor-owned utilities, assessing the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region's transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

The CapX 2020 participants filed a Certificate of Need for three 345 kV lines and associated system interconnections with the MPUC in August 2007. Following a public process, the MPUC is expected to decide on the need for these 345 kV lines by early 2009. If the MPUC certifies need, it will then determine routes for the new lines in subsequent proceedings. Portions of the 345 kV lines will also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. A fourth line, a 230 kV line in north central Minnesota, is also among the CapX 2020 projects. A request for a Certificate of Need/Site Permit for this line is expected to be filed by mid-2008, with the MPUC decision on need and routing expected approximately one year later.

Minnesota Power may invest capital in two of the lines, a 250-mile 345 kV line between Fargo, North Dakota and Monticello, Minnesota, and a 70-mile 230 kV line between Bemidji and Grand Rapids, Minnesota. Our investment in these two lines would entail an estimated $60 million and $90 million, respectively. Upon receipt of the required Certificates of Need, we intend to file with the MPUC for current cost recovery of the expenditures related to our investment in the lines under a Minnesota Power transmission cost recovery tariff rider mechanism authorized by Minnesota legislation. For the utilities involved, the first four projects represent a combined investment of approximately $1.4 to $1.7 billion. Construction of the lines is targeted to begin in 2009 or 2010 and last approximately three to four years, but depends on the timing and outcome of regulatory need and routing decisions.

AREA and Boswell Unit 3 Emission Reduction Plans. In May 2006, the MPUC approved our filing for current cost recovery of expenditures to reduce emissions to meet pending federal requirements at Taconite Harbor and Laskin under the AREA Plan. The AREA Plan approval allows Minnesota Power to recover Minnesota jurisdictional costs for SO2, NOX and mercury emission reductions made at these facilities without a rate proceeding. Current cost recovery from retail customers will include a return on investment and recovery of incremental expense. The AREA Plan is expected to significantly reduce emissions from Taconite Harbor and Laskin, while maintaining a reliable and reasonably-priced energy supply to meet the needs of our customers. We believe that control and abatement technologies applicable to these plants have matured to the point where further significant air emission reductions can be attained in a relatively cost-effective manner. Current cost recovery filings are required to be made 90 days prior to the anticipated in-service date for the equipment at each unit, with rate recovery beginning the month following the in-service date.

Minnesota Power has completed installation of new equipment at Laskin and current cost recovery of AREA Plan costs has begun. The first of three Taconite Harbor unit installations was completed and placed back in-service in June 2007, with current cost-recovery began in July 2007. We anticipate cost recovery on the other Taconite Harbor units once work is completed and the units have been placed back in-service, which is expected in late 2008. As of December 31, 2007, we have spent $36 million of the anticipated $60 million in AREA Plan expenditures.

In May 2006, we announced plans to make emission reduction investments at our Boswell Unit 3 generating unit. Plans include reductions of particulate, SO2, NOX and mercury emissions to meet pending federal and state requirements. In late March 2007, the Boswell Unit 3 project received the necessary construction permits. On October 26, 2007, the MPUC issued a written order approving Minnesota Power’s petition for current cost recovery for the Boswell Unit 3 emission reduction plan with some minor modifications and additional reporting requirements. MPUC approval authorized a cash return on construction work in progress during the construction phase in lieu of AFUDC-Equity and allows for a return on investment and current cost recovery of incremental operations and maintenance expenses once the unit is placed into service in late 2009. On December 26, 2007, the MPUC approved Boswell Unit 3’s rate adjustment for 2008. As of December 31, 2007, we have spent $89 million of the anticipated $200 million in Boswell Unit 3 emission reduction plan expenditures.

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Outlook (Continued)

Energy (Continued)

Rate Cases. We have and will continue to significantly increase our rate base. On December 28, 2007, we submitted a filing with the FERC seeking to increase electric rates for our wholesale customers. On February 8, 2008, the FERC approved our wholesale rate. Our wholesale customers consist of 16 municipalities in Minnesota and two private utilities in Wisconsin, including SWL&P. The FERC authorized an average 10 percent increase for wholesale municipal customers, a 12.5 percent increase for SWL&P, and an overall return on equity of 11.25 percent. The rate increase will go into effect on March 1, 2008, and on an annualized basis, the filing will generate approximately $7.5 million in additional revenue. We also anticipate filing a retail rate case with the MPUC in mid-2008. SWL&P also anticipates filing a retail rate case with the PSCW in 2008.

Industrial Customers. Electric power is a key component in the mining, paper production and pipeline industries. Approximately 50 percent of our Regulated Utility kilowatthour sales are made to our Large Power Customers in the taconite, paper and pulp, and pipeline industries.

Based on our research of the taconite industry, Minnesota taconite production for 2008 is anticipated to be about 41.5 million tons (production was 39 million tons in 2007; 40 million tons in 2006 and 41 million tons in 2005).

The pulp and paper customers are projected to run near capacity in 2008. Capacity closures in North America and Europe, along with the strength of the Euro and Canadian dollar, should benefit Minnesota Power’s customers.

Our pipeline customers continued to operate at or above historic pumping levels during 2007 and forecast operating at record pumping levels in 2008. As Western Canadian oil sands reserves continue to develop and expand, pipeline operators served by the Company are executing expansion plans to transport additional crude oil supply to United States markets. We believe we are strategically positioned to serve these expanding pipeline facilities as Canadian supply continues to grow and displace domestic and imported Gulf Coast production.

Several natural resource-based companies have been making significant progress developing new projects in northeastern Minnesota. These potential projects are in the ferrous and non-ferrous mining, paper, oil and steel related industries. They include the Polymet Mining, Mesabi Nugget and Minnesota Steel Industry projects, as well as the Keewatin Taconite expansion. If some or all of these projects are completed, Minnesota Power could serve between 100 MW and 400 MW of new load.

In 2006, a contract for approximately 70 MW was executed with PolyMet Mining, a new customer planning to start a copper, nickel and precious metals (non-ferrous) mining operation in late 2008. If PolyMet Mining receives all necessary environmental permits and achieves start-up, the contract will be fully implemented and would run through at least 2018. In April 2007, the MPUC approved our contract with PolyMet Mining.

In June 2007, a contract was executed with Mesabi Nugget, a company currently constructing an iron nugget facility near Hoyt Lakes, Minnesota. Iron nuggets, which typically consist of more than 94 percent iron (compared to taconite pellets at 63-65 percent iron), are ideal in meeting the requirements of electric-arc furnaces producing steel. On February 7, 2008, the MPUC held a hearing on the contract and adopted a motion approving the contract, subject to the issuance of a written order. Mesabi Nugget has received all necessary permits to begin construction and operations in 2008 and would be a 15-MW customer with the potential for further load growth. The Mesabi Nugget contract would run through at least 2017.

In February 2008, United States Steel announced its intent to restart a pellet line at its Keewatin Taconite processing facility. This pellet line, which has been idled since 1980, would be restarted and updated as part of a $300 million investment. It is anticipated to bring about 3.6 million tons of additional pellet making capability to Northeastern Minnesota by 2011, pending successful approval of environmental permitting.

A new contract with Blandin Paper was approved by the MPUC on February 4, 2008. The new contract carries forward the same contract term, cancellation provision and take-or-pay provisions of the prior contract and only changed the demand nomination feature.

ALLETE 2007 Form 10-K

 

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Outlook (Continued)

Energy. (Continued)

Minnesota Fuel Clause. In June 2003, the MPUC initiated an investigation into the continuing usefulness of the fuel clause as a regulatory tool for electric utilities. Our initial comments on the proposed scope and procedure of the investigation were filed in July 2003. In November 2003, the MPUC approved the initial scope and procedure of the investigation. Subsequent comments were filed during 2004. The fuel clause docket then became dormant while the MISO Day 2 docket, which held many fuel clause considerations, became active. In March 2007, the MPUC solicited comments on whether the original fuel clause investigation should continue and, if so, what issues should be pursued. We filed comments in April 2007, suggesting that if the investigation continued, it should focus on remaining key elements of the fuel clause, beyond the purchased power transactions examined in the MISO Day 2 proceeding, such as fuel purchases and outages. Additionally, we suggested that more specialized fuel clause issues be addressed in separate dockets on an as needed basis. The DOC filed a letter requesting that the parties to the docket update the record in this proceeding by the end of September 2007. Minnesota Power complied by filing additional comments, updating our previous filings in the fuel clause investigation docket to account for changes occurring since the investigation began in July 2003. Reply comments were filed in October 2007. The fuel clause investigation docket is awaiting further action by the MPUC.

 

Fuel Clause Recovery of MISO Day 2 Costs. We filed a petition with the MPUC in February 2005 to amend our fuel clause to accommodate costs and revenue related to the day-ahead and real-time markets through which we engage in wholesale energy transactions in MISO (MISO Day 2). In December 2006, the MPUC issued an order allowing us and the other utilities involved in the MISO Day 2 proceeding to continue recovering MISO Day 2 charges through the Minnesota retail fuel clause except for MISO Day 2 administrative charges. On January 8, 2007, this order was challenged by the Minnesota OAG, through a request for reconsideration. The request was opposed by Minnesota Power and the other utilities, as well as MISO. The reconsideration request was denied by the MPUC. Upon denial of the reconsideration request, the OAG appealed the MPUC Order in a filing with the Minnesota Court of Appeals. Oral argument in the case will be held on February 27, 2008, and a decision would be expected approximately 90 days thereafter. The Company is unable to predict the outcome of this matter.

The December 2006 MPUC order, subject to appeal, granted deferred accounting treatment for three MISO Day 2 charge types that were determined to be administrative charges. Under the order, Minnesota Power refunded, through customer bills, approximately $2 million of administrative charges previously collected through the fuel clause between April 1, 2005, and December 31, 2006, and recorded these administrative charges as a regulatory asset. We were permitted to continue accumulating MISO Day 2 administrative charges after December 31, 2006, as a regulatory asset until we file our next rate case, at which time recovery for such charges will be determined. The balance of this regulatory asset was $3.7 million on December 31, 2007, and we consider regulatory recovery to be probable. This order removed the subject to refund requirement of the two interim orders, and included extensive fuel clause reporting requirements impacting our monthly and annual fuel clause filings with the MPUC. There was no impact on earnings as a result of this ruling. As a result of the MPUC’s December 2006 order allowing recovery of nearly all MISO Day 2 charges through the fuel clause, we rescinded our December 2005 Letter of Intent to Withdraw from MISO in December 2006.

Investment in ATC. Our Wisconsin subsidiary, Rainy River Energy Corporation – Wisconsin, has invested $60 million in ATC. As of December 31, 2007, our equity investment balance in ATC was $65.7 million, representing approximately an 8 percent ownership interest. (See Note 6.) We will have the opportunity to make additional investments in ATC through general capital calls based upon our pro-rata investment level in ATC. We expect to invest an additional $5 to $7 million in 2008.

Real Estate. Conditions in the Florida real estate market were very difficult in 2007. Market demand worsened throughout the year, consistent with conditions experienced throughout most of the rest of the country. While we are unable to predict when the Florida real estate market will improve, we believe the long-term growth indicators for Florida real estate remain strong.

Substantially all of our properties have key entitlements in place. With minimal leverage, low on-going carrying costs and a low inventory book basis, we expect that our Real Estate business will continue to be profitable, and an important contributor to ALLETE’s on-going earnings stream. We expect net income from Real Estate to be approximately 10 percent to 20 percent of total ALLETE consolidated net income over the next several years. We believe the northeastern Florida market area where a large portion of our real estate inventory is located will continue to experience above average long-term population growth, and our inventory of mixed-use land in those areas will remain attractive to buyers.

ALLETE Properties plans to maximize the value of the property it currently owns through entitlement, infrastructure improvements and orderly sales of properties. In addition to managing its current real estate inventory, ALLETE Properties is focused on identifying, acquiring, entitling and developing infrastructure on vacant land in Florida and other parts of the southeast United States.

ALLETE 2007 Form 10-K

 

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Outlook (Continued)

Real Estate (Continued)

Progress continues on our three major planned development projects in Florida—Town Center, a new downtown for Palm Coast; Palm Coast Park, located in northwest Palm Coast; and Ormond Crossings, located in Ormond Beach along Interstate 95. (See Item 1 – Business - Real Estate.) Other ongoing land sales and rental income at the retail shopping center in Winter Haven provide us with additional revenue.

Summary of Development Projects For the Year Ended December 31, 2007	Ownership	Total Acres (a)	Residential Units (b)	Non-residential Sq. Ft. (b, c)
Town Center	80%
At December 31, 2006		1,356	2,222	2,705,310
Property Sold		(99)	(130)	(540,059)
Change in Estimate (a)		(266)	197	62,949
		991	2,289	2,228,200
Palm Coast Park	100%
At December 31, 2006		4,337	3,760	3,156,800
Property Sold		(888)	(606)	(40,000)
Change in Estimate (a)		(13)	–	–
		3,436	3,154	3,116,800
Ormond Crossings	100%
At December 31, 2006		5,960	(d)	(d)
Change in Estimate (a)		8
		5,968
		10,395	5,443	5,345,000

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

(b)	Estimated and includes minority interest. Density at build out may differ from these estimates.

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

(d)

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

Summary of Other Land Inventories For the Year Ended December 31, 2007	Ownership	Total	Mixed Use	Residential	Non-residential	Agricultural
Acres (a)
Palm Coast Holdings	80%
At December 31, 2006		2,136	1,404	346	247	139
Property Sold		(111)	(78)	–	(14)	(19)
Change in Estimate (a)		(1,160)	(964)	(239)	96	(53)
		865	362	107	329	67
Lehigh	80%
At December 31, 2006		223	–	140	74	9
Change in Estimate (a)		6	–	–	–	6
		229	–	140	74	15
Cape Coral	100%