NWEC Northwestern (MM)

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 650,000 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 and have distributed electricity and natural gas in Montana since 2002.

We were incorporated in Delaware in November 1923. Our principal office is located at 3010 W. 69 ^th Street, Sioux Falls, South Dakota 57108 and our telephone number is (605) 978-2900. We maintain an Internet site at http://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 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

MONTANA

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's land area, and includes a population of approximately 786,000 according to the 2000 census. We deliver electricity to approximately 328,000 customers in 187 communities and their surrounding rural areas, 15 rural electric cooperatives and in Wyoming to the Yellowstone National Park. In 2007, by category, residential, commercial and industrial, and other sales accounted for approximately 36%, 52%, and 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 1,724 MWs, the average daily load was approximately 1,186 MWs, and more than 10.4 million MWHs were supplied during the year ended December 31, 2007.

Our Montana electric transmission system consists of approximately 7,000 miles of transmission lines, ranging from 50 to 500 kV, 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 kV and 161 kV facilities form the key assets of our Montana transmission system. Lower voltage systems, which range from 50 kV to 115 kV, provide for local area service needs. 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

8

Power Administration; and the Western Area Power Administration.

Our Montana electric distribution system consists of approximately 21,000 miles of overhead and underground distribution lines and approximately 335 transmission and distribution substations.

Electric Supply

Currently, we own no regulated generation assets in Montana. Accordingly, we purchase substantially all of our Montana capacity and energy requirements for electric supply from third parties. Our annual electric supply load requirements are slightly in excess of 700 average 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 agreement with PPL Montana for 325 MWs of on-peak supply and 175 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 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 under several QF contracts entered into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 MWs of capacity. We have several other long and medium-term power purchase agreements including contracts for 135 MWs of wind generation and 5 MWs of seasonal base-load hydro supply. In December 2007, we filed a biennial Electric Default Supply Resource Procurement Plan with the MPSC which will 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'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

9

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), labeled The 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 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 60,100 customers in 110 communities in South Dakota. In 2007, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 38%, 53%, 5% and 4% of our South Dakota electric utility revenue, respectively. Currently, we serve these customers principally from generation capacity obtained through our joint ownership interests in three base-load generation plants and other peaking facilities that provide us with 312 MWs of demonstrated capacity. In addition, we have contracted capacity with MidAmerican Energy Company (MidAmerican) for an additional 50 MWs. Peak demand was

10

approximately 317 MWs, the average daily load was approximately 154 MWs, and more than 1.35 million MWHs were supplied during the year ended December 31, 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 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.

Electric 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. During periods of lower demand, electricity in excess of our load requirements are sold in the competitive wholesale market. In 2007, this was approximately 10% of the power generated.

11

MidAmerican provided 50 MWs of firm capacity during the summer months of 2007 and we have an agreement with them to supply firm capacity of 53 MWs and 56 MWs during the summer 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 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.

We have a resource plan that includes estimates of customer usage and programs to provide for economic, reliable and timely supply 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, we have adequate base-load generation capacity to meet customer supply needs through 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, 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, 2007, the average delivered cost per ton of fuel burned for our base-load plants was $25.49 at Big Stone I, $14.70 at Coyote and $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 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'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 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's system. Transmission services under this agreement, and our costs for such services, are variable and depend upon a number of

12

factors, including the respective parties' system peak demand and the number of our transmission assets that are integrated into the Western Area Power Authority's system. In 2007, our costs for services under this contract totaled approximately $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

MONTANA

We distribute natural gas to approximately 177,000 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 3,900 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 billion dekatherms, and our peak capacity was approximately 335 million dekatherms per day during the year ended December 31, 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 195 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 47 million dekatherms of remaining reserves as of December 31, 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, 17 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.

13

Natural Gas Supply

Under an agreement with the MPSC, we supply natural 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, 2007, were approximately 19.2 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'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 electric 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 NEBRASKA

We provide natural gas to approximately 84,500 customers in 60 South Dakota communities and four Nebraska communities. We have approximately 2,200 miles of distribution gas mains in South Dakota and Nebraska. In South Dakota, we also transport natural gas for five gas-marketing firms and two large end-user accounts, currently serving 85 customers through our distribution systems. In Nebraska, we transport natural gas for three gas-marketing firms and one end-user account, servicing eight customers through our distribution system. We delivered approximately 15.2 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 2007.

We have nonexclusive municipal franchises to purchase, transport and distribute 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

14

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, 30 of our South Dakota and Nebraska municipal franchises, which account for approximately 53,300 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, 2007, were approximately 5.2 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, 2007, were approximately 5.2 million dekatherms. Our Nebraska natural gas supply, storage and pipeline requirements are fulfilled primarily through a third-party contract with ONEOK Energy 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.

15

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 have a 30% interest in Colstrip Unit 4, a 740 MW demonstrated-capacity coal-fired power plant located in southeastern Montana. Our interest represents approximately 222 MWs at full load, and was historically a leased interest; however, during 2007 we purchased our leased interest for approximately $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 MWs to Puget and 111 MWs to DB plus losses. We have a separate agreement with DB to repurchase 111 MWs through December 2010, which has been committed to supply a portion of the Montana electric supply load.

We currently have approximately 111 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" 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.

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.

16

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 $19.8 million to $57.0 million. As of December 31, 2007, we have a reserve of approximately $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.

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 had finalized Clean Air Mercury Regulations (CAMR) that affect coal-fired plants. These regulations established 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 than CAMR’s 2018 cap that would require every coal-fired generating plant in the state to achieve reduction levels by 2010. If the Montana rules are maintained in their current form and enhanced chemical injection technologies are not sufficiently developed to meet these Montana levels of reduction by 2010, then adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. Recent tests have shown that it may be possible to meet the Montana rules 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 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 $26.1 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. In 2007, we completed remediation of sediment in a short segment of Moccasin Creek that had been impacted by the former manufactured gas plant operations. Our current reserve for remediation costs at this site is approximately $12.4 million, and we estimate that approximately $10 million of this amount will be incurred during the next five years.

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's environmental consulting firm for Kearney and

17

Grand Island, respectively. We have initiated additional site investigation and assessment work at these locations. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-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's voluntary remediation program for cleanup due to exceedences of regulated pollutants in the groundwater. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the problems at these sites; however, additional groundwater monitoring will be necessary. In Helena, we continue limited operation of an oxygen delivery system implemented to enhance natural biodegradation of pollutants in the groundwater and 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 risk-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 recover 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 MW 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'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's and CFB'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.

On July 18, 2005, we and CFB 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) oil in accordance with the EPA's Toxic Substance Control Act regulations. 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 assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available 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

18

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

19

EMPLOYEES

As of December 31, 2007, we had 1,351 employees. Of these, 1,037 employees were in Montana and 314 were in South Dakota or Nebraska. Of our Montana employees, 413 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 192 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.

20

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