UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the transition period from          to          

Commission File Number: 0-6921-10499

NORTHWESTERN CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:605-978-2908605-978-2900

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

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

YesxNoo Nox

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

YesoNox

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YesxNoo

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large Accelerated Filerx           Accelerated Filero           Non-accelerated Filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YesoNox

The aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant was $1,219,000,000 computed using the last sales price of $34.35 per share of the registrant’s common stock on June 30, 2006,2007, the last business day of the registrant’s most recently completed second fiscal quarter.

As of February 23, 2007, 35,671,11122, 2008, 38,972,551 shares of the registrant’s common stock, par value $0.01 per share, were outstanding.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

YesxNoo

Documents Incorporated by Reference

NoneCertain sections of our Proxy Statement for the 2008 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K

INDEX

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Annual Report on Form 10-K regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference herein relating to management’smanagement's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates,”" “may,”" “will,”" “should,”" “believes,”" “estimates,”" “expects,”" “intends,”" “plans,”" “predicts,”" “projects,”" “targets,”" “will likely result,”" “will continue”continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management’smanagement's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that our projections will be achieved. Factors that may cause such differences include, but are not limited to:

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors”Factors" which is part of the disclosure included in Part I, Item 1A of this Report.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. Although we believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable, any or all of the forward-looking statements in this Annual Report on Form 10-K, our reports on Forms 10-Q and 8-K, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Annual Report on Form 10-K, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of a forward-looking statement in this Annual Report on Form 10-K or other public communications that we

might make as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent annual and periodic reports filed with the SEC on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

Unless the context requires otherwise, references to “we,”" “us,”" “our,”" “NorthWestern Corporation,”" “NorthWestern Energy”Energy" and “NorthWestern”“NorthWestern" refer specifically to NorthWestern Corporation and its subsidiaries. “Predecessor Company”Company" refers to us prior to emergence from bankruptcy (operations prior to October 31, 2004). “Successor Company”Company" refers to us after emergence from bankruptcy (operations after November 1, 2004).

GLOSSARY

Allowance for Funds Used During Construction (AFUDC) –-An accounting convention prescribed by the Federal Energy Regulatory Commission that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.

Ancillary Services -These services ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services may include: load regulation, spinning reserve, non-spinning reserve, replacement reserve, and voltage support.

Base-Load- The minimum amount of electric power or natural gas delivered or required over a given period of time at a steady rate. The minimum continuous load or demand in a power system over a given period of time usually is not temperature sensitive.

Base-Load Capacity- The generating equipment normally operated to serve loads on an around-the-clock basis.

Cushion Gas -The natural gas required in a gas storage reservoir to maintain a pressure sufficient to permit recovery of stored gas.

Degree DayDeregulation -A measure of the coldness / warmness of the weather experienced, based on the extent to which the daily mean temperature falls below or above a reference temperature.

Deregulation –In the energy industry, the process by which regulated markets become competitive markets, giving customers the opportunity to choose their energy supplier.

Environmental Protection Agency (EPA) –- A Federal agency charged with protecting the environment.

Federal Energy Regulatory Commission (FERC) –- The Federal agency that has jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas transmission and related services pricing, oil pipeline rates and gas pipeline certification.

Franchise -A special privilege conferred by a unit of state or local government on an individual or corporation to occupy and use the public ways and streets for benefit to the public at large. Local distribution companies typically have exclusive franchises for utility service granted by state or local governments.

Hedging –-Entering into transactions to manage various types of risk (e.g. commodity risk).

Hinshaw Exemption -A pipeline company (defined by the Natural Gas Act and exempted from FERC jurisdiction under the NGA) defined as a regulated company engaged in transportation in interstate commerce, or the sale in interstate commerce for resale, of natural gas received by that company from another person within or at the boundary of a state, if all the natural gas so received is ultimately consumed within such state. A Hinshaw pipeline may receive a certificate authorizing it to transport natural gas out of the state in which it is located, without giving up its status as a Hinshaw pipeline.

Independent Systems Operator (ISO) –- An entity that has been granted the authority by multiple utilities to operate in a non-discriminatory manner all the transmission assets of a fixed geographic area.

Montana Consumer Counsel (MCC)Lignite Coal - - A Montana state constitution established advocateThe lowest rank of coal, often referred to as brown coal, used almost exclusively as fuel for public utilitysteam-electric power generation. It has a high inherent moisture content, sometimes as high as 45 percent. The heat content of lignite ranges from 9 to 17 million Btu per ton on a moist, mineral-matter-free basis.

Mid-Columbia Electricity Price Index (Mid-C) –An electric pricing index of volume-weighted averages of specifically defined bilateral, wholesale, physical transactions. Calculations for these indexes average power transactions from Columbia, Midway, Rocky Reach, Wells, and transportation consumers, which represents them beforeWanapum/Vantage, delivery points along the Public Service Commission, state and federal courts, and administrative agencies in matters concerning public utility regulation.Columbia River.

Midcontinent Area Power Pool (MAPP) –- A voluntary association of electric utilities and other electric industry participants that acts as a regional transmission group, responsible for facilitating open access of the transmission system and a generation reserve sharing pool which provides efficient and available generation to meet regional demand.

Montana Consumer Counsel (MCC)- A Montana state constitution established advocate for public utility and transportation consumers, which represents them before the Public Service Commission, state and federal courts, and administrative agencies in matters concerning public utility regulation.

Montana Public Service Commission (MPSC) –-The state agency that regulates public utilities doing business in Montana.

Nebraska Public Service Commission (NPSC) –- The state agency that regulates public utilities doing business in Nebraska.

Open Access -Non-discriminatory, fully equal access to transportation or transmission services offered by a pipeline or electric utility.

Open Season -A period of time in which potential customers can bid for services, and during which such customers are treated equally regarding priority in the queue for service.

Peak Load –-A measure of the maximum amount of energy delivered at a point in time.

Qualifying Facility (QF) –- As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price determined by a public service commission that is intended to be equal to that which the utility would otherwise pay if it were to build its own power plant or buy power form another source.

Regional Transmission Organization (RTO) –- An independent entity, which is established to have “functional control”control" over utilities’utilities' transmission systems, in order to expedite transmission of electricity. RTO’sRTO's typically operate markets within their territories.

Securities and Exchange Commission (SEC) –- The U.S. agency charged with protecting investors, maintaining fair, orderly and efficient markets and facilitating capital formation.

South Dakota Public Utilities Commission (SDPUC)–- The state agency that regulates public utilities doing business in South Dakota.

Sub-bituminous coal-- A coal whose properties range from those of lignite to those of bituminous coal and used primarily as fuel for steam-electric power generation. Sub-bituminous coal contains 20 to 30 percent inherent moisture by weight. The heat content of sub-bituminous coal ranges from 17 to 24 million Btu per ton on a moist, mineral-matter-free basis.

Tariffs- A collection of the rate schedules and service rules authorized by a federal or state commission. It lists the rates the regulated entity will charge to provide service to its customers as well as the terms and conditions that it will follow in providing service.

Test Period -In a rate case, a test period is used to determine the cost of service upon which the utility’sutility's rates will be based. A test period consists of a base period of twelve consecutive months of recent actual operational experience, adjusted for changes in revenues and costs that are known and are measurable with reasonable accuracy at the time of the rate filing and which will typically become effective within nine months after the last month of actual data utilized in the rate filing.

Tariffs – A collection of the rate schedules and service rules authorized by a federal or state commission. It lists the rates the regulated entity will charge to provide service to its customers as well as the terms and conditions that it will follow in providing service.

Tolling Arrangement -An arrangement whereby a party moves fuel to a power generator and receives kilowatt hours (kWh) in return for a pre-established fee.

Transition Costs –-Out of market energy costs associated with the change of an industry from a regulated, bundled service to a competitive open-access service.

Transmission- Transmission or transportation is the flow of electricity from generating stations over high voltage lines to substations. The electricity then flows from the substations into a distribution network.

Western Area Power Administration (WAPA)–- One of five federal power-marketing administrations and electric transmission agencies established by Congress.

Measurements:

British Thermal Unit (Btu) –-a basic unit used to measure natural gas; the amount of natural gas needed to raise the temperature of one pound of water by one degree Fahrenheit.

Degree Day -A measure of the coldness / warmness of the weather experienced, based on the extent to which the daily mean temperature falls below or above a reference temperature.

Dekatherm –-A measurement of natural gas; ten therms or one million Btu.

Kilovolt (kV) -A unit of electrical power equal to one thousand volts.

Megawatt (MW) –- A unit of electrical power equal to one million watts or one thousand kilowatts.

Megawatt Hour (MWH) –- One million watt-hours of electric energy. A unit of electrical energy which equals one megawatt of power used for one hour.

Part I

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, is one of the largest providers ofprovides electricity and natural gas in the Upper Midwest and Northwest, servingto approximately 640,000650,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923. On February 15, 2002, we acquired1923 and have distributed electricity and natural gas transmission and distribution assets and natural gas storage assets of the formerin Montana Power Company, which have been in operation since 1912.

On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with Babcock & Brown Infrastructure Limited (BBI) under which BBI will acquire NorthWestern Corporation in an all-cash transaction. For more information on the proposed transaction, see Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Our utility operations are regulated primarily by the Montana Public Service Commission, the South Dakota Public Utilities Commission, the Nebraska Public Service Commission, and the Federal Energy Regulatory Commission. We operate our business in five reporting segments:

For additional information related to our industry segments, see Note 25 of “Notes to Consolidated Financial Statements,” included in Item 8 herein.2002.

We were incorporated in Delaware in November 1923. Our principal office is located at 125 S. Dakota Avenue,3010 W. 69^th Street, Sioux Falls, South Dakota 5710457108 and our telephone number is (605) 978-2908.978-2900. We maintain an Internet site athttp://www.northwesternenergy.com. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities and Exchange Act of 1934, as amended, along with our annual report to shareholders and other information related to us are available, free of charge, on this site as soon as reasonably practicable after we electronically file those documents with, or otherwise furnish them to, the Securities and Exchange Commission (SEC).SEC. Our Internet Website and those of our subsidiaries and the information contained therein or connected thereto are not intended to be incorporated into this Annual Report on Form 10-K and should not be considered a part of this Annual Report on Form 10-K.

We operate our business in the following reporting segments:

REGULATED ELECTRIC OPERATIONS

MontanaMONTANA

Our regulated electric utility business consists of an extensive electric transmission and distribution network. Our service territory covers approximately 107,600 square miles, representing approximately 73% of Montana’sMontana's land area, and includes a population of approximately 786,000 according to the 2000 census. We deliver electricity to approximately 322,000328,000 customers in 187 communities and their surrounding rural areas, 15 rural electric cooperatives and in Wyoming to the Yellowstone National Park. In 2006,2007, by category, residential, commercial and industrial, and other sales accounted for approximately 35%36%, 51%52%, and 14%12% of our Montana regulated electric utility revenue, respectively. We also transmit electricity for nonregulated entities owning generation facilities, other utilities and power marketers serving the Montana

electricity market. The total control area peak demand was approximately 1,644 megawatts,1,724 MWs, the average daily load was approximately 1,165 megawatts,1,186 MWs, and more than 10.210.4 millionmegawatt hours MWHs were supplied during the year ended December 31, 2006.2007.

Our Montana electric transmission system consists of approximately 7,000 miles of transmission lines, ranging from 50 to 500 kilovolts, 260kV, 272 circuit segments and approximately 125,000 transmission poles with associated transformation and terminal facilities, and extends throughout the western two-thirds of Montana from Colstrip in the east to Thompson Falls in the west. Our 500 kV transmission system, which is jointly owned, 230 kilovoltkV and 161 kilovoltkV facilities form the key assets of our Montana transmission system. Lower voltage systems, which range from 50 kilovoltskV to 115 kilovolts,kV, provide for local area service needs. We also jointly own a 500-kilovolt transmission system that is part of the Colstrip Transmission System, which transfers electricity generated from the 2,180 megawatt Colstrip generation facility to markets within the state and west of Montana. The system has interconnections with five major nonaffiliated transmission systems located in the Western Electricity Coordinating Council (WECC) area, as well as one interconnection to a nonaffiliated system that connects with the Mid-Continent Area Power Pool region. With these interconnections, we transmit power to and from diverse interstate transmission systems, including those operated by Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville

Power Administration; and the Western Area Power Administration.

Our Montana electric distribution system consists of approximately 20,70021,000 miles of overhead and underground distribution lines and approximately 335 transmission and distribution substations.

Montana’s Electric Utility Industry Restructuring and Customer Choice Act was passed in 1997, which allowed for electric customer choice and competition among electric suppliers. Although larger Montana customers have a choice with regard to electricity suppliers, we do not currently face material competition in the transmission and distribution of electricity within our service territory.Supply

Default Supply

Under Montana law,Currently, we are the permanent default supplier and are obligated to provide default supply electric service to customers who have not chosen or have not had an opportunity to choose an alternative electricity supplier. We own no regulated generation assets in Montana. Accordingly, we purchase substantially all of our Montana capacity and energy requirements for defaultelectric supply from third parties.

Our annual defaultelectric supply load requirements are slightly in excess of 700 average megawatts.MWs. We currently have under contract approximately 94 percent of the energy requirements necessary to meet our projected load requirements through June 30, 2008, with approximately 96 percent at fixed prices. For the period July 1, 2008 through June 30, 2009, we have under contract approximately 73 percent of our projected load requirements, with approximately 96 percent at fixed prices. Remaining customer load requirements are met with market purchases. Specifically, we have a seven year power purchase agreementsagreement with PPL Montana for 300 megawatts325 MWs of firm base-loadon-peak supply and 150 megawatts175 MWs of off-peak supply through June 2010 and decreasing volumes thereafter through June 2014. Our jointly owned interest in Colstrip Unit 4 supplies 90 MWs of unit-contingent, base-load energy for a term of 11.5 years, which commenced on peak energy through June 30, 2007.July 1, 2007, to meet a portion of our electric supply requirements and, in a separate agreement 21 MWs of unit contingent power for 76 months beginning March 2008. We also purchase power from 19under several QF contracts entered into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 megawattsMWs of capacity. We have additionalseveral other long and medium-term power purchase agreements including contracts for 135 megawattsMWs of wind generation 50 megawatts of gas-fired generation and 5 megawattsMWs of seasonal base-load hydro supply. In addition, our Colstrip Unit 4 division has committed to supply 90 megawatts of unit-contingent, base-load energy for a term of 11.5 years, commencing on July 1,December 2007, to meet a portion of our default supply requirements. In December 2005, we filed a biennial Electric Default Supply Resource Procurement Plan (Plan) with the MPSC. In accordance with this Plan, during 2006 we entered into new supply contracts through bilateral negotiations and a first-ever energy supply auction in Montana, that combinedMPSC which will provide approximately 50 percent of our default supply portfolio requirements beginning July 1, 2007. We currently have under contract approximately 96 percent of the energy requirements necessary to meet our projected load requirements through June 30, 2007, with approximately 74 percent at fixed prices. For the period July 1, 2007 through June 30, 2008, we have under contract approximately 83 percent of our projected load requirements, with approximately 74 percent at fixed prices. Remaining customer load requirements are met with market purchases.guide future resource acquisition activities.

Our electric supply purchases are being recovered through an electricity cost tracking process pursuant to which rates are adjusted on a monthly basis for electricity loads and electricity costs for the upcoming 12-month period. On an annual basis, rates are adjusted to include any differences in the previous tracking year’syear's actual to estimated information, for recovery in the subsequent tracking year. The MPSC reviews the prudency of our energy supply procurement activities as part of the annual tracking filing.

FERC Regulation

We are subject to the jurisdiction of, and regulation by, the FERC with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of securities, incurrence of certain long-term debt, and compliance with mandatory reliability regulations.

In Montana, we sell transmission service across our system under terms, conditions and rates defined in our Open Access Transmission Tariff (OATT), on file with FERC. We are required to provide retail transmission service in Montana under tariffs for customers still receiving “bundled" service and under the OATT for “choice" customers and other wholesale transmission customers such as cooperatives. In 2007, FERC issued Order No. 890,Preventing Undue Discrimination and Preference in Transmission Service(Order 890). FERC Order 890 contained many changes to the OATT, and a number of items which all FERC jurisdictional entities, including us, were to comply with under various time frames defined by Order 890. We met or have approved mitigation plans for each of the compliance tasks by the dates specified by FERC. In 2008, FERC expects the North American Electric Reliability Corporation (NERC) and the North American Energy Standards Board to further define and develop business practices and changes to the Open Access Same-time Information System (OASIS), which will allow for further transparency and nondiscriminatory use of the transmission system. We intend to participate in the processes under which these standards and business practices are developed, and will ultimately be subject to them once they are complete.

The Area Control Error Diversity Interchange (ADI) between the Idaho Power Company, PacifiCorp and our control areas was implemented during the first quarter of 2007. The ADI effort is expected to improve our ability to satisfy NERC required reliability criteria. Other entities in the Northwest and Southwest regions of the WECC may be joining this effort in the second quarter of 2008.

Under an agreement beginning in 2005, Idaho Power Company (Idaho Power) sold regulating reserve service to us, which in turn we used to provide service under Schedule 3 (Regulation and Frequency Response) to our customers under our OATT. Idaho Power terminated the agreement as of December 31, 2007. Upon completion of a competitive RFP process, we entered into one-year agreements with Avista Utilities and Powerex to replace the Idaho Agreement, which will allow us to

balance loads and resources within our balancing authority area on a moment-to-moment basis and to provide Schedule 3 service under our Montana OATT. Both agreements have been approved by the FERC. We are in the process of conducting an RFP for services beyond 2008. Our tariffs allow for pass-through of ancillary costs, including the regulating reserve described above.

In October 2006, we submitted a filing with FERC requesting an increase in transmission rates in Montana under our OATT. While the request is due to an increase in overall transmission costs, the rate adjustment pertains only to wholesale transmission and retail choice customers. Therefore, the portion of the requested cost increase pertaining to the remaining Montana retail customer electric supply loads, which represents approximately 70% of this increase, is subject to MPSC jurisdictional rates.

We also requested certain changes to the tariff, most notably, changing network service to a stated rate instead of a load ratio share-based charge and the inclusion of a new schedule for generation imbalance service. In December 2006, FERC issued an initial order approving our proposal to convert from load ratio share to a stated rate. The FERC accepted our proposed revisions for filing, and suspended them until May 18, 2007, at which time the rates were implemented, subject to refund. The FERC also set the proposed revisions for hearing and settlement judgment procedures. We filed settlement documents on February 15, 2008 and are awaiting FERC approval, which is expected during the first half of 2008.

MPSC Regulation

Our Montana operations are subject to the jurisdiction of the MPSC with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our operations, including when we issue, assume, or guarantee securities in Montana, or when we create liens on our regulated Montana properties.

In July 2007, we filed a request with the MPSC for an electric transmission and distribution revenue increase of $31.4 million. In December 2007, we and the MCC filed a joint Stipulation and Agreement (Stipulation) regarding the rate filing. Specific terms of the Stipulation include:

The MPSC has approved interim rates, subject to refund, beginning January 1, 2008, and we anticipate finalizing the rate case during the second quarter of 2008.

Montana's Electric Utility Industry Restructuring and Customer Choice Act was passed in 1997, which provided for deregulation and allowed for customer choice and competition among suppliers. During 2007, the Montana legislature passed House Bill 25 (HB 25), labeledThe Generation Reintegration Act, which became effective October 1, 2007. This bill largely removes the remaining remnants of deregulation from Montana Law that began in 1997 by eliminating customer choice for all customers except for the largest industrial customers using more than five MWs, and providing utilities with the ability to build and own electric generation assets that would be included in utility cost of service. In addition, the bill provides for a timely upfront approval process for electricity supply resource projects and requires carbon offsets to reduce carbon dioxide emissions.

South DakotaSOUTH DAKOTA

Our South Dakota electric utility business operates as a vertically integrated generation, transmission and distribution utility. We have the exclusive right to serve an area in South Dakota comprised of 25 counties with a combined population of approximately 99,900 according to the 2000 census. We provide retail electricity to more than 59,70060,100 customers in 110 communities in South Dakota. In 2006,2007, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 37%38%, 51%53%, 9%5% and 3%4% of our South Dakota electric utility revenue, respectively. Currently, we serve these customers principally from generation capacity obtained through our undividedjoint ownership interests in three base-load generation plants and other peaking facilities that provide us with 310 megawatts312 MWs of demonstrated capacity. In addition, we have contracted capacity with MidAmerican Energy Company (MidAmerican) for an additional 50 MWs. Peak demand was

approximately 307 megawatts,317 MWs, the average daily load was approximately 145 megawatts,154 MWs, and more than 1.21.35 million megawatt hoursMWHs were supplied during the year ended December 31, 2006.2007. We use market purchases and internal peaking generation to provide peak supply in excess of our base-load capacity.

Residential, commercial and industrial services are generally bundled packages of generation, transmission, distribution, meter reading, billing and other services. In addition, we provide wholesale transmission of electricity to a number of South Dakota municipalities, state government agencies and agency buildings. For these wholesale sales, we are responsible for the transmission of contracted electricity to a substation or other distribution point, and the purchaser is responsible for further distribution, billing, collection and other related functions. We also provide sales of electricity to resellers, primarily including power pools or other utilities. Sales to power pools fluctuate from year to year depending on a number of factors, including the availability of excess short-term generation and the ability to sell excess power to other utilities in the power pool.

Our transmission and distribution network in South Dakota consists of approximately 3,200 miles of overhead and underground transmission and distribution lines as well as 120 substations. We have interconnection and pooling arrangements with the transmission facilities of Otter Tail Power Company; Montana-Dakota Utilities Co.; Xcel Energy, Inc.; and the Western Area Power Administration. We have emergency interconnections with the transmission facilities of East River Electric Cooperative, Inc. and West Central Electric Cooperative. These interconnection and pooling arrangements enable us to arrange purchases or sales of substantial quantities of electric power and energy with other pool members and to participate in the efficiency benefits of pool arrangements.

Direct competition does not presently exist within our South Dakota service territory for the supply and delivery of electricity, except with regard to certain new large load customers.customers with demand in excess of two MWs. The SDPUC, pursuant to the South Dakota Public Utilities Act, assigned the South Dakota service territory to us effective March 1976. Pursuant to that law, we have the exclusive right, other than as previously noted, to provide fully bundled services to all present and future electric customers within our assigned territory for so long as the service provided is adequate. There have been no allegations of inadequate service since assignment in 1976. The assignment of a service territory is perpetual under current South Dakota law.

We sell a portion of the electricity generated in facilities that we own jointly into the wholesale market. We face competition from other electricity suppliers with respect to our wholesale sales. These wholesale sales are made with electricity in excess of our load requirements and are not a material part of our operating results.

ElectricityElectric Supply

Most of the electricity that we supply to customers in South Dakota is generated by power plants that we own jointly with unaffiliated parties. In addition, we have several wholly owned peaking/standby generating units at seven locations throughout our service territory. Details of our generating facilities are described further in the chart below. Each of the jointly owned plants is subject to a joint management structure. We are not the operator of any of these plants. Except as otherwise noted, we are entitled to a proportionate share of the electricity generated in our jointly owned plants and are responsible for a proportionate share of the operating expenses, based upon our ownership interest. Most of the power allocated to us from these facilities is distributed to our South Dakota customers, althoughcustomers. During periods of lower demand, electricity in 2006,excess of our load requirements are sold in the competitive wholesale market. In 2007, this was approximately 16%10% of the power was sold in the wholesale market.generated.

We have agreements with

MidAmerican Energy Company (MidAmerican) to supplyprovided 50 MWs of firm capacity during the summer months of 2007-2009 as follows: 40 megawatts in 2007; 43 megawatts in 2008;2007 and 46 megawatts in 2009. During 2006, MidAmerican provided 40 megawattswe have an agreement with them to supply firm capacity of firm capacity53 MWs and 56 MWs during the summer months. In addition,months of 2008 and 2009, respectively. MidAmerican has provided us notification that they will not extend the agreement beyond 2009 and we are currently analyzing other firm capacity resources to replace this contract. We are a member of the Midcontinent Area Power Pool (MAPP),MAPP, which is an area power pool arrangement consisting of utilities and power suppliers having transmission interconnections located in a nine-state area in the North Central region of the United States and in two Canadian provinces. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The 2006 MAPP accredited capacity was approximately 304 megawatts.

We have a resource plan that includes estimates of customer usage and programs to provide for economic, reliable and timely suppliessupply of energy. We continue to update our load forecast to identify the future electric energy needs of our customers, and we evaluate additional generating capacity requirements on an ongoing basis. This forecast shows customer peak demand growing modestly, which will result in the need to add peaking capacity in the future. However,future; however, we have adequate base-load generation capacity to meet customer supply needs in the foreseeable future.

Electric Generation Coststhrough at least 2013. We are undergoing an evaluation of our needs for base-load supply beyond that point based on our current load forecast.

Coal was used to generate approximately 99% of the electricity utilized for South Dakota operations for the year ended December 31, 2006.2007. Our natural gas and fuel oil peaking units provided the balance of generating capacity. We have no interests in nuclear generating plants. The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. Coyote is a mine-mouth generating facility. Neal #4 and Big Stone I receive their fuel supply via rail. Continuing upward pressure on coal prices and transportation costs could result in increases in costs to our customers due to mechanisms to recover fuel adjustments in our rates. The average cost, inclusive of transportation costs, by type of fuel burned is shown below for the periods indicated:

During the year ended December 31, 2006,2007, the average delivered cost per ton of fuel burned for our base-load plants was $25.87$25.49 at Big Stone I, $13.50$14.70 at Coyote and $16.67$16.39 at Neal #4. The average cost by type of fuel burned and delivered cost per ton of fuel varies between generation facilities due to differences in transportation costs and owner purchasing power for coal supply. Changes in our fuel costs are passed on to customers through the operation of the fuel adjustment clause in our South Dakota tariffs.

The Big Stone I facility currently burns sub-bituminous coal from the Powder River Basin delivered under a contract through the end of 2007, which can be extended by mutual agreement.2010. Neal #4 also receives sub-bituminous coal from the Powder River Basin delivered under multiple firm and spot contracts with terms of up to several years in duration. The Coyote facility has a contract for the supply of lignite coal that expires in 2016 and provides for an adequate fuel supply for Coyote’sCoyote's estimated economic life.

The South Dakota Department of Environment and Natural Resources has given approval for Big Stone I to burn a variety of alternative fuels, including tire-derived fuel and refuse-derived fuel. In 2006,2007, approximately 1.3% of the fuel consumption at Big Stone I was derived from alternative fuels.

Although we have no firm contract for the supply of diesel fuel or natural gas for our electric peaking units, we have historically been able to purchase diesel fuel requirements from local suppliers and have enough diesel fuel in storage to satisfy our current requirements. We have been able to use excess capacity from our natural gas operations as the fuel source for our gas peaking units.

We must pay fees to third parties to transmit the power generated at our Big Stone I, Coyote, and Neal #4 plants to our South Dakota transmission system. We have a 10-year agreement, expiring in 2011, with the Western Area Power Administration for transmission services, including transmission of electricity from Big Stone I and Neal #4 to our South Dakota service areas through seven points of interconnection on the Western Area Power Administration’sAdministration's system. Transmission services under this agreement, and our costs for such services, are variable and depend upon a number of

factors, including the respective parties’parties' system peak demand and the number of our transmission assets that are integrated into the Western Area Power Authority’sAuthority's system. In 2006,2007, our costs for services under this contract totaled approximately $4.4$5.1 million. Our tariffs in South Dakota generally allow us to pass through these transmission costs to our customers.

FERC Regulation

Our South Dakota transmission operations underlie the MISO system and are part of the WAPA Control Area. The Coyote and Big Stone I power plants, of which we are a joint owner, are connected directly to the MISO system, and we have ownership rights in the transmission lines from these plants to our distribution system. We are not participating in the MISO markets that began operation on April 1, 2005, but continue to utilize WAPA to handle our scheduling and power marketing activities. We have negotiated a settlement as a grandfathered agreement with MISO and the other Big Stone I and Coyote power plant joint owners related to providing MISO with the information it needs to operate its system, while exempting us from assignment of MISO operational costs. We are working with the other non-MISO MAPP members in developing an Independent Transmission Services Coordinator. It is still intended for MISO to provide the reliability coordinator functions for MAPP.

SDPUC Regulation

Our South Dakota operations are subject to SDPUC jurisdiction with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our operations. Our retail electric rates, approved by the SDPUC, provide several options for residential, commercial and industrial customers, including dual-fuel, interruptible, special all-electric heating, and other special rates, as well as various incentive riders to encourage business development. An adjustment clause provides for quarterly adjustment based on differences in the delivered cost of energy, delivered cost of fuel, ad valorem taxes paid and commission-approved fuel incentives. The adjustment goes into effect upon filing, and is deemed approved within 10 days after the information filing unless the SDPUC staff requests changes during that period.

REGULATED NATURAL GAS OPERATIONS

MontanaMONTANA

We distribute natural gas to approximately 174,000177,000 customers located in 105 Montana communities. We also serve several smaller distribution companies that provide service to approximately 30,000 customers. Our natural gas distribution system consists of approximately 3,8003,900 miles of underground distribution pipelines. We transmit natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. We transported natural gas volumes of approximately 38.838 billion dekatherms, and our peak capacity was approximately 314335 million dekatherms per day during the year ended December 31, 2006.2007.

Our natural gas transmission system consists of more than 2,000 miles of pipeline, which vary in diameter from two inches to 20 inches, and serve more than 130 city gate stations. We have connections in Montana with five major, nonaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, Encana and Havre Pipeline. Seven compressor sites provide more than 42,000 horsepower, capable of moving more than 314 million dekatherms per day. In addition, we own and operate a pipeline border crossing through our wholly owned subsidiary, Canadian-Montana Pipe Line Corporation.

We own and operate three working natural gas storage fields in Montana with aggregate working gas capacity of approximately 16.2 billion dekatherms and maximum aggregate daily deliverability of approximately 185195 million dekatherms. We own a fourth storage field that is no longer economically feasible as a working storage field and is being depleted at approximately 0.02 million dekatherms per day, with approximately 5347 million dekatherms of remaining reserves as of December 31, 2006.2007.

We have nonexclusive municipal franchises to transport and distribute natural gas in the Montana communities we serve. The terms of the franchises vary by community, but most are for 30 to 50 years. During the next five years, 1817 of our municipal franchises, which account for approximately 77,000 customers, are scheduled to expire. Our policy is to seek

renewal of a franchise in the last year of its term.

Montana’s Natural Gas Utility Restructuring and Customer Choice Act, which was passed in 1997, provides that a natural gas utility may voluntarily offer its customers their choice of natural gas suppliers and provide open access in Montana. Although we have opened access to our Montana gas transmission and distribution systems and gas supply choice is available to all of our natural gas customers in Montana, we currently do not face material competition in the transmission and distribution of natural gas in our Montana service areas.

DefaultNatural Gas Supply

Under an agreement with the MPSC, we provide default supply servicenatural gas to customers that have not chosen other suppliers. Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts and short-term market purchases. Our portfolio approach to natural gas supply enables us to maintain a diversified supply of natural gas sufficient to meet our supply requirements. We benefit from direct access to suppliers in the major natural gas producing regions in the United States, primarily the Rockies (Colorado), Mid-Continent, Panhandle (Texas/Oklahoma), Montana, and Alberta, Canada. These suppliers also provide us with market insight, which assists us in making procurement decisions. Our Montana natural gas supply requirements for the year ended December 31, 2006,2007, were approximately 19.419.2 million dekatherms. We have contracted with several major producers and marketers with varying contract durations to provide the necessary supply to meet ongoing requirements.

Similar to our electric supply in Montana, our gas supply purchases are recovered through a gas cost tracking process, which provides for the adjustment of rates on a monthly basis to reflect changes in gas prices. On an annual basis rates are adjusted to include any differences in the previous tracking year’syear's actual to estimated information, for recovery in the subsequent tracking year. The MPSC reviews the prudency of our procurement activities as part of this annual tracking filing.

We filed a Biennial Natural Gas Procurement Plan (Gas Plan) in December 2006. This Gas Plan provides the MPSC the blueprint we will follow in procuring natural gas supply to meet our defaultelectric supply needs and reliability requirements and the implementation of hedging strategies to reduce price volatility. The next Gas Plan will be filed in December 2008.

FERC Regulation

FERC Order No. 636 requires that all companies with interstate natural gas pipelines separate natural gas supply and production services from interstate transportation service and underground storage services. The effect of the order was that natural gas distribution companies, such as us, and individual customers purchase natural gas directly from producers, third parties and various gas-marketing entities and transport it through interstate pipelines. We have established transportation rates on our transmission and distribution systems to allow customers to have supply choices. Our transportation tariffs have been designed to make us economically indifferent as to whether we sell and transport natural gas or merely deliver it for the customer.

Our natural gas transportation pipelines are generally not subject to the jurisdiction of the FERC, although we are subject to state regulation. We conduct limited interstate transportation in Montana that is subject to FERC jurisdiction, but through a Hinshaw Exemption the FERC has allowed the MPSC to set the rates for this interstate service.

MPSC Regulation

Our Montana operations are subject to the jurisdiction of the MPSC with respect to natural gas rates, terms and conditions of service, accounting records, and other aspects of its operations.

In July 2007, we filed a request with the MPSC for a natural gas transmission, storage and distribution revenue increase of $10.5 million. In December 2007, we and the MCC filed a joint Stipulation regarding the rate filing. The specific terms of the Stipulation include an increase in base natural gas rates of $5 million. The remaining terms of the Stipulation are discussed above in the MPSC regulation section related to our Montana electric operations.

South Dakota and NebraskaSOUTH DAKOTA AND NEBRASKA

We provide natural gas to approximately 83,90084,500 customers in 5960 South Dakota communities and four Nebraska communities. We have approximately 2,200 miles of distribution gas mains in South Dakota and Nebraska. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska, and in South Dakota we sell natural gas to a number of large volume customers delivered through the distribution system of an unaffiliated natural gas utility company. In South Dakota, we also transport natural gas for twofive gas-marketing firms and two large end-user accounts, currently serving 9085 customers through our distribution systems. In Nebraska, we transport natural gas for three gas-marketing firms and one end-user account, servicing eight customers whose supply is contracted from another gas company.through our distribution system. We delivered approximately 5.315.2 million dekatherms of third-party transportation volume on our South Dakota distribution system and approximately 2.1 million dekatherms of third-party transportation volume on our Nebraska distribution system during 2006.2007.

We have nonexclusive municipal franchises to purchase, transport distribute and storedistribute natural gas in the South Dakota and Nebraska communities we serve. The maximum term permitted under Nebraska law for these franchises is 25 years while the

maximum term permitted under South Dakota law is 20 years. Our policy is to seek renewal of a franchise in the last year of its term. During the next five years, 1530 of our South Dakota and Nebraska municipal franchises, which account for approximately 41,17553,300 customers, are scheduled to expire.

In South Dakota and Nebraska, we are subject to competition for natural gas supply. In addition, competition currently exists for commodity sales to large volume customers and for delivery in the form of system by-pass, alternative fuel sources such as propane and fuel oil and, in some cases, duplicate providers. We do not face material competition from alternative natural gas supply companies in the communities we serve in South Dakota and Nebraska.

Competition in the natural gas industry may result in the further unbundling of natural gas services. Separate markets may emerge for the natural gas commodity, transmission, distribution, meter reading, billing and other services currently provided by utilities. At present, it is unclear when or to what extent further unbundling of utility services will occur.

Natural gas is used primarily for residential and commercial heating. As a result, the demand for natural gas depends

upon weather conditions. Natural gas is a commodity that is subject to market price fluctuations. Purchase adjustment clauses contained in South Dakota and Nebraska tariffs allow us to pass through increases or decreases in gas supply and interstate transportation costs on a timely basis, so we are generally allowed to pass these changes in natural gas prices through to our customers.

Natural Gas Supply

Our South Dakota natural gas supply requirements for the year ended December 31, 2006,2007, were approximately 4.85.2 million dekatherms. We have contracted with Tenaska Marketing Ventures, Inc. in South Dakota to manage transportation, storage and procurement of supply in order to minimize cost and price volatility to our customers.

Our Nebraska natural gas supply requirements for the year ended December 31, 2006,2007, were approximately 4.95.2 million dekatherms. Our Nebraska natural gas supply, storage and pipeline requirements are fulfilled primarily through a third-party contract with ONEOK Energy Marketing and Trading, LP.Services Co.

To supplement firm gas supplies in South Dakota and Nebraska, we also contract for firm natural gas storage services to meet the heating season and peak day requirements of our natural gas customers. We also maintain and operate two propane-air gas peaking units with a peak daily capacity of approximately 6,400 dekatherms.These plants provide an economic alternative to pipeline transportation charges to meet the peaks caused by customer demand on extremely cold days.

FERC Regulation

Our natural gas transportation pipelines are generally not subject to the jurisdiction of the FERC, although we are subject to state regulation. We have capacity agreements with interstate pipelines that are subject to FERC jurisdiction.

SDPUC Regulation

Our South Dakota operations are subject to the jurisdiction of the SDPUC with respect to rates, terms and conditions of service, accounting records and other aspects of our natural gas distribution operations in South Dakota. A purchased gas adjustment provision in our natural gas rate schedules permits the monthly adjustment of charges to customers to reflect increases or decreases in purchased gas, gas transportation and ad valorem taxes.

Our retail natural gas tariffs, approved by the SDPUC, include gas transportation rates for transportation through our distribution systems by customers and natural gas marketers from the interstate pipelines at which our systems take delivery to the end-user's premises. Such transporting customers nominate the amount of natural gas to be delivered daily and telemetric equipment installed for each customer monitors daily usage.

In June 2007, we filed a request with the SDPUC for a natural gas distribution revenue increase of $3.7 million. In December 2007, the SDPUC approved our settlement with SDPUC Staff related to our natural gas rate case, granting an annual revenue increase of approximately $3.1 million.

NPSC Regulation

Our natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated in Nebraska by the NPSC. High volume customers are not subject to such regulation but can file complaints if they allege discriminatory treatment. Under the State Natural Gas Regulation Act, for a regulated natural gas utility to propose a change in rates to its regulated customers, it is required to file an application for a rate increase with the NPSC and with the communities in which it serves customers. The utility may negotiate with those communities for a settlement with regard to the rate change, or it may proceed to have the NPSC review the filing and make a determination.

Since enactment of the State Natural Gas Regulation Act, our initial tariffs, representing rates in effect at the time the law was approved, have been accepted by the NPSC, and the NPSC has adopted certain rules governing the terms and conditions of service of regulated natural gas utilities. Our retail natural gas tariffs provide residential, general service and commercial and industrial options, as well as firm and interruptible transportation service. A purchased gas adjustment clause provides for adjustments based on changes in gas supply and interstate pipeline transportation costs.

In June 2007, we filed a request with the NPSC for a natural gas distribution revenue increase of $2.8 million. We and the cities chose the process described above whereby we can negotiate the settlement directly with the cities regarding the outcome of the rate case. In November, a settlement was reached between us and the cities resulting in an annual revenue increase of approximately $1.5 million. The NPSC issued an order in December approving the settlement.

UNREGULATED ELECTRIC OPERATIONS

We leasehave a 30% share ofinterest in Colstrip Unit 4, a 740 megawattMW demonstrated-capacity coal-fired power plant located in southeastern Montana. The lease term runs through December 31, 2018. Our leased interest represents approximately 222 megawattsMWs at full load. We expect to finalize the purchase of the owner participant interest inload, and was historically a portion of the Colstrip Unit 4 generating facility in the first quarter ofleased interest; however, during 2007 representing approximately 79 megawatts ofwe purchased our leased interest for approximately $39 million.$145.2 million, plus the assumption of $53.7 million of debt.

We sell the majority of our generation from Colstrip Unit 4 to Puget Sound Energy (Puget) and DB Energy Trading, LLC, (DB) under agreements expiring on December 29, 2010. When operating at full contract capacity, we deliver 97 megawattsMWs to Puget and 111 megawattsMWs to DB plus losses.

We have a separate agreement with DB to repurchase 111 megawattsMWs through December 2010, which are available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 megawatts havehas been committed to supply a portion of the Montana defaultelectric supply load through December 31, 2018. load.

We currently have approximately 132 megawatts111 MWs of uncommitted base-load capacity after December 31, 2010. Due to the base-load nature of this capacity and the fact that the northwestern region of the United States is projected to be “short”“short" of base-load capacity in 2010, we do not believe that we have a material financial risk arising from this merchant capacity. In January 2008, we retained a financial advisor to assist us in evaluating our strategic options with respect to our interest in Colstrip Unit 4.

A long-term coal supply contract with Western Energy Company provides the coal necessary to run the Colstrip facility.

UNREGULATED NATURAL GAS OPERATIONS

Our subsidiary, NorthWestern Services LLC (NSC), provides natural gas supply and management services, to approximately 70 retail choice customers in eastern South Dakota. In addition, NSC’s subsidiary, Nekota Resources LLC, (Nekota), owns and operates 88 miles of intrastate natural gas pipeline used to make retail deliveries of natural gas. In 2006, NSC managed 14.7 million dekatherms and sold approximately 6 million dekatherms of natural gas supply. We are currently evaluating our unregulated natural gas business. During the first quarter of 2007, we expect to transfer Nekota and certain customers to our regulated natural gas segment. In addition, we may seek to sell the remaining unregulated natural gas business.

Natural gas is a commodity that is subject to significant market price fluctuations. Moreover, competition currently exists for commodity sales to large volume customers and for delivery in the form of system by-pass, alternative fuel sources such as propane and fuel oil and, in some cases, duplicate providers. As a result, NSC faces material competition from alternative natural gas supply companies for certain customers.

NSC’s natural gas supply portfolio is comprised of third-party fixed-term purchase contracts and short-term market

purchases. To allow NSC to focus on more profitable transactions, certain customers have been encouraged to obtain natural gas supply from other providers.

SEASONALITY AND CYCLICALITY

Our electric and gas utility businesses are seasonal businesses, and weather patterns can have a material impact on their operating performance. Because natural gas is used primarily for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Demand for electricity is often greater in the summer and winter months for cooling and heating, respectively. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or summers in the future, these weather patterns could adversely affect our results of operations and financial condition.

REGULATION

Electric Operations

Our utility operations are subject to various federal, state and local laws and regulations affecting businesses generally, such as laws and regulations concerning service areas, tariffs, issuances of securities, employment, occupational health and safety, protection of the environment and other matters.

Federal

We are a “public utility” within the meaning of the Federal Power Act. Accordingly, we are subject to the jurisdiction of, and regulation by, the FERC with respect to the issuance of securities, incurrence of certain long-term debt, the transmission of electric energy in interstate commerce and the setting of wholesale electric rates. As such, we are required to submit annual filings of certain financial information on the FERC Form No. 1, Annual Report of Major Electric Utilities, Licensees and Others, and quarterly filings of certain financial information on the FERC Form No. 3-Q, Quarterly Financial Report of Electric Companies, Licensees, and Natural Gas Companies.

In Montana, we sell transmission service across our system under terms, conditions and rates defined in our Open Access Transmission Tariff (OATT), on file with FERC, which became effective in July 1996. We are required to provide retail transmission service in Montana under tariffs for customers still receiving “bundled” service and under the OATT for “choice” customers. In October 2006, we submitted a filing with FERC requesting an increase in transmission rates in Montana under the OATT. While the request presents a net increase of $28.8 million in overall transmission costs, the rate adjustment pertains only to wholesale transmission and retail choice customers. Therefore, the portion of the requested cost increase pertaining to the remaining Montana retail customer default supply loads, which represents approximately 70% of this increase, is subject to MPSC jurisdictional rates, and will be subject to MPSC review and approval prior to any increase in rates. Since the last FERC transmission rate adjustment, which was filed in March 1998, our cost of service has increased and the type of transmission service that we provide has changed as partial retail access has developed in Montana. The overall net effect of this filing for affected customers is expected to be an average rate increase of between 6 – 18%, depending on the type of customer.

We have also requested certain changes to the tariff, most notably, changing network service to a stated rate instead of a load ratio share-based charge and the inclusion of a new schedule for generation imbalance service. In December 2006, FERC issued an initial order approving our proposal to convert from load ratio share to a stated rate. The FERC accepted our proposed revisions for filing, and suspended them until May 18, 2007, at which time the rates may be implemented, subject to refund. The FERC also set the proposed revisions for hearing and settlement judgment procedures. We expect to complete this process by June 2007; however, we cannot currently predict the outcome.

In South Dakota, the FERC has approved our request for waiver of the requirements of FERC Order No. 889 as it relates to the “Standards of Conduct,” exempting us as a small public utility. Without the waiver, the “Standards of Conduct” would have required us to physically separate our transmission operations and reliability functions from our marketing and merchant functions.

We have been participating with other transmission owners in the Pacific Northwest in the pursuit of independent

regional transmission management by an independent entity that had been known as Grid West. Grid West was dissolved during 2006 due to lack of support. Various transmission owners continued working on some of the Grid West initiatives, believing that an incremental approach to adding new services would be a better fit for the region. As a result, we signed a contract with Idaho Power Company, PacifiCorp and British Columbia Transmission Corporation to implement Area Control Error Diversity Interchange (ADI) between the control areas. This effort may reduce the regulating reserves required for our control area and help us to meet the required Western Energy Coordinating Council (WECC) control area reliability standards. It is anticipated that ADI will be implemented during the first quarter of 2007.

Our South Dakota transmission operations underlie the MISO system and are part of the WAPA Control Area. The Coyote and Big Stone I power plants, of which we are a joint owner, are connected directly to the MISO system, and we have ownership rights in the transmission lines from these plants to our distribution system. We are not participating in the MISO markets that began operation on April 1, 2005, but continue to utilize WAPA to handle our scheduling requirements. We have negotiated a settlement as a grandfathered agreement with MISO and the other Big Stone I and Coyote power plant joint owners related to providing MISO with the information it needs to operate its system, while exempting us from assignment of MISO operational costs. We are working with the other non-MISO MAPP members in developing an Independent Transmission Services Coordinator. It is still intended for MISO to provide the reliability coordinator functions for MAPP.

On November 25, 2003, FERC issued Order No. 2004 on Standards of Conduct. In Order No. 2004, FERC adopted standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities (jointly referred to as Transmission Providers) that are subject to the gas and electric standards of conduct in Part 161 and Part 37 of FERC’s regulations, respectively. The standards of conduct govern the relationship between regulated Transmission Providers and their Energy Affiliates. We are a Transmission Provider because we are a public utility currently subject to Part 37 of FERC’s regulations. On April 9, 2004, we submitted a compliance filing under Order No. 2004 requesting the FERC to clarify and confirm that our Montana natural gas system operations do not qualify as an “Energy Affiliate” of our electric transmission operations or, in the alternative, grant us a limited waiver of the independent functioning requirements of sections 358.2 and 358.4 of the FERC’s regulations. The request for a limited waiver would allow us to (1) operate our interstate electric transmission and Montana’s intrastate natural gas distribution (and associated transmission and storage) systems in a common control center with employees trained in both areas but operating in only one discipline on any given shift, and (2) train our scheduling employees on both electric and gas systems to ensure adequate staffing during emergencies and employee vacations. On July 20, 2006, the FERC ruled, based on our representations that our gas LDC division is not engaged in any off-system sales or any of the other Energy Affiliate activities, that our LDC division meets the criteria for exemption of sections 358.3(d)(6)(v), and, therefore is not an Energy Affiliate under Order No. 2004.

We have conducted an “Open Season” for the development of new electric transmission capacity from Montana to Idaho. Although still early in the development stages, potential customers have made transmission service requests for 850 megawatts of capacity in the project. These requests can be revoked at any time by the customer up to the point of an executed service agreement between the customer and us. The customer would be responsible for the costs of development through defined FERC Tariff procedures. If successful, the process could lead to a significant transmission project for the movement of energy from Montana to the south or vice versa and would be the first large-scale bulk transmission project in our control area in nearly 20 years. On September 12, 2006, we submitted a petition for declaratory order seeking FERC approval to use a transmission rate design that allocates cost responsibility for new and expanded transmission facilities along two related but distinct transmission paths, according to the cost of the new facilities required to satisfy particular service requests. On December 22, 2006, FERC granted our petition and found that our pricing proposal is consistent with the FERC’s “Or” pricing policy. With FERC’s approval of our pricing proposal, we have begun developing “indicative” prices for the various transmission alternatives under the “Open Season” and will be meeting with the participants early in 2007 to discuss these prices. These proposed rates will be subject to review by the FERC in a future rate proceeding.

In August 2006, we entered into an Amended and Restated Interconnection Agreement with Idaho Power Company, PacifiCorp, and Avista Corporation which governs the operation and maintenance of a jointly owned 230,000-volt transmission line (commonly referred to as the “AMPS” line) that extends from the Noxon area in northwestern Montana to Treasureton in southeast Idaho. The original Interconnection Agreement was executed in 1965. The Amendment serves several purposes. First, certain provisions of the Agreement regarding resource sharing that are no longer applicable were eliminated. Second, the Amended Agreement provides for the installation of a Phase Shifting Transformer (PST) in our Mill Creek Substation near Butte, Montana. The PST is required to control power flows on the AMPS line and assure electricity reliability of the parties’ interconnected systems. NorthWestern Energy, Idaho Power Company, and PacifiCorp will own the PST, which is expected to be installed and energized in the spring of 2008. Finally, the Amended and Restated Interconnection Agreement extends the term of the original agreement by 10 years to April 2025. By its order dated

December 18, 2006, FERC accepted the Amended and Restated Interconnection Agreement for filing.

One of the principal legislative initiatives of the current administration is the adoption of comprehensive federal energy legislation. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (2005 Act). The 2005 Act includes a wide range of provisions addressing many aspects of the energy industry. Specifically, with respect to the electric utility industry, the 2005 Act includes provisions which, among other things, repeal the Public Utility Holding Company Act of 1935 (PUHCA) as of February 8, 2006, create incentives for the construction of transmission infrastructure, eliminates the statutory restrictions on ownership of qualifying facilities by electric utilities, and expand the authority of FERC to include overseeing the reliability of the bulk power system.

Montana

Our Montana operations are subject to the jurisdiction of the MPSC with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our operations. As a public utility, we are also subject to MPSC jurisdiction when we issue, assume, or guarantee securities in Montana, or when we create liens on our regulated Montana properties. As such, we are required to submit annual filings of certain financial information on our Electric, Natural Gas, and Propane Utilities.

In accordance with a 2004 stipulation and settlement agreement between NorthWestern, the MPSC and the MCC, on September 29, 2006 we submitted an informational filing to the MPSC outlining our cost of providing electric and natural gas delivery service in Montana. The informational filing is based on actual costs in 2005, adjusted for known and measurable cost changes that occurred in 2006. The filing demonstrates a revenue deficiency of approximately $29.1 million in electric rates and $12.3 million in natural gas rates; however, we did not seek a rate adjustment, as we would like the MPSC to give priority to its approval of the transaction with BBI.

Montana’s Electric Utility Industry Restructuring and Customer Choice Act (Montana Restructuring Act) enabled larger customers in Montana to choose their supplier of commodity electricity beginning on July 1, 1998, and provided that all other Montana customers would be able to choose their electric supplier during a transition period through June 30, 2007. Under this legislation, during this transition period, we were designated to serve as the “default supplier” for customers who have not chosen an alternate supplier. The Montana Restructuring Act provided for the full recovery of costs incurred in procuring default supply contracts during this transition period. Two additional electric energy bills, HB 509 and SB 247, were passed by the 2003 Montana Legislature. These bills established us as the permanent default supplier, extended the transition period to June 30, 2027, required smaller customers to remain default supply customers through the transition period, and established a specific set of requirements and procedures that guide power supply procurements and their cost recovery. Compliance with these procurement procedures should mitigate the risk of nonrecovery of our costs of acquiring electric supply.

South Dakota

Our South Dakota operations are subject to SDPUC jurisdiction with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our operations. Under the South Dakota Public Utilities Act, a requested rate increase may be implemented 30 days after the date of its filing unless its effectiveness is suspended by the SDPUC and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the SDPUC. Our electric rate schedules provide that we may pass along to all classes of customers qualified increases or decreases in costs related to fuel used in electric generation, purchased power, energy delivery costs and ad valorem taxes.

Our retail electric rates, approved by the SDPUC, provide several options for residential, commercial and industrial customers, including dual-fuel, interruptible, special all-electric heating, and other special rates, as well as various incentive riders to encourage business development. An adjustment clause provides for quarterly adjustment based on differences in the delivered cost of energy, delivered cost of fuel, ad valorem taxes paid and commission-approved fuel incentives. The adjustment goes into effect upon filing, and is deemed approved within 10 days after the information filing unless the SDPUC staff requests changes during that period.

The states of South Dakota, North Dakota and Iowa have enacted laws with respect to the siting of large electric generating plants and transmission lines. The SDPUC, the North Dakota Public Service Commission and the Iowa Utilities Board have been granted authority in their respective states to issue site permits for nonexempt facilities.

Natural Gas Operations

Federal

FERC Order No. 636 requires that all companies with interstate natural gas pipelines separate natural gas supply and production services from interstate transportation service and underground storage services. The effect of the order was that natural gas distribution companies, such as us, and individual customers purchase natural gas directly from producers, third parties and various gas-marketing entities and transport it through interstate pipelines. We have established transportation rates on our transmission and distribution systems to allow customers to have supply choices. Our transportation tariffs have been designed to make us economically indifferent as to whether we sell and transport natural gas or merely deliver it for the customer.

Our natural gas transportation pipelines are generally not subject to the jurisdiction of the FERC, although we are subject to state regulation. We conduct limited interstate transportation in Montana that is subject to FERC jurisdiction, but through a Hinshaw Exemption the FERC has allowed the MPSC to set the rates for this interstate service.

Montana

Our Montana operations are subject to the jurisdiction of the MPSC with respect to natural gas rates, terms and conditions of service, accounting records, and other aspects of its operations. As a public utility, we are also subject to MPSC jurisdiction when we issue, assume or guarantee securities in Montana, or when we create liens on our Montana properties.

South Dakota

Our South Dakota operations are subject to the jurisdiction of the SDPUC with respect to rates, terms and conditions of service, accounting records and other aspects of our natural gas distribution operations in South Dakota. Under the South Dakota Public Utilities Act, a requested rate increase may be implemented 30 days after the date of its filing unless its effectiveness is suspended by the SDPUC and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the SDPUC. A purchased gas adjustment provision in our natural gas rate schedules permits the monthly adjustment of charges to customers to reflect increases or decreases in purchased gas, gas transportation and ad valorem taxes. The adjustment goes into effect upon filing, and is deemed approved within 10 days after the information filing unless the SDPUC staff requests changes during that period.

Our retail natural gas tariffs, approved by the SDPUC, include gas transportation rates for transportation through our distribution systems by customers and natural gas marketers from the interstate pipelines at which our systems take delivery to the end-user’s premises. Such transporting customers nominate the amount of natural gas to be delivered daily and telemetric equipment installed for each customer monitors daily usage.

Nebraska

Our natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated in Nebraska by the NPSC. High volume customers are not subject to such regulation but can file complaints if they allege discriminatory treatment. Under the State Natural Gas Regulation Act, for a regulated natural gas utility to propose a change in rates to its regulated customers, it is required to file an application for a rate increase with the NPSC and with the communities in which it serves customers. The utility may negotiate with those communities for a settlement with regard to the rate change, or it may proceed to have the NPSC review the filing and make a determination. While the utility and the communities are negotiating a settlement, the utility can commence charging the requested rate, as interim rates subject to refund, 60 days after the filing of the increase request. If the utility and the communities are unable to reach a settlement, then the matter is transferred to the NPSC for its review and further proceedings. The interim rates become final and no longer subject to refund if the NPSC has not taken final action within 210 days after the matter is referred to the NPSC.

Since enactment of the State Natural Gas Regulation Act, our initial tariffs, representing rates in effect at the time the law was approved, have been accepted by the NPSC, and the NPSC has adopted certain rules governing the terms and conditions of service of regulated natural gas utilities. Our retail natural gas tariffs provide residential, general service and commercial and industrial options, as well as firm and interruptible transportation service. A purchased gas adjustment clause provides for adjustments based on changes in gas supply and interstate pipeline transportation costs.

ENVIRONMENTAL

Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. The range of exposure for environmental remediation obligations at present is estimated to range between $20.4$19.8 million to $56.1$57.0 million. As of December 31, 2006,2007, we have a reserve of approximately $34.1$32.7 million. We anticipate that as environmental costs become fixed and reliably determinable, we will seek insurance reimbursement and/or authorization to recover these in rates; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

The Clean Air Act Amendments of 1990 and subsequent amendments stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We comply with these existing emission requirements through purchase of sub-bituminous coal, and we believe that we are in compliance with all presently applicable environmental protection requirements and regulations with respect to these plants. Recent legislation has been proposed, which may require further limitations on emissions of these pollutants along with limitations on carbon dioxide, particulate matter, and mercury emissions. The recent regulatory and legislative proposals are subject to normal administrative processes, and we cannot make any prediction as to whether the proposals will pass or the impact of those actions. In November 2006, The Sierra Club sent a Notice of Intent to File a Suit to the owners, including us, of Big Stone I, asserting that it would file a lawsuit in 60 days alleging that the plant failed to obtain permits for certain projects undertaken in 1995, 2001 and 2005 and otherwise failed to comply with the Clean Air Act. The owners intend to vigorously defend against any lawsuit filed by The Sierra Club.

Coal-Fired Plants

We have a jointly owned interest in Colstrip Unit 4, a coal-fired power plant located in southeastern Montana. In addition, we are joint owners in three coal-fired plants used to serve our South Dakota customer supply demands. Citing its authority under the Clean Air Act, the EPA hashad finalized Clean Air Mercury Regulations (CAMR) that affect coal-fired plants. These regulations establishestablished a cap-and-trade program to take effect in two phases, with a first phase to begin in January 2010, and a second phase with more stringent caps to begin in January 2018. Under CAMR, each state is allocated a mercury emissions cap and is required to develop regulations to implement the requirements, which can follow the federal requirements or be more restrictive.

In February 2008 the EPA’s mercury regulations were turned down by the U.S. Court of Appeals for the District of Columbia Circuit; however, Montana has finalized its own rules more stringent rulesthan CAMR’s 2018 cap that would require every coal-fired generating plant in the state to achieve by 2010 reduction levels more stringent than CAMR’s 2018 cap. Becauseby 2010. If the Montana rules are maintained in their current form and enhanced chemical injection technologies mayare not be sufficiently developed to meet this levelthese Montana levels of reductionsreduction by 2010, there is a risk thatthen adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. We expectRecent tests have shown that it may be possible to meet the Montana mercury rules to be challenged. If those rules are overturned and we are instead required to comply with CAMR, achievement of the 2010 and 2018 requirements may be possible with more refined chemical injection technology combined with adjustments to boiler/fireball dynamics at a minimal cost. We are continuing to work with the other Colstrip owners to determine the ultimate financial impact of these new rules.

In addition to the requirements related to emissions noted above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse emissions, including a recent US Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost to us of such reductions could be significant.

Manufactured Gas Plants

Approximately $28.6$26.1 million of our environmental reserve accrual is related to manufactured gas plants. TwoA formerly operated manufactured gas plantsplant located in Aberdeen, and Mitchell, South Dakota, havehas been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. At this time, no material remediation is necessary at the Mitchell location. In January 2007, we received a letter from the South Dakota Department of Environment and Natural Resources (SD DENR) that this location is at a No Further Action Status. We are currently investigating, characterizing, and characterizinginitiating remedial actions at the Aberdeen site pursuant to work plans approved by the SD DENRSouth Dakota Department of Environment and some remedial activities commenced atNatural Resources. In 2007, we completed remediation of sediment in a short segment of Moccasin Creek that had been impacted by the Aberdeen site in 2006.former manufactured gas plant operations. Our current reserve for remediation costs at the Aberdeenthis site is approximately $15.4$12.4 million, and we estimate that approximately $13$10 million of this amount will be incurred during the next five years. During 2006, we incurred remediation costs of approximately $0.4 million.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. On March 30, 2006 and May 17, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ’sNDEQ's environmental consulting firm for Kearney and

Grand Island, respectively, and we are evaluating the results of these reports.respectively. We plan to conducthave initiated additional site investigation and assessment work at these locations in 2007.locations. At present, we cannot determine with a reasonable degree of certainty the

nature and timing of any remediation cleanuprisk-based remedial action at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the MDEQ’sMDEQ's voluntary remediation program for cleanup due to the existence of exceedences of regulated pollutants in the groundwater. We have conducted additional groundwater monitoring during 2005 at the Butte and Missoula sites and, have analyzed the data and presented it to the MDEQ. Atat this time, we believe that natural attenuation should address the problems at these sites; however, additional groundwater monitoring will be necessary. ClosureIn Helena, we continue limited operation of an oxygen delivery system implemented to enhance natural biodegradation of pollutants in the Buttegroundwater and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may be necessary to prevent certain contaminants from migrating offsite. We have evaluated the results of a pilot program meant to promote aerobic degradation of certain targeted contaminants. Further data collection is necessary to complete the evaluation and assess other remediation technologies to determine the optimal remedial technology for this site.we are currently evaluating limited source area treatment/removal options. Monitoring of groundwater at this site will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remediationrisk-based remedial action at the Helena site.

Based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and the potential to recouprecover some portion of prudently incurred remediation costs in rates, we do not expect remediation costs at these locations to be materially different from the established reserve.

Milltown Mining Waste

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three megawattMW generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’sEPA's formal Record of Decision issued on December 20, 2004). In light of this pre-Record of Decision announcement, we entered into a stipulation (Stipulation) with Atlantic Richfield, the EPA, the Department of the Interior, the State of Montana and the Confederated Salish and Kootenai Tribes (collectively, the Government Parties), which capped NorthWestern’sNorthWestern's and CFB’sCFB's collective liability to Atlantic Richfield and the Government Parties at $11.4 million. In April 2006, we released escrowed amounts of $2.5 million and $7.5 million to the State of Montana and Atlantic Richfield, respectively, in accordance with the terms of the consent decree described below. Pursuant to the terms of the consent decree, the parties expect that the remaining financial obligation of $1.4 million to the State of Montana will be covered through a combination of any refund of premium upon cancellation of the catastrophic release policy described below, and the sale or transfer of land and water rights associated with the Milltown Dam operations.

On July 18, 2005, CFBwe and weCFB executed the Milltown Reservoir superfund site consent decree, which incorporated the terms set forth in the Stipulation. The consent decree was approved by the Federal District Court for the District of Montana on February 8, 2006 and became effective on April 10, 2006. In light of the material environmental risks associated with the catastrophic failure of the Milltown Dam, we secured a 10-year, $100 million environmental insurance policy, effective May 31, 2002, to mitigate the risk of future environmental liabilities arising from the structural failure of the Milltown Dam caused by an act of God. We are obligated under the settlement to continue to maintain the environmental insurance policy until the Milltown Dam is removed during implementation of the remedy. Dam removal activities will be initiated in January of 2008.

Pursuant to the terms of the consent decree, the parties expect that the remaining financial obligation of $1.4 million to the State of Montana will be covered through a combination of any refund of premium upon cancellation of the catastrophic release policy, and the sale or transfer of land and water rights associated with the Milltown Dam operations.

Other

We continue to manage equipment containing polychlorinated biphenyl (PCB)-containing oil and equipment in accordance with the EPA’sEPA's Toxic Substance Control Act regulations. We, along with other potentially responsible parties, are currently negotiating with EPA over remediation of an oil recycling facility in Oregon to which waste oil had been transported by The Montana Power Company and others. We anticipate that these negotiations will be successfully resolved during 2007. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to performassist in performing a comprehensive evaluation of our environmental reserve. Based upon information available to our consultants at this time, we believe that the current

environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The

portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

EMPLOYEES

As of December 31, 2006,2007, we had 1,3541,351 employees. Of these, 1,0311,037 employees were in Montana and 323314 were in South Dakota or Nebraska. Of our Montana employees, 407413 were covered by six collective bargaining agreements involving five unions. Five of these agreements expire in 2008. In addition, our South Dakota and Nebraska operations had 195192 employees covered by the System Council U-26 of the International Brotherhood of Electrical Workers. This collective bargaining agreement expires in 2009. We consider our relations with employees to be in good standing.

Executive Officers

Officers are elected annually by, and hold office at the pleasure of the Board and do not serve a “term of office” as such.

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our shares or other securities.

The agreement to sell NorthWestern to BBI will be completed only if certain conditions are met, including various federal and state regulatory approvals. If the sale is not completed, then our shareholders may not be able to obtain the premium for their shares of common stock offered in the proposed transaction.

The agreement to sell NorthWestern to BBI is still subject to MPSC approval and certain other closing conditions. The inability to obtain MPSC approval or fulfill those closing conditions could result in the termination of the agreement. If the BBI transaction does not close, then our shareholders will not receive the agreed upon purchase price per share.

We have incurred, and may continue to incur, significant costs associated with outstanding litigation, and the formal investigation being conducted by the SEC relating to the restatement of our 2002 quarterly financial statements and other accounting and financial reporting matters (SEC investigation), which may adversely affect our results of operations and cash flows.

These costs, which are being expensed as incurred, have had, and may continue to have, an adverse affect on our results of operations and cash flows. Pending litigation matters are discussed in detail under the Legal Proceedings section in Note 2321 to the Consolidated Financial Statements. An adverse result in any of these matters could have an adverse effect on our business.

We are subject to extensive governmental regulations that affect our industry and our operations. Existing and changed regulations and possible deregulation have the potential to impose significant costs, increase competition and change in rates which could have a material adverse effect on our results of operations and financial condition.

Our operations are subject to extensive federal, state and local laws and regulations concerning taxes, service areas, tariffs, rates, issuances of securities, employment, occupational health and safety, protection of the environment and other matters. In addition, we are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. In the course of complying with these requirements, we may incur significant costs. If we fail to comply with these requirements, then we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted or become applicable to us and future changes in laws and regulations may have a detrimental effect on our business.

We are regulated by commissions in the states we serve. As a result, these commissions review our books and records, including energy supply contracts, which could result in rate changes or other limitations on our ability to recover costs and have a material adverse effect on our results of operations and financial condition.

Competition for various aspects of electric and natural gas services has been introduced throughout the country that will

open these markets to new providers of some or all of traditional electric utility and natural gas services. Competition could result in the further unbundling of electric utility and natural gas services as has occurred in Montana for electricity and in Montana, South Dakota and Nebraska for natural gas. Separate markets may emerge for generation, transmission, distribution, meter reading, billing and other services currently provided by electric utility and natural gas providers as a bundled service. As a result, additional competitors could become active in the generation, transmission and distribution segments of our industry.

To the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would under-recover our costs, which could adversely impact our results of operations and liquidity.

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. To the extent our energy supply costs are deemed imprudent by the MPSC or other applicable state regulatory commissions, we would under-recover our costs, which could adversely impact our results of operations. During the fourth quarter of 2005, the MCC submitted testimony alleging we were imprudent and recommending the MPSC consider disallowing portions of our forecasted electric and natural gas supply costs contained in the 2005 tracker filings. In March 2006, upon signing a stipulation with the MCC, we recognized a loss of approximately $4.3 million related to the removal of replacement costs and certain forward sales contracts from our 2005-2006 electric tracking period forecast. The stipulation settles various issues relative to our electric supply costs raised by the MCC and has been approved by the MPSC in its final order regarding our 2005 electric tracker filing. Our actual costs for the 2005-2006 tracking period were presented in our 2006 tracker filing. The MPSC suspended the 2006 electric tracker docket and will combine it with our 2007 tracker filing for processing purposes. In May 2006, the MPSC approved our 2005 annual natural gas tracker as filed.

We do not own any natural gas reserves or regulated electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, then we might be required to purchase gas and/or electricity supply requirements in the energy markets, which may not be on commercially reasonable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under recovery that would reduce our liquidity.

Our obligation to supply a minimum annual quantity of power to the Montana default supply could expose us to material commodity price risk if certain qualifying facilities (QFs) under contract with us do not supply during a time of high commodity prices, as we are required to supply any quantity deficiency.

We perform management of the QF portfolio of resources under the terms and conditions of the QF Tier II Stipulation. This Stipulation may subject us to commodity price risk if the QF portfolio does not perform in a manner to meet the annual minimum energy requirement.

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the default supply with a certain minimum amount of power at an agreed upon price per megawatt. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk, unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts.

However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to secure the quantity deficiency from other sources. Since we own no material generation in Montana, the anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility.

The value of our Colstrip Unit 4 leasehold improvements could be impaired if we are unable to obtain adequate terms on 132 megawatts of power that are not under contract after 2010.

Beginning July 1, 2007, 90 megawatts of base-load energy from Colstrip Unit 4 has been committed to supply a portion of the Montana default supply for a term of 11.5 years, commencing on July 1, 2007, at an average nominal price of $35.80 per megawatt hour. We expect that the sale of the 132 megawatts of our remaining output, which is not under contract after

2010, will be sufficient to allow us to recover the carrying value of our Colstrip Unit 4 leasehold improvements. If we are unable to sell the 132 megawatts at such a sufficient price, then the value of our Colstrip Unit 4 leasehold improvements would be materially adversely impacted.

Our jointly owned electric generating facilities and our leasehold interest in Colstrip Unit 4 are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone I Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

Seasonal and quarterly fluctuations of our business could adversely affect our results of operations and liquidity.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial condition could be adversely affected. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas.

We are subject to extensive governmental laws and regulations that affect our industry and our operations, which could have a material adverse effect on our results of operations and financial condition.

We are subject to regulation by federal and state governmental entities, including the FERC, MPSC, SDPUC and NPSC. Regulations can affect allowed rates of return, recovery of costs and operating requirements. In addition, existing regulations may be revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted or become applicable to us

and future changes in laws and regulations may have a detrimental effect on our business.

Our utility business isrates are approved by our respective commissions and are effective until new rates are approved. In addition, supply costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover costs in rates or adjustment clauses could have a material adverse effect on our results of operations, cash flows and financial position.

We are subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and liabilities.

Our utility business isWe are subject to extensive laws and regulations imposed by federal, state and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, solid waste disposal and other environmental considerations. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations. However,operations; however, possible future developments, including the promulgation of more stringent environmental laws and regulations, such as the new mercury emissions rules in Montana, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures.

In addition to the requirements related to the mercury emissions rules noted above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse emissions, including a recent US Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost to us of such reductions could be significant.

Many of these environmental laws and regulations create permit and license requirements and provide for substantial civil and criminal fines which, if imposed, could result in material costs or liabilities. We cannot predict with certainty the occurrence of private tort allegations or government claims for damages associated with specific environmental conditions. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities in order to meet future requirements and obligations under environmental laws.

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for current environmental remediation obligations is estimated to be $20.4$19.8 million to $56.1$57.0 million. We had an environmental reserve of $34.1$32.7 million at December 31, 2006.2007. This reserve was

established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or claims for damages allegedly associated with specific environmental conditions. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

A downgradeTo the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would under recover our costs, which could adversely impact our results of operations and liquidity.

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we would under recover our costs, which could adversely impact our results of operations.

We do not own any natural gas reserves or regulated electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, then we might be required to purchase gas and/or electricity supply requirements in the energy markets, which may not be on commercially

reasonable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under recovery that would reduce our liquidity.

Our obligation to supply a minimum annual quantity of power to the Montana electric supply could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to supply any quantity deficiency.

We perform management of the QF portfolio of resources under the terms and conditions of the QF Tier II Stipulation. This Stipulation may subject us to commodity price risk if the QF portfolio does not perform in a manner to meet the annual minimum energy requirement.

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the electric supply with a certain minimum amount of power at an agreed upon price per MW. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts.

However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to secure the quantity deficiency from other sources. Since we own no material generation in Montana, the anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility.

Our jointly owned regulated electric generating facilities and our joint ownership in Colstrip Unit 4 are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal for our regulated generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone I Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major regulated generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

We must meet certain credit ratings could negativelyquality standards. If we are unable to maintain an investment grade credit rating, we would be required under certain commodity purchase agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect our abilityliquidity and /or access to operate our business and/or access capital.

A downgrade of our credit ratings could adversely affect our liquidity, as counter parties could require us to post collateral. In addition, our ability to raise capital on favorable terms could be hindered, and our borrowing costs could increase.

None

NorthWestern’sNorthWestern's executive offices are located at 125 S. Dakota Avenue,3010 West 69^th Street, Sioux Falls, South Dakota 57104,57108, where we lease approximately 27,35020,000 square feet of office space, pursuant to a lease that expires on June 30, 2007.December 1, 2012.

Our principal office for our South Dakota and Nebraska operations is owned and located at 600 Market Street W., Huron, South Dakota 57350. Substantially all of our South Dakota and Nebraska facilities are owned. Our principal office for our Montana operations is owned and located at 40 East Broadway Street, Butte, Montana 59701. We own or lease other officesfacilities throughout the state of Montana, including a 20,000 square foot facility in Butte, Montana, where we provide call center customer support services and conduct customer billing and other functions.Montana.

For further information regarding our operating properties, including generation and transmission, see the descriptions included in Item 1.

We discuss details of our legal proceedings in Note 23,21, Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information is about costs or potential costs that may be material to our financial results.

No matters were submitted to a vote of our security holders during the quarter ended December 31, 2006.2007.

Part II

Our common stock, which is traded under the ticker symbol NWEC, is listed on the NASDAQ Global Select Market System. As of February 23, 2007,22, 2008, there were approximately 1,071922 common stockholders of record.

Dividends

We pay dividends on our common stock after our Board of Directors (Board) declares them. The Board reviews the dividend quarterly and establishes the dividend rate based upon such factors as our earnings, financial condition, capital requirements, debt covenant requirements and/or other relevant conditions.  Although we expect to continue to declare and pay cash dividends on our common stock in the future, we cannot assure that dividends will be paid in the future or that, if paid, the dividends will be paid in the same amount as during 2006.2007. Quarterly dividends were declared and paid on our common stock during 20062007 as set forth in the table below.

QUARTERLY COMMON STOCK PRICE RANGES AND DIVIDENDS

On February 23, 2007,22, 2008, the last reported sale price on the NASDAQ for our common stock was $36.41.$27.69.

Securities Authorized for Issuance under Equity Compensation Plans

The following table presents summary information about our equity compensation plans, including our employee incentive plan. The table presents the following data on our plans as of the close of business on December 31, 2006:2007:

For additional information regarding our stock option plans and the accounting effects of our stock-based compensation, please see Notes 3 and 1917 to our Financial Statements included in Item 8 herein.

The following selected financial data has been derived from our consolidated financial statements and should be read in conjunction with the consolidated financial statements and notes thereto and with “Management’s“Management's Discussion and Analysis of Financial Condition and Results of Operations”Operations" and other financial data included elsewhere in this report. The historical results are not necessarily indicative of results to be expected for any future period. Between September 14, 2003 and October 31, 2004, we operated as a debtor-in-possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7,Financial Reporting by Entities in Reorganization Under the Bankruptcy Code. In accordance with SOP 90-7, we applied the principles of fresh-start reporting as of the close of business on October 31, 2004. During 2003, we committed to a plan to sell or liquidate our interest in Expanets and Blue Dot and accounted for our interest in these subsidiaries as discontinued operations. In 2002, we disposed of our interest in CornerStone and accounted for the disposal as discontinued operations. Accordingly, the financial data below for 2002 has been restated.

FIVE-YEAR FINANCIAL SUMMARY

The following discussion and analysis should be read in conjunction with “Item 6 Selected Financial Data”Data" and our consolidated financial statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our industry segments, see Note 2523 of “Notes to Consolidated Financial Statements”Statements" of our consolidated financial statements, which are included in Item 8 herein. For information regarding our revenues, net income (losses) and assets, see our consolidated financial statements included in Item 8.

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, is one of the largest providers ofprovides electricity and natural gas in the Upper Midwest and Northwest, servingto approximately 640,000650,000 customers in Montana, South Dakota and Nebraska. As you read this discussion and analysis, refer to our Consolidated Statements of Income, (Loss), which present the results of our operations for 2007, 2006 2005 and 2004.2005. Following is a brief overview of highlights for 2006,2007, and a discussion of our strategy. Additional details on our results of operations follow the Critical Accounting Policies and Estimates section.

PendingHighlights

Highlights for the year ended December 31, 2007 include:

Termination of Merger Agreement with Babcock & Brown Infrastructure Limited

On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with BBI,Babcock and Brown Infrastructure Limited (BBI), an infrastructure investment company listed on the Australian Stock Exchange, under which BBI willwould acquire NorthWestern Corporation in an all-cash transaction at $37 per share. The Merger Agreement has beenWe had received all approvals necessary for the transaction, except from the MPSC. On May 22, 2007, the MPSC unanimously approved by both companies’ Boards of Directors. Our shareholders approveddirected its staff to draft an order denying the transaction. On June 25, 2007, we and BBI filed a formal joint request asking the MPSC to consider a revised proposal. In connection with our joint request to the MPSC, we and BBI agreed that if the MPSC denied the revised application, then either party in their sole discretion could terminate the Merger Agreement at our August 2, 2006 annual meeting. Agreement. On July 24, 2007, the MPSC denied the joint request and BBI terminated the Merger Agreement. The MPSC issued a final written order on July 31, 2007.

We incurred transaction related costs of approximately $1.5 million during the year ended December 31, 2007. Our total transaction related costs since inception were $15.5 million, which have been expensed as incurred.

Strategy

We are focused on growing through investing in our core utility business and earning a reasonable return on invested capital, while providing safe, reliable service. The transaction is conditioned upon a number of federalneed for additional infrastructure investment, growing customer demand for electricity and state regulatory approvals or reviews,environmental initiatives create opportunities to grow our core business. In addition, we continue to focus on enhancing our system reliability, including significant planned investments in electric transmission.

Our cash flows from operations and satisfaction of other customary closing conditions. We have received approvals or clearances from the following:existing borrowing capacity should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). In order to fund our

Due

strategic growth opportunities we will utilize available cash flow, debt capacity that would allow us to existing statutory language in South Dakota, we submitted a filingmaintain investment grade ratings (50 -55% debt to the SDPUC to determine if it has jurisdiction over the salecapital ratio), and if so,necessary additional equity financing. We will continue to target a long-term dividend payout ratio of 60 – 70 % of net income.

Rate Case Filings

As a part of our focus on earning a fair return on our utility investments, during 2007 we filed general rate cases in each of our jurisdictions. Our regulatory approach is based on filing rate requests designed to provide for transaction approval. In July,recovery of legitimate expenses and a reasonable return on investment. Following is the SDPUC filed a notice with FERC that it intended to intervene and file a protest in the federal proceedings. In October, we reached a settlement agreement under which the SDPUC will not oppose approvalcurrent status of the transaction by FERC, which includes the following provisions:each of these filings:

In December, the SDPUC determined that current state law does not allow them to exercise jurisdiction over the proposed sale.

We must still obtain theare currently awaiting FERC approval of a proposed settlement in our transmission rate case, and anticipate finalizing the MPSC. We and the intervenors have submitted testimony and additional information to the MPSC. The MPSC has set a tentative date of March 14, 2007 to commence a technical hearing on the transaction. We anticipate receiving the MPSC’s decisionrate case during the first half of 2008. Interim rates were implemented in May 2007. If so, thenThis proposed settlement would result in an annualized margin increase of approximately $3.0 million.

These rate cases are a key component of our earnings growth and achieving our financial objectives.

Investment Opportunities

We continue to make significant maintenance capital investments in our system in excess of our depreciation, which is the amount of these costs we recover through rates. This is consistent with the regulatory approach described above. See the “Capital Requirements" discussion for further detail on planned maintenance capital expenditures. In addition to this base level of capital investment, we have several other significant investment opportunities. The first step in any of these opportunities is to obtain legislative and regulatory support prior to making the investment. To avoid excessive risk for us, it is critical to reduce regulatory uncertainty before making large capital investments.

During 2007, the Montana legislature passed House Bill 25, which allows for utilities to be fully vertically integrated by owning rate base generation. As a result, we recently proposed a new natural gas-fired generation plant with an estimated cost in excess of $100 million. The plant would provide regulating reserve capacity for electric supply and assist with providing adequate regulation capacity to maintain federal reliability standards within our balancing area. We anticipate closingrequesting the transactionMPSC's approval for this plant in the second quarter of 2007.

The Merger Agreement contains certain covenants whereby NorthWestern is required to continue to operate in the ordinary course of business and must obtain BBI’s consent prior to making certain new investments or divestitures, issuing new debt or common stock or making dividend changes, among other provisions. In addition, the Merger Agreement also contains certain termination rights for both NorthWestern and BBI in which under specified circumstances NorthWestern may be required to pay BBI a termination fee of $50 million and BBI may be required to pay NorthWestern a business interruption fee of $70 million.

In November 2006, a majority of the remaining shares available under our 2005 Long-Term Incentive Plan were granted to directors, officers and employees. These service-based restricted share awards vest over the next five years; however, all unvested shares will vest immediately upon closing of the transaction with BBI. If the transaction is completed in 2007 as anticipated, stock-based compensation expense will be approximately $14 million. Upon closing, NorthWestern's common stock will cease to be publicly traded.

Other Highlights

Other highlights for the year include:

Strategy

Our primary focus during 2007 will be to complete the proposed transaction with BBI. Once the transaction is completed, we will work with BBI to refine our long-term strategy. In addition, we are currently implementing plans to build an electric transmission pathway as described below.2008.

Our Montana transmission assets are strategically located to take advantage of the potential transmission grid expansion in the Northwest part of the United States. We feel these types of FERC regulated projects would be able to provide stable and reliable returns. There are a number of potential paths and more than a dozen points of interconnection with major players in the Northwest. Regional load growth forecasts remain strong allowing us to leverage our strategic geographic advantage related to transmission. In Montana, we have begun siting and permitting work on two significant electric transmission growth opportunities - a $250 million expansion of the existing Colstrip 500 kV system that would increase capacity by 500-700 MWs and a new $800 million 500 kV transmission line from Southwestern Montana to Southeastern Idaho with a potential capacity of 1,500 MWs.

Uncertainty surrounding global climate change and environmental concerns related to new coal-fired generation development is changing the mix of the potential sources of new generation in the region. State renewable portfolio standards are increasing the region's reliance on wind generation and Montana has one of the best wind regimes in the country. Certain aspects of our proposed transmission development projects are scaleable and thus can be built out to more closely match the timing of new generation and loads.

The proposed new 500 kV transmission line between southwestern Montana and southeastern Idaho is known as the Mountain States Transmission Intertie (MSTI). The transmission line's main purpose will be to meet requests for transmission service from customers and relieve constraints on the high-voltage transmission system in the region. We have conducted an “Open Season”Open Season Process in 2004 to identify potential interest for the development of new electric transmission capacity from Montana to Idaho. Although still early in the development stages, potential customerson this path and currently we have made890 MWs of transmission service requests from open season participants for 850 megawatts of capacity inon the project.proposed new transmission line. These requests can be revoked at any time by the customer up to the point of an executed service agreement between the customer and us.agreement. The customer(s) is responsible for the costs of development through defined FERC Tariff procedures. If successful, the process could leadproposed MSTI 500 kV line will extend from a new substation to a significant transmission project for the movement of energy from be built near either Townsend or Garrison,

Montana to the existing Borah or Midpoint substation, located in southern Idaho. The new substation south or vice versaof Townsend, Montana will be adjacent to, and wouldinterconnect with, the two existing 500 kV lines between Colstrip and Garrison, Montana. An initial siting study identified several reasonable alternatives for the route and we are in the process of selecting a preferred, as well as two alternative routes. Based on our current timeline, we anticipate the line will be in service by 2013. Construction cannot commence until all local, state and federal permits/regulatory requirements are met. We have capitalized approximately $1.8 million of preliminary survey and investigative costs associated with this project as of December 31, 2007.

We have experienced continued strong organic load growth in South Dakota, including several large load additions during 2007. Due to this load growth and the first large-scale bulk transmission projecttightening of capacity markets in the MAPP region, we are evaluating the need for capacity and base-load additions in our control areaSouth Dakota service territory. Currently, we estimate the capacity need is in nearly 20 years. On September 12, 2006,the 50-75 MW range. In addition, in South Dakota and Nebraska we submitted a petition for declaratory order seeking FERC approvalexpect to use a transmission rate design that allocates cost responsibility fordeploy up to $20 million in capital over the next three years to continue pipeline extension projects to serve new and expanded transmissionethanol and biodiesel facilities along two related but distinct transmission paths, according toin the costregion. Our investment in these pipeline extension projects are protected by letters of the new facilities required to satisfy particular service requests. On December 22, 2006, FERC granted our petition and found that our pricing proposal is consistent with the FERC’s “Or” pricing policy. With FERC’s approvalcredit. During 2007, approximately $8.0 million of our pricing proposal, we have begun developing “indicative” prices for the various transmission alternatives under the “Open Season” and will be meeting with the participants earlycapital expenditures were related to growth in 2007service to discuss these prices. These proposed rates will be subject to review by FERC in a future rate proceeding.types of facilities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’sManagement's discussion and analysis of financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions, including those related to goodwill, qualifying facilities liabilities, impairment of long-lived assets and revenue recognition, among others. Actual results could differ from those estimates.

We have identified the policies and related procedures below as critical to understanding our historical and future performance, as these polices affect the reported amounts of revenue and the more significant areas involving management’smanagement's judgments and estimates.

Goodwill and Long-lived Assets

We believe that the accounting estimate related to determining the fair value of goodwill and long-lived assets, and thus any impairment, is a “critical accounting estimate”estimate" because: (i) it is highly susceptible to change from period to period since it requires company management to make cash flow assumptions about future revenues, operating costs and discount rates over an indefinite life; and (ii) recognizing an impairment could have a significant impact on the assets reported on our balance sheet and our operating results. Management’sManagement's assumptions about future sales margins and volumes require significant judgment because actual margins and volumes have fluctuated in the past and are expected to continue to do so. In estimating future margins, we use our internal budgets.

Statement of Financial Accounting Standards (SFAS) No. 142,Goodwill and Other Intangible Assets, was issued during 2001 and is effective for all fiscal years beginning after December 15, 2001. According to the guidance set forth in SFAS No. 142, we are required to evaluate our goodwill for impairment at least annually (October 1) and more frequently when indications of impairment exist. Accounting standards require that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of thean impairment loss, to recognize, we compare the implied fair value of the reporting unit’sunit's goodwill is compared with its carrying value.

We evaluate our property, plant and equipment for impairment whenever indicators of impairment exist. SFAS No. 144,Accounting for the Impairment or the Disposal of Long-Lived Assets, requires that if the sum of the undiscounted cash flows from a company’scompany's asset, without interest charges, is less than the carrying value of the asset, impairment must be recognized in the financial statements. If an asset is deemed to be impaired, then the amount of the impairment loss recognized represents the excess of the asset’sasset's carrying value as compared to its estimated fair value, based on management’smanagement's assumptions and projections.

Qualifying Facilities Liability

Certain QFsQF contracts under the Public Utility Regulatory Policy Act (PURPA) require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hourMWH through 2029. As of December 31, 2006,2007, our gross contractual obligation related to the QFs is approximately $1.6$1.5 billion. A portion of the costs incurred to purchase this energy is recoverable though rates authorized by the MPSC, totaling approximately $1.2 billion through 2029. We maintain a liability based on the net present value (discounted at 7.75%) of the difference between our estimated obligations under the QFs and the related amounts recoverable in rates. Our obligation may fluctuate substantially due to variable pricing and actual

There are ten contracts encompassed in the QF liability of which, three contracts account for more than 98% of the output. The liability was established based on certain assumptions and projections over the contract terms related to pricing, estimated output capacity utilization and recoverable amounts. The estimated capacity factor for each QF and the estimated escalation rate for one of the contracts are key assumptions. The estimated capacity factors are primarily based on historical actual capacity factors. The estimated escalation rate for the one contract was based on a combination of historical actual results and market data available for future projections. Since the liability is based on projections over a 25-year period; actual QF output, changes in pricing, contract amendments and regulatory decisions relating to QFs could significantly impact the liability and our results of operations in any given year.

In assessing the liability each reporting period, we compare our assumptions to actual results and make adjustments as necessary. Actual QF utilization, QF contract amendments and regulatory decisions relating to QFs could significantly impact the liability and our results of operations. During the first quarter of 2005, we amended one of our QF contracts, which reduced our capacity and energy rates over the term of the contract (through 2028). As a result of this amendment, we reduced our QF liability based on the new rates, resulting in a $4.9 million gain.necessary for that period.

In December 2006, the MPSC issued an order finalizing certain QF rates for the periods July 1, 2003 through June 30, 2006. The result of this order could provide for a significant reduction to our QF liability, as it reduces the escalating energy and capacity rates for one contract that we utilize in determining the present value of our obligation. If the order is upheld in its current form, we anticipate reducingcould reduce our QF liability by approximatelya range of $25 million. This order has been contested by certain QFs,million to $50 million based on our current estimated changes to the assumptions. We are currently in litigation with a QF over this matter and we cannot predict the outcome of this litigation, therefore we have not changed our historical assumptions or reduced the liability. We will continue to assess the status of the litigation and will not recognizechange our assumptions until we can determine a reduction to the liability until any appeals are exhausted. We have submitted interim rates for the period July 1, 2006 through June 30, 2007, that if approved and ultimately upheld, would result in an additional reduction to our QF liability of approximately $24 million. At December 31, 2006, our estimated QF liability was $147.9 million.probable outcome.

Revenue Recognition

Revenues are recognized differently depending on the various jurisdictions. For our South Dakota and Nebraska operations, consistent with historic treatment in the respective jurisdictions, electric and natural gas utility revenues are based on billings rendered to customers. For our Montana operations, operating revenues are recorded monthly on the basis of consumption or services rendered. Customers are billed on a monthly cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electric and natural gas services delivered to the customers but not yet billed at month-end.

Regulatory Assets and Liabilities

Our regulated operations are subject to the provisions of SFAS No. 71,Accounting for the Effects of Certain Types of Regulation. Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. If any part of our operations become no longer subject to the provisions of SFAS No. 71, then we would need to evaluate the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets.

While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. For example, we had recorded liabilities in previous years for remediation obligations related to several formerly operated manufactured gas plants (MGP) in South Dakota. In December 2007, the SDPUC approved our settlement with SDPUC Staff related to our natural gas rate case, which included a provision allowing us to include approximately $1.4 million annually in rates to recover MGP environmental clean-up costs. This was partially offset by a requirement to return approximately $2.3 million ($0.8 million annually) of previous insurance recoveries to customers. The SDPUC's approval of our settlement provides reasonable assurance that we will recover future South Dakota related MGP costs, therefore we recorded net regulatory assets (with a corresponding reduction to operating, general and administrative expenses) of $12.6 million in December 2007 to offset the previously recorded South Dakota MGP related liabilities.

Pension and Postretirement Benefit Plans

We sponsor defined benefit pension plans, which cover substantially all employees, and provide postretirement health care and life insurance benefits for certain of our employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 1816 to the consolidated financial statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics and economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, long-term nature of the obligations, and the

importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management’smanagement's best estimate of future economic conditions.

For 2006 weWe set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. ForThis is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our analysis we reviewed both the yield curve of our actuaries and Citigroup.plans. Based on this analysis, in 2007 we increased our discount rate 0.25%0.50% to 5.75%. We previously set the discount rate based upon6.25% for our review of the Citigroup Pension Index and Moody’s Aa bond rate index. Based on this analysis, we used a discount rate of 5.5% in 2005 and 2004.pension plans.

The health care cost trend rates are established through a review of actual recent cost trends and projected future trends. Our retiree medical trend assumptions are the best estimate of expected inflationary increases to our healthcare costs. Due to the relative size of our retiree population (under 700 members), the assumptions used are based upon both nationally expected trends and our specific expected trends. Our average increase remains consistent with the nationally expected trends. The long-term trend assumption is based upon our actuary’sactuary's macroeconomic forecast, which includes assumed long-term nominal gross domestic product (GDP) growth plus the expected excess growth in national health expenditures versus GDP, the assumed impact of population growth and aging, and variations by healthcare sector. Based on this review, the health care cost trend rate used in calculating the December 31, 20062007 accumulated postretirement benefit obligation was an 8%a 10% increase in health care costs in 2007 gradually decreasing each successive year until it reaches a 5.0% annual increase in health care costs in 2010.2013.

The expected long-term rate of return assumption on plan assets was determined based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension and postretirement portfolios. We target an asset allocation of roughly 70% equity securities, and 30% fixed-income securities. Considering this information and future expectations for asset returns, we decreased our expected long-term rate of return on assets assumption from 8.5% during 2005 to 8.00% for 2006.2006 and 2007. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.50% for union and 3.57% – 3.64%3.58% - 3.61% for nonunion employees in 2006.2007.

Cost Sensitivity

The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):

Accounting MechanismsTreatment

In accordance with SFAS No. 158,Employers’Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, which is effective for us as of December 31, 2006, and SFAS No. 87,Employers’Employers' Accounting for Pensions,we utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. SFAS No. 158 also requires that a plan’splan's funded status be recognized as an asset or liability. Through fresh-start reporting in 2004 we had previously recorded the funded status of our plans on the balance sheet, and adjusted our

qualified pension and other postretirement benefit plans to their projected benefit obligation by recognition of all previously unamortized actuarial gains and losses. Therefore, we recognized all prior service costs, and net actuarial gains and losses from 2005 and 2006 as of December 31, 2006.

As our regulated operations are subject to the provisions of SFAS No. 71, our financial statements reflect the effects of the different rate making principles followed by the jurisdiction regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service. In 2005, the MPSC authorized the recognition of pension costs based on an average of the funding to be made over a 5-year period for the calendar years 2005 through 2009.

Income Taxes

Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We currently estimate that as of December 31, 2006,2007, we have approximately $420$346 million of consolidated net operating loss carryforwards (CNOLs) to offset federal taxable income in future years. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our consolidated statement of operations and provision for income taxes.

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes (FIN(FIN 48). FIN 48 is an interpretation of FASB Statement No. 109,Accounting for Income Taxes, and it seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes by prescribing a recognition threshold and measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance on the derecognition, classification, accounting in interim periods and expanded disclosure with respect to the uncertainty in income taxes. FIN 48 iswas effective for us as of January 1, 2007. We are currently in process of reviewing our uncertain tax positions to determine the impact to our financial statements. FIN 48 provides that a tax position that meets the more-likely-than-not threshold shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Based onAs a result of the implementation of FIN 48, we increased our preliminary assessment, during the first quarter of 2007, we expect to increase our net deferred tax assets by $70$77.5 million to $90and decreased other noncurrent liabilities by $2.4 million, with a corresponding decrease to goodwill. The decrease to goodwill is consistent with the guidance in FASB Statement No. 109,Accounting for Income Taxes, and the requirements of fresh-start reporting, as our uncertain tax positions relate to periods prior to our emergence from bankruptcy. We have unrecognized tax benefits of approximately $111.1 million as of December 31, 2007. The resolution of tax matters in a particular future period could have a material impact on our cash flows, results of operations and provision for income taxes.

RESULTS OF OPERATIONS

The following is a summary of our results of operations in 2007, 2006, 2005, and 2004.2005. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment.

Factors Affecting Results of Continuing Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Weather affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity. The weather’sweather's effect is measured using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily actual temperature is less than the baseline. Cooling degree-days result when the average daily actual temperature is greater than the baseline. The statistical weather information provided in our regulated segments represents a comparison of these degree-days.

OVERALL CONSOLIDATED RESULTS

Year Ended December31, 2007 Compared with Year Ended December31, 2006

Consolidated gross margin in 2007 was $531.7 million, an increase of $12.6 million, or 2.4%, from gross margin in 2006.

A substantial portion of the increase in 2007 regulated margins relates to a change in presentation of property taxes collected through our Montana property tax tracker. In 2007, margins in our regulated electric and natural gas segments increased by $11.5 million related to collections through our Montana property tax tracker. In 2006, we netted comparative property tax tracker collections of $7.8 million against property and other taxes. Additional increases in our regulated margin primarily related to customer growth and favorable weather. In addition, we had higher transmission revenues due to our interim rate increase (subject to refund) and increased transmission of energy acquired by others across our system. Offsetting these increases were decreases in unregulated electric margin due to lower average contracted prices and higher fuel supply costs, partially offset by an increase in volumes resulting from higher demand and plant availability.

Consolidated operating, general and administrative expenses were $221.6 million in 2007 as compared to $240.2 million in 2006.

The reduction in operating, general and administrative expenses of $18.6 million was primarily due to the following:

Offsets to these reductions include the following:

In addition to the $11.1 million decrease in 2007, we expect operating lease expense to decrease another $14.4 million in 2008.

Property and other taxes were $87.6 million in 2007 as compared to $74.2 million in 2006. Property and other taxes in 2006 are net of $7.8 million that we collected through our Montana property tax tracker, as discussed in the gross margin analysis above. In addition, property and other taxes increased by approximately $5.6 million during 2007.

We have seen significant increases in our Montana property taxes since 2003 due primarily to increasing valuation assessments of our property by the Montana Department of Revenue. We have protested approximately $16.6 million, $16.3 million and $11.6 million of our 2007, 2006 and 2005 property taxes, respectively, and are currently appealing our 2005 valuation in Montana state court. We have recognized our property tax expense based on the total amount billed (including amounts protested), so if we are successful with our appeal, we will recognize a reduction of property tax expense in the period the appeal is resolved. Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover these amounts in rates; however the MPSC has only authorized recovery of approximately 60% of this increase for the last three years. We disputed the MPSC's decision in Montana District Court, and during the first quarter of 2007, the District Court ruled in the MPSC's favor. We did not appeal the decision. We have recognized property tax expense based on the 60% recovery previously approved by the MPSC; therefore, this ruling did not impact our expense recognition.

Depreciation expense was $82.4 million in 2007 as compared with $75.3 million in 2006. This $7.1 million increase was primarily due to increased property in service and a $2.0 million increase due to our purchase of our previously leased interest in Colstrip Unit 4. We expect annual depreciation expense to increase by $4.4 million in 2008 in addition to the $2.0 million in 2007 due to this purchase.

In February 2007, a jury verdict was rendered against us in Montana state court, which ordered us to pay $17.4 million in compensatory and $4.0 million in punitive damages in a case calledAmmondson, et al. v. NorthWestern Corporation, et al. Due to the verdict, we recognized a loss of $19.0 million in our 2006 results of operations to increase our recorded liability related to this claim.

Consolidated operating income in 2007 was $140.1 million, as compared with $110.4 million in 2006. This $29.7 million increase was primarily due to the $12.6 million increase in gross margin and lower operating expenses as discussed above.

Consolidated interest expense in 2007 was $56.9 million, an increase of $0.9 million, or 1.6%, from 2006. We expect interest expense to increase by approximately $8.2 million in 2008 as a result of the additional debt related to the purchase of our previously leased interest in Colstrip Unit 4. See “Liquidity and Capital Resources" for additional information regarding our refinancing activities.

Consolidated other income in 2007 was $2.4 million, a decrease of $6.7 million from 2006. This decrease was primarily due to the inclusion in 2006 results of gains of $3.9 million related to an interest rate swap and $2.3 million on the sale of a partnership interest in oil and gas properties.

Consolidated income tax expense in 2007 was $32.4 million as compared with $25.9 million in 2006. Our effective tax rate for 2007 was 37.8% as compared to 40.9% for 2006. Portions of our BBI transaction related costs were considered non-deductible for taxes in 2006; however, with the termination of the agreement these costs became deductible, resulting in a reduction to our tax expense of approximately $1.2 million in 2007. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Consolidated net income in 2007 was $53.2 million compared with $37.9 million for the same period in 2006. This increase was primarily due to higher operating income as discussed above, partially offset by lower other income and increased income tax expense.

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005