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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2002

OR

For the transition period from                                      to                                     .

Commission File Number: 0-692

NORTHWESTERN CORPORATION
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: 605-978-2908

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

Securities registered under Section 12(g) of the Act:

Preferred Stock, Par Value $100
(Title of Class)

        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. Yes ý    No o

        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. ý

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ý    No o

        As of June 28, 2002, the aggregate market value of the voting common stock held by non-affiliates of the registrant was $464,375,116, computed using the last sales price of $16.95 per share of the registrant's common stock on June 28, 2002, the last business day of the registrant's most recently completed second fiscal quarter, as reported by the New York Stock Exchange.

        As of April 7, 2003, 37, 396,762 shares of the registrant's common stock, par value $1.75 per share, were outstanding.

Documents Incorporated by Reference

None

NORTHWESTERN CORPORATION
FORM 10-K
INDEX

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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 herein relating to management'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," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "targets," "will likely result," "will 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 we believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that our expectations will be achieved. Factors that may cause such differences include:

•

our success in implementing our turnaround plan, which is dependent upon receiving significant proceeds from the sale of non-core assets;



•

if we are unable to significantly reduce our debt, restructure our debt or obtain additional capital, our ability to fund our operations and service our substantial indebtedness will be adversely affected;



•

risks regarding the class action lawsuit relating to the disposition of the energy assets by The Montana Power Company, including the acquisition of our Montana utility;



•

the risk of litigation or regulatory action in connection with the restatement of our quarterly reports for fiscal 2002;



•

our ability to fully address and correct inadequacies or material weaknesses in our internal controls and to thereafter maintain effective systems of internal controls;



•

the risk of disruption of Expanets' business, including the loss of key employees, customers and suppliers, and reduction in the value of such business and its assets as a result of our efforts to sell or dispose of Expanets, or its assets, and our limited ability to provide further funds to such business;



•

adverse federal, state, or local legislation or regulation or adverse determinations by regulators;



•

unscheduled generation outages, maintenance or repairs;



•

unanticipated changes in commodity prices or in fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments;



•

the risk of vendors requiring additional credit support, including letters of credit, or other constraints on trade credit;



•

increases in interest rates;



•

the rate of growth and economic conditions in our service territories;



•

changes in general economic and competitive conditions in the markets in which we may compete; and



•

risks regarding business uncertainties related to the occurrence of natural disasters, war, hostilities and the threat of terrorist actions.

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        We have attempted to identify, in context, certain of the factors that we believe may cause actual future experiences and results to differ materially from our current expectation regarding the relevant matter of 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" which is a part of the disclosure included in Item 7 of this report on Form 10-K entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations."

        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 and other materials 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 report on Form 10-K, our reports on Forms 10-Q and 8-K, 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 inaccurate assumptions or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this 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 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 periodic reports filed with the Commission on Forms 10-Q and 8-K and Proxy Statements on Schedule 14A.

        Unless the context requires otherwise, references to "we," "us," "our," "NorthWestern Corporation" and "NorthWestern" refer specifically to NorthWestern Corporation and its subsidiaries and references to "NorthWestern Energy LLC" refer to NorthWestern Energy, L.L.C., our wholly-owned subsidiary.

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Part I

ITEM 1. BUSINESSES

OVERVIEW

        NorthWestern Corporation is one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 598,000 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 through our energy division, NorthWestern Energy, formerly NorthWestern Public Service. In February 2002, we completed the acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company for $478 million in cash and the assumption of $511 million in existing debt and mandatorily redeemable preferred securities of subsidiary trusts of The Montana Power Company, net of cash received. As a result of the acquisition, from February 15, 2002, the closing date of the acquisition, through November 15, 2002, we distributed electricity and natural gas in Montana through our wholly owned subsidiary, NorthWestern Energy LLC. Effective November 15, 2002, we transferred all of the energy and natural gas transmission and distribution operations of NorthWestern Energy LLC to NorthWestern Corporation and since that date, we have operated that business as part of our NorthWestern Energy division. We are operating our utility business under the common name "NorthWestern Energy" in all our service territories.

        We operate our business in five reporting segments:

•

electric utility operations;

•

natural gas utility operations;

•

communications;

•

heating, ventilation and air conditioning, or HVAC, and plumbing related services; and

•

all other, which primarily consists of our other miscellaneous service and non-energy related operations and activities that are not included in the other identified segments, together with the unallocated corporate costs and investments, and any eliminating amounts.

For additional information related to our industry segments, see Note 23 of "Notes to Consolidated Financial Statements," included in Item 8 herein.

        We also have made significant investments in three non-energy businesses:

•

Expanets, Inc., or Expanets, a provider of networked communications and data services and solutions to medium sized businesses nationwide:

•

Blue Dot Services Inc., or Blue Dot, a nationwide provider of air conditioning, heating, plumbing and related services; and

•

CornerStone Propane Partners, L.P., or CornerStone, a publicly traded limited partnership (OTC: CNPP.PK) that is a retail propane and wholesale energy related commodities distributor.

        Our experience with our non-energy businesses has been very disappointing. They have adversely impacted our overall results of operations, financial condition and liquidity for the past three years. See Note 23 of "Notes to Consolidated Financial Statements," included in Item 8 herein. We have written off our investment in CornerStone and have written off substantially all of our investments in Expanets and Blue Dot. In particular, Expanets has suffered from the continued deterioration of business in the telecommunications markets and billings and collections problems caused by the problems encountered

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during the conversion to its EXPERT enterprise system. During 2002, we recorded the following charges aggregating approximately $878.5 million:

        We have incurred a significant amount of debt as a result of the investments we made in Expanets, Blue Dot, and CornerStone and our purchase of the electric and natural gas transmission and distribution business formerly owned by The Montana Power Company. At December 31, 2002, we had a common stockholders' deficit of $456.1 million and currently have $2.2 billion in debt and trust preferred instruments outstanding. The performance of Expanets, Blue Dot, and CornerStone has not met our expectations. It has become increasingly apparent that we will never recover our investments in these entities and that these entities will not generate cash flows in sufficient amounts to provide meaningful contributions to our debt service.

        In February 2003, we closed and received funds from a $390.0 million senior secured term loan. The net proceeds of $366.0 million, after payment of financing fees and costs, were used to repay approximately $260 million of outstanding debt and accrued interest and retire approximately $20 million of outstanding letter-of-credit commitments under our existing $280 million bank credit facility. The remaining proceeds will be used to provide working capital and for general corporate purposes.

        Also in February 2003, we outlined the elements of a turnaround plan that we are implementing. We will return our focus to our core utility business. We propose to sell or dispose of our non-core assets, including Expanets, Blue Dot, the Montana First Megawatts generation project, and several other smaller investments we have made and to enforce our sale of our Colstrip Transmission Line. We no longer hold a direct or indirect economic equity interest in CornerStone; accordingly, the results of CornerStone's operations are no longer reflected in our financial statements. We have told Expanets and Blue Dot that they must become financially independent from us. We are unwilling to provide additional financial support to Blue Dot or Expanets and the Montana Public Service Commission will not let us make advances of more than $10 million in the aggregate to our non-regulated businesses without their prior approval. To the extent possible under our senior secured term loan, we intend to use any proceeds from sales of non-core assets to reduce our debt.

        Our senior secured term loan contains certain restrictions on the sale or disposition of assets, including non-core assets, and on the prepayment of the senior secured term loan and our other indebtedness. However, in the event of the sale of non-core or other assets having a fair market value of less than 10% of the value of the consolidated tangible assets of our utility business as of December 17, 2002, the reference date for the senior secured term loan, we must first offer the net proceeds of such sale to our lenders and, if such offer is rejected, we may use such proceeds to prepay other indebtedness. If we are unable to prepay debt as a result of these or other restrictions, we intend to retain the proceeds of any sale of non-core assets, or surplus cash, until the maturity date of such debt, at which time those funds would be applied to such debt.

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        For our utility only operations, which excludes Blue Dot, Expanets, and all other unregulated entities, and absent proceeds from the sale of non-core assets, we estimate the following for the years 2003 and 2004 ($ are approximate and in millions):

(1)

The 2003 amount includes a net decrease in working capital of approximately $45 million and interest payments of approximately $140 million. The 2004 amount includes a net decrease in working capital of approximately $15 million and interest payments of approximately $140 million.

(2)

These amounts are comprised of capital expenditures.

(3)

The 2003 amount represents the net total of our currently anticipated financing activities for 2003 and is comprised of the following:

We have the right to defer payment of our trust preferred dividend payments for up to 20 consecutive quarters. The 2004 amount includes trust preferred dividend payments of approximately $30 million, and other debt payments of approximately $9 million.

        Based on our current plans and business conditions, we expect that our available cash, cash equivalents and investments, together with amounts generated from operations, will be sufficient to meet our cash requirements for at least the next twelve months. However, due to a decrease in cash and cash equivalents during 2004, we believe that we may need additional funding sources or proceeds from the sale of non-core assets, by the end of 2004 or early in 2005. Commencing in 2005, we face substantial debt reduction payments. Absent the receipt of significant proceeds from the sale of non-core assets, the raising of additional capital or a restructuring of our debt, we will not have the ability to reduce our debt or meet our maturing debt obligations. Even if we are successful in selling some or all of our non-core assets, we will have to restructure our debt or seek new capital.

        We have advised our Audit Committee of our Board of Directors that in the course of our 2002 year-end closing process and 2002 audit, we noted deficiencies in internal controls relating to: timely evaluation and substantiation of material account balances; and supervision, staffing, and training of accounting personnel. At that time, we discussed our evaluation of appropriate reserves for accounts receivable and billing adjustments. With the assistance of advisors, we continue to evaluate methods to improve our internal controls and procedures.

        We were incorporated in Delaware in 1923. Our principal office is located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104 and our telephone number is (605) 978-2908. We maintain an internet site at http://www.northwestern.com which contains information concerning us and our subsidiaries. During the fourth quarter of 2002, we began making available 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, free of charge, on this site as soon as reasonably practicable after we electronically file those

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documents with, or otherwise furnish them to, the Securities and Exchange Commission. 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.

ENERGY BUSINESSES

    Electric Operations

Services, Service Areas and Customers

Montana

        We operate a regulated electric utility business in Montana through our NorthWestern Energy division. Our Montana electric utility business consists of an extensive electric transmission and distribution network. Our Montana service territory covered approximately 107,600 square miles, representing approximately 73% of Montana's land area as of December 31, 2002, and included approximately 786,000 people according to the 2000 census. We also transmit electricity for non-regulated entities owning generation facilities, other utilities and power marketers in Montana. In 2002, by category, residential electric transmission and distribution sales, and commercial and industrial transmission and distribution sales accounted for approximately 42% and 54% of our Montana electric utility revenue, respectively.

        Our Montana electric transmission system consists of approximately 7,000 miles of transmission lines, ranging from 50 to 500 kilovolts, 260 circuit segments and 125,000 transmission poles with associated transformation and terminal facilities as of December 31, 2002, and extends throughout the western two-thirds of Montana from Colstrip in the east to Thompson Falls in the west. Our 230 kilovolt and 161 kilovolt facilities form the backbone of our Montana transmission system. Lower voltage systems, which range from 50 kilovolts to 115 kilovolts, 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 Colstrip generation to markets within the state and west of Montana. The system has interconnections with five major non-affiliated transmission systems located in the Western Electricity Coordinating Council area, as well as one interconnection to a system that connects with the Mid-Continent Area Power Pool region. With these interconnections, we also transmit power to and from diverse interstate transmission systems, including those operated by Avista Corporation; Idaho Power Company, a division of Idacorp, Inc.; PacifiCorp; the Bonneville Power Administration; and the Western Area Power Administration.

        As of December 31, 2002, we delivered electricity to approximately 299,000 customers in 191 communities and their surrounding rural areas in Montana, including Yellowstone National Park. We also delivered electricity to rural electric cooperatives in Montana that served approximately 76,000 customers as of December 31, 2002. Our Montana electric distribution system consisted of approximately 16,400 miles of overhead and underground distribution lines and approximately 375 transmission and distribution substations as of December 31, 2002.

South Dakota

        We operate our regulated electric utility business in South Dakota through our NorthWestern Energy division as a vertically integrated generation, transmission and distribution utility. Our electricity revenues in South Dakota are generated primarily through:

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residential generation, transmission and distribution sales,


•

commercial and industrial generation, transmission and distribution sales, and


•

wholesale sales.

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        We have the exclusive right to serve an assigned service area in South Dakota comprised of 25 counties with a combined population of approximately 99,500 people according to the 2000 census. We provided retail electricity to over 57,000 customers in 108 communities in South Dakota as of December 31, 2002. In 2002, by category, including supply for non-choice customers, commercial and industrial, residential, wholesale and other sales accounted for approximately 50%, 39%, 8% and 3% of our electric utility revenue, respectively.

        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 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 pool or other utilities. Power pool sales 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 3,100 miles of overhead and underground transmission and distribution lines across South Dakota as well as 120 substations as of December 31, 2002. We have interconnections and pooling arrangements with the transmission facilities of Otter Tail Power Company, a division of Otter Tail Corporation; Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.; 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 interconnections 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 benefits of pool arrangements.

Competition and Demand

        Although 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 Montana service territory. Direct competition does not presently exist within our South Dakota service territory for the supply and delivery of electricity. Our service territory in South Dakota was assigned to us by the South Dakota Public Utilities Commission pursuant to the South Dakota Public Utilities Act, effective March 1976. Pursuant to the South Dakota Public Utilities Commission grant, we have the exclusive right 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. However, we make such wholesale sales with respect to electricity in excess of our load requirements and such sales are not a material part of our business or operating strategy.

        Competition for various aspects of electric services is being introduced throughout the country that will open utility markets to new providers of some or all traditional utility services. Competition in the utility industry is likely to result in the further unbundling of utility services as has occurred in Montana. Separate markets may emerge for generation, transmission, distribution, meter reading, billing and other services currently provided by utilities as a bundled service. At present, it is unclear when or to what extent further unbundling of utility services will occur. We do not expect deregulation in South Dakota in the near future, but it is unclear if and when such competition will begin to affect our other territories. Some competition currently exists within our Montana and South Dakota service territories with respect to the ability of some customers to self-generate or by-pass parts of the electric

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system, but we do not believe that such competition is material to our operations. Potential competitors may also include various surrounding providers as well as national providers of electricity.

        In our Montana service territory, peak demand was approximately 1,390 megawatts, the average daily load was approximately 944 megawatts, and over 8,270,283 megawatt hours were delivered to choice and default supply customers during the year ended December 31, 2002. In our South Dakota service territory, peak demand was approximately 327 megawatts, including required reserve margins, the average hourly load was approximately 124 megawatts, and over 1,092,868 megawatt hours were delivered during the year ended December 31, 2002.

Electricity Supply

Montana

        In Montana, we purchase substantially all of our power from third parties. We have power-purchase agreements with PPL Montana for 450 megawatts on-peak and 300 megawatts off-peak, and Duke Energy for 111 megawatts on and off peak. We also have 12 "qualifying facility" contracts that The Montana Power Company was required to enter into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 megawatts of firm winter peak capacity. We have secured an additional contract from Thompson River Co-gen, LLC for 10 megawatts and are negotiating with additional parties with respect to three contracts aggregating approximately 190 megawatts, including a contract for 130 megawatts with Montana First Megawatts, our affiliate. In addition, we have recently completed a request for proposals, or RFPs, for wind generation and are currently reviewing such competitive bids to complement the supply portfolio. We believe that these arrangements, in conjunction with our ability to make open market purchases, are sufficient to meet our power supply needs through June 30, 2007, the end of the deregulation transition period in Montana. For more information about our obligations as a result of deregulation in Montana during the statutory transition period, see "Utility Regulation—Montana."

        These open market purchases, along with the Montana Public Service Commission, or MPSC, approved base load supply, are being recovered through an annual electricity cost tracking process pursuant to which rates are based on estimated electricity loads and electricity costs for the upcoming tracking period and are annually reviewed and adjusted by the MPSC for any differences in the previous tracking year's estimates to actual information. This process is similar to the cost recovery process that has been utilized for more than 20 years in Montana, South Dakota and other states for natural gas purchases for residential and commercial customers. The MPSC further stated that we have an ongoing responsibility to prudently administer its supply contracts and the energy procured pursuant to those contracts for the benefit of ratepayers.

        On March 27, 2001, we announced our plan to construct Montana First Megawatts, a 260 megawatt, natural gas-fired, combined-cycle electric generation facility. We commenced construction of the facility, located in Great Falls, Montana, in early November 2001. In light of the uncertainties regarding regulatory review of the Montana First Megawatts' power sales contract with NorthWestern Energy, and resulting difficulties in funding the project due to such uncertainties, we suspended construction on the project in June 2002. The facility is fully permitted and we estimate that a buyer of such facility could complete the project in approximately twelve months following the recommencement of construction activities. As part of our turnaround plan, we are evaluating our options with respect to the disposition of all or a substantial portion of our ownership interest in the project. We estimate total construction, development and related costs will be approximately $180 million inclusive of our existing investment. As of and at December 31, 2002, we determined that absent regulatory approval of the Montana First Megawatts' power sales contract with NorthWestern Energy, the value of the project was equal to the estimated salvage value of project equipment, so we recorded an impairment charge of $35.7 million against our investment of approximately $78.4 million in the project. Due to adverse changes to the independent power generation development market, absent receipt of necessary

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regulatory approvals of the power sales contract, there is no assurance that we will be able to sell this asset at a favorable price, if at all, and therefore, we may be required to take additional charges.

        On June 19, 2002, our power marketing affiliate entered into two five-year power supply contracts to supply a total of approximately 20 megawatts of electricity to customers located in Montana. These supply obligations commenced on July 1, 2002 and continue through June 30, 2007. Our affiliate secured supply to cover these contractual obligations through June 30, 2003. We intend to enter into new supply arrangements and/or make open market purchases to cover the remaining term of these supply obligations.

        NorthWestern Energy leases a 30% share of Colstrip Unit 4, an 805 megawatt gross capacity coal-fired power plant located in southeastern Montana through the unregulated Colstrip Unit 4 Lease Management Division of NorthWestern Energy. A long-term coal supply contract with Western Energy Company provides the coal necessary to run the plant. We sell our leased share of Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to Duke Energy Trading & Marketing and to Puget Sound Energy under agreements expiring December 20, 2010.

South Dakota

        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 that are installed at nine 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. Except as otherwise noted, we are entitled to a proportional share of the electricity generated in our jointly owned plants and are responsible for a proportional 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, although in 2002, approximately 23% of the power was sold in the wholesale market. Our facilities had a total net summer peaking capacity in 2002 of approximately 312 megawatts.

        We have entered into an agreement to purchase up to 28 megawatts of firm summer capacity from Basin Electric Generating Co. to assist in meeting peak demands during the summer of 2003. We also have contracted with MidAmerican Energy Company to supply firm capacity energy as follows during the years 2004-2006: 32 megawatts in 2004; 36 megawatts in 2005; and 40 megawatts in 2006. In addition, we are a member of the Midcontinent Area Power Pool, 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 Midcontinent Area Power Pool agreement and transactions between

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Midcontinent Area Power Pool members are subject to the jurisdiction of the Federal Energy Regulatory Commission, or the FERC.

        The 2002 peak demand in our South Dakota service areas was approximately 327 megawatts, including required reserve margins, and the average daily load in South Dakota during 2002 was approximately 124 megawatts. Our share of generation capacity from jointly owned plants exceeded the average daily load in 2002 and our total system capability through our generating facilities and supply contract with Basin Electric Generating at the time of peak demand was approximately 340 megawatts. We believe we have adequate supplies through our share of generation from jointly owned plants, existing supply contracts, Midcontinent Area Power Pool power swap availability and capacity for sale in the current market to meet our power supply needs during the next few years.

        We have a resource plan that includes estimates of customer usage and programs to provide for economic, reliable and timely supplies 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 baseload generation capacity to meet customer supply needs in the foreseeable future.

Electricity Generation Costs

        Coal was used to generate approximately 95% of the electricity utilized for South Dakota operations for the year ended December 31, 2002. Our natural gas and fuel oil peaking units provided the balance. We have no nuclear exposure. The fuel for our jointly owned base load generating plants is provided primarily through supply contracts of various lengths with several coal companies. The coal contracts for our baseload plants have varying lengths and terms. Currently, there is upward pressure on coal prices, which may result in modest increases in costs to our customers as we pass these costs through in our rates. The average cost by type of fuel burned is shown below for the periods indicated:

*

Includes pollution control reagent.

        During the year ended December 31, 2002, the average delivered cost per ton of fuel for our base load plants was $20.91 at Big Stone, $11.12 at Coyote and $13.55 at Neal. Changes in our fuel costs are passed on to customers through the operation of the fuel adjustment clause in our South Dakota tariffs. For a discussion of federal regulations regarding the use of coal to produce electricity, see "Utility Regulation—Environmental." Also see "Risk Factors—Changes in commodity prices may increase our cost of producing and distributing electricity and distributing natural gas or decrease the amount we receive from selling electricity and natural gas, adversely affecting our financial performance and condition" included in Item 7 hereof.

        Our base load coal plants have contracts for the delivery of lignite and sub-bituminous coal covering various periods. The Big Stone facility currently burns Wyoming sub-bituminous coal from the Powder River Basin supplied under contracts that continue through the end of 2004. The Coyote facility has a contract for the delivery of lignite coal that expires in 2016 and provides for an adequate fuel supply for Coyote's estimated economic life. Neal receives Wyoming sub-bituminous coal under multiple firm and spot contracts with terms of up to several years in duration.

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        The South Dakota Department of Environment and Natural Resources has given approval for Big Stone to burn a variety of alternative fuels, including tire-derived fuel and refuse-derived fuel. In 2002, approximately 1.8% of the fuel consumption at Big Stone was derived from alternative fuels.

        Although we have no firm contract for diesel fuel or natural gas for our electric peaking units, we have historically been able to purchase diesel fuel requirements from local suppliers and currently 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 and Neal plants to our South Dakota transmission system. In 2001, we entered into a new 10-year agreement with the Western Area Power Administration for transmission services, including transmission of electricity from Big Stone and Neal 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 factors, including the respective parties' system peak demand and the amount of our transmission assets that are integrated into the Western Area Power Authority's system. In 2001 and 2002, our costs for services under this contract totaled approximately $3.28 million. Our tariffs in South Dakota generally allow us to pass costs with respect to power purchased, including transmission costs, from other suppliers to our customers.

    Natural Gas Operations

Services, Service Areas and Customers

        Our regulated natural gas utility operations purchase, transport, distribute and store natural gas for approximately 242,000 commercial and residential customers in Montana, South Dakota and Nebraska as of December 31, 2002. Natural gas service generally includes fully bundled services consisting of natural gas supply and interstate pipeline transmission services and distribution services to our customers, although certain large commercial and industrial customers, as well as wholesale customers, may buy the natural gas commodity from another provider and utilize our utility's transportation and distribution service.

Montana

        We distributed natural gas to nearly 160,000 customers located in 109 Montana communities as of December 31, 2002. The MPSC does not assign service territories in Montana. However, we have nonexclusive municipal franchises to purchase, transport, distribute and store 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 4 years, one of our municipal franchises, which accounts for approximately 4,000 customers, is scheduled to expire. We also serve several smaller distribution companies that provided service to approximately 28,000 customers as of December 31, 2002. Our natural gas distribution system consisted of approximately 3,400 miles of underground distribution pipelines as of December 31, 2002.

        We also 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 55 billion cubic feet in the year ended December 31, 2002. NorthWestern Energy's Montana peak capacity was approximately 300 million cubic feet per day during the year ended December 31, 2002. Our Montana natural gas transmission system consisted of over 2,000 miles of pipeline, which vary in diameter from 2 inches to 20 inches, and served over 130 city gate stations as of December 31, 2002. NorthWestern Energy has connections in Montana with five major, non-affiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, Encana and Havre Pipeline. Seven compressor sites provided over 42,000 horsepower, capable of moving approximately 300 million cubic feet per day during the year ended December 31,

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2002. 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 storage capacity of approximately 16.2 billion cubic feet and maximum aggregate working gas capacity of approximately 180 million cubic feet per day. We own a fourth storage field that is being depleted at approximately 0.03 million cubic feet per day with approximately 78 million cubic feet of remaining reserves as of December 31, 2002.

South Dakota and Nebraska

        We provided natural gas to approximately 82,000 customers in 59 South Dakota communities and 4 Nebraska communities as of December 31, 2002. The state regulatory agencies in South Dakota and Nebraska do not assign service territories. We have nonexclusive municipal franchises to purchase, transport, distribute and store 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 6 years, 5 of our South Dakota and Nebraska municipal franchises, which account for approximately 36,000 customers, are scheduled to expire. We have never been denied the renewal of any of these franchises. We have approximately 2,000 miles of distribution gas mains in South Dakota and Nebraska with distribution capacity of approximately 15,000 MMBTU per day as of December 31, 2002. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska.

Competition and Demand

        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. We also provide default supply service to customers in our Montana service territories who have not chosen other suppliers under cost-based rates.

        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 in which we serve in South Dakota and Nebraska. We are currently the largest provider of natural gas in our South Dakota and Nebraska service territories based on MMBTU sold. In South Dakota, we also transport natural gas for one gas marketing firm currently serving four customers through our distribution systems. In Nebraska, we transport natural gas for one customer, whose supply is contracted from another gas company. We delivered approximately 6.6 million MMBTU of third-party transportation volume on our South Dakota distribution system and approximately 0.95 million MMBTU of third-party transportation volume on our Nebraska distribution system.

        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. To remain competitive in the future, we must provide top quality services at reasonable prices. To prepare for the future, we must ensure that all aspects of our natural gas business are efficient, reliable, economical and customer-focused.

        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

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price fluctuations. Purchase adjustment clauses contained in South Dakota and Nebraska tariffs allow us to reflect increases or decreases in gas supply and interstate transportation costs on a timely basis, so we are generally allowed to pass these higher natural gas prices through to our customers.

Natural Gas Supply

        Like most utilities, our natural gas supply requirements are fulfilled through third party fixed term purchase contracts, natural gas storage services contracts and short-term market purchases. This supply flexibility or portfolio approach, 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, Pan-handle (Texas/Oklahoma) and Montana, and Alberta, Canada. These suppliers also provide us with market insight, which assists us in making procurement decisions.

        In Montana our natural gas supply requirements for the year ended December 31, 2002, were approximately 20.3 million MMBTU. We have contracted with over seven major producers and marketers with varying contract durations for natural gas supply in Montana.

        Our South Dakota natural gas supply requirements for the year ended December 31, 2002, were approximately 5.4 million MMBTU. We have contracted with BP Canada Energy Marketing Corp. 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, 2002, was approximately 5.7 million MMBTU. Our Nebraska natural gas supply, storage and pipeline requirements are fulfilled primarily through a third-party contract with ONEOK.

        To supplement firm gas supplies in South Dakota and Nebraska, NorthWestern also contracts for firm natural gas storage services to meet the heating season and peak day requirements of our natural gas customers. NorthWestern also operates two propane-air gas peaking units with a daily capacity of approximately 6,400 MMBTU. These plants provide an economic alternative to pipeline transportation charges to meet the peaks caused by customer demand on extremely cold days. We believe that our Montana, South Dakota and Nebraska natural gas supply, storage and distribution facilities and agreements are sufficient to meet our ongoing supply requirements.

Employees

        As of December 31, 2002, we had 1,817 team members employed in our energy division, NorthWestern Energy. Of these, our Montana operations had 1,488 team members employed in its electric and gas utilities business, 406 of whom were covered by collective bargaining agreements involving six unions. In addition, our South Dakota and Nebraska operations had 329 team members employed in its electric gas and utilities business, 202 of whom were covered by the System Council U-26 of the IBEW. We consider our relations with team members to be good.

    Utility 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 and the

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setting of wholesale electric rates. We are an exempt "holding company" under the Public Utility Holding Company Act.

        In April 1996, the FERC issued Order No. 888 and Order No. 889 requiring utilities to allow open use of their transmission systems by other utilities and power marketers. We and other jurisdictional utilities filed open access transmission tariffs, or OATTs, with the FERC in compliance with Order No. 888. NorthWestern Public Service and The Montana Power Company included OATTs in their filings which conform to the "Pro Forma" tariff in Order No. 888 in which eligible transmission service customers can choose to purchase transmission services from a variety of options ranging from full use of the transmission network on a firm long-term basis to a fully interruptible service available on an hourly basis. These tariffs also include a full range of ancillary services necessary to support the transmission of energy while maintaining reliable operations of our transmission system. NorthWestern Energy LLC, and subsequently, NorthWestern, succeeded to The Montana Power Company's OATTs.

        In Montana, NorthWestern Energy sells transmission service across its system under terms, conditions and rates defined in its OATT, which became effective in July 1996. NorthWestern Energy is required to provide retail transmission service in Montana under tariffs for customers still receiving "bundled" service and under the OATT for "choice" customers.

        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.

        On December 20, 1999, the FERC issued Order No. 2000, its most recent order regarding Regional Transmission Organizations, or RTOs. An RTO is an organization that attempts to capture efficiencies created by combining individually operated transmission systems into a single operation, focusing on operational and strategic transmission issues. Pursuant to Order No. 2000, utilities that own, operate or control interstate transmission facilities were required to file a proposal with the FERC by October 15, 2000, describing the utilities' efforts to participate in an RTO expected to be operational by December 15, 2001.

        The Montana Power Company was a co-sponsor of a filing at the FERC that proposed to form RTO West. RTO West would be a nonprofit organization with an independent board that would act as the independent system operator for the aggregated transmission systems of participating transmission owners. If RTO West is implemented and we participate, we would execute a transmission operating agreement with RTO West prior to startup of the RTO West operation, which is not currently contemplated to occur before early 2006. We do not anticipate that the transmission operating agreement would include any of our transmission assets other than those used in NorthWestern Energy's Montana operations. RTO West would not be permitted to own transmission assets pursuant to its charter, so the transmission operating agreement would not convey ownership of the assets to RTO West but would grant RTO West the right to operate the assets consistent with the obligation to provide services pursuant to applicable tariffs. NorthWestern Energy and other participating transmission owners would likely retain the right and obligation to maintain the facilities that RTO West has authority to operate pursuant to the transmission operating agreements. Participation in RTO West would create a new commercial arrangement for the transmission of the energy we distribute in Montana, but NorthWestern Energy does not anticipate any material change in the size or timing of the transmission related revenue stream as a result of participation in RTO West.

        With respect to our South Dakota transmission operations, we filed in October 2000 our Order No. 2000 Compliance Filing with the FERC detailing options we are pursuing in order to participate in an RTO, including participation in the investigation of the formation of a regional transmission entity as well as the pursuit of various options associated with joining the Midwest Independent System Operator.

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        On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, or the SMD NOPR. The proposed rules set forth in the SMD NOPR would require, among other things, that:

•

all transmission owning utilities transfer control of their transmission facilities to an independent third party;



•

transmission service to bundled retail customers be provided under the FERC-regulated transmission tariff rather than state-mandated terms and conditions; and



•

new terms and conditions for transmission service be adopted nationwide, including new provisions for pricing transmission in the event of transmission congestion.

        If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. On January 15, 2003, the FERC announced the issuance of a white paper on SMD NOPR to be released in April 2003. The FERC also has indicated that it expects to issue the final rules during the summer of 2003.

        Furthermore, the SMD NOPR presents several uncertainties, including what percentage of our investments in RTO West would be recovered, how the elimination of transmission charges, as proposed in the SMD NOPR, would impact us, and what amount of capital expenditures would be necessary to create a new wholesale market. We cannot predict when the FERC will issue final rules on SMD NOPR, or in what form, or the effect that they may have on the current RTO West proceedings. Although we cannot predict with certainty the impact the future proceedings will have on the Company's earnings, revenues or prices, management believes that in the aggregate, our earnings and revenues would not be materially affected.

        The Montana Power Company provided wholesale power to two electric cooperatives, but the two cooperatives have chosen to obtain their power supply from another source, and NorthWestern Energy provides only transmission services to the Montana cooperatives. In order to recover the transition costs associated with power that would have been supplied to these two cooperatives, The Montana Power Company made a filing with the FERC in April 2000, seeking recovery of approximately $23.8 million in transition costs associated with serving both of the wholesale electric cooperatives. On November 1, 2002, the FERC granted the electric cooperatives' motion for summary judgment and determined that The Montana Power Company had failed to meet its burden of showing that it was entitled to recover the transition costs at issue. NorthWestern Energy, as successor to The Montana Power Company, is currently appealing the decision by the administrative law judge through the appropriate FERC rules of practice and procedure.

        The limited liability company that formerly held our Montana transmission and distribution assets has been renamed "Clark Fork and Blackfoot, L.L.C." This entity operates the Milltown Dam, a two megawatt hydroelectric dam at the confluence of the Clark Fork and Blackfoot Rivers, under a license granted by the FERC. The current license for operation of the dam would have expired but for extensions received from the FERC. The Montana Power Company received an extension of its FERC license to operate the dam until 2007, and we are currently seeking to extend that license until 2008. Generally, under FERC rules, notice of intent to renew a license must be filed five years prior to its expiration. Accordingly, Clark Fork and Blackfoot, L.L.C. gave the FERC its notice to seek renewal of the license in 2003. In the event the FERC license were terminated, the FERC may require that the dam be removed. If Clark Fork and Blackfoot, L.L.C. does not receive the license extension, it might be required to relinquish the license, cease operating the dam and remove the structures as early as 2007. Based on estimates received from our environmental consultants, management believes that the cost of such removal would be approximately $10 million.

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Montana

        NorthWestern Energy's Montana operations are subject to the jurisdiction of the MPSC with respect to electric service territorial issues, rates, terms and conditions of service, accounting records and other aspects of its operations.

        In August 2000, The Montana Power Company filed a combined request for increased natural gas and electric rates with the MPSC. The Montana Power Company requested increased annual electric revenues of approximately $38.5 million, with a proposed interim annual increase of approximately $24.9 million. On November 28, 2000, the MPSC granted the former owner an interim electric rate increase of $14.5 million. On May 8, 2001, The Montana Power Company received a final order from the MPSC resulting in an annual electric service revenue increase of $16.0 million.

        Montana law required that the MPSC determine the value of net unmitigable transition costs associated with the transformation of the utility business from a vertically integrated electric service company to a utility providing only default supply and transmission and distribution services. The MPSC was also obligated to set a competitive transition charge to be included in distribution rates to collect those net transition costs. The majority of these transition costs relate to out-of-market power purchase contracts, which run through 2032, that The Montana Power Company was required to enter into with certain "qualifying facilities" as established under the Public Utility Regulatory Policies Act of 1978. The Montana Power Company estimated the pre-tax net present value of its transition costs to be approximately $304.7 million in a filing with the MPSC on October 29, 2001.

        On January 31, 2002, the MPSC approved a stipulation among The Montana Power Company, us and a number of other parties, which, among other things, conclusively established the pre-tax net present value of the retail transition costs relating to out-of-market power purchase contracts recoverable in retail rates to be approximately $244.7 million, approximately $60 million less than The Montana Power Company's filing with the MPSC. In addition, the stipulation set a fixed annual recovery for the retail transition costs beginning at $14.9 million in the first year after implementation and increasing up to $25.6 million through 2029. Because the recovery stream as finalized by the stipulation is less than the total payments due under the out-of-market power purchase contracts, the difference must be mitigated or covered from other revenue sources. Qualifying Facilities Contracts, or QFs, require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our gross contractual obligation related to the QFs is approximately $1.9 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.5 billion through 2029. Upon completion of the purchase price allocation related to our acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company, we established a liability of $134.3 million, based on the net present value of the difference between our obligations under the QFs and the related amount recoverable. Although we believe that we have opportunities to mitigate the impact of these differences through improved management of our obligations under these contracts and by negotiating buyouts of certain of these contracts, we cannot assure you that our actions will be successful.

        The stipulation also required The Montana Power Company and us to contribute $30 million to an account, which will fund credits to Montana electric distribution customers. The account is being applied on a per kilowatt hour basis which began on July 1, 2002 with a term of one year, and had a balance of $16.3 million at December 31, 2002. See "Risk Factors—We may not be able to fully recover transition costs, which could adversely affect our net income and financial condition" and "Risk Factors—If the MPSC disallows the recovery of the costs incurred in entering into default supply portfolio contracts while we are required to act as the "default supplier," we may be required to seek alternative sources of supply and may not be able to fully recover the costs incurred in procuring default supply contracts, which could adversely affect our net income and financial condition" included in Item 7 hereof.

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        Montana's Electric Utility 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 will be able to choose their electric supplier during a transition period through June 30, 2007. We are required to act 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. In its 2001 session, the Montana Legislature passed House Bill 474, which, among other things, reaffirmed full cost recovery for the default supplier by mandating that the MPSC use an electric cost recovery mechanism providing for full recovery of prudently incurred electric energy supply costs. In November 2002, Initiative 117 was passed, repealing HB 474 and reinstating a transition period ending on June 30, 2007. Because of the original language in the Restructuring Act, we believe we have adequate assurances of recovering our costs of acquiring electric supply. On October 29, 2001, The Montana Power Company filed with the MPSC its initial default supply portfolio, containing a mix of long and short-term contracts from new and existing power suppliers and generators. On April 25, 2002, the MPSC approved NorthWestern Energy LLC's proposed "cost recovery mechanism" in the form filed. On June 21, 2002, the MPSC issued a final order approving contracts meeting approximately 60% of the default supply winter peak load and approximately 93% of the annual energy requirements. We believe our current power supply arrangements, in conjunction with an ability to make open market purchases, are sufficient to meet our power supply needs through 2007. For further discussion of this risk, see "Risk Factors—We may not be able to fully recover transition costs, which could adversely affect our net income and financial condition" and "Risk Factors—If the MPSC disallows the recovery of the costs incurred in entering into default supply portfolio contracts while we are required to act as the "default supplier," we may be required to seek alternative sources of supply and may not be able to fully recover the costs incurred in procuring default supply contracts, which could adversely affect our net income and financial condition" included in Item 7 hereof.

South Dakota

        We are subject to the South Dakota Public Utilities Commission with respect to electric service territorial issues, rates, terms and conditions of service, accounting records 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 South Dakota Public Utilities Commission and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the South Dakota Public Utilities Commission. 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 South Dakota Public Utilities Commission, 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. We make an information filing with the Commission each month showing our calculations for the adjustment. The adjustment goes into effect 10 days after the information filing unless the South Dakota Public Utilities Commission 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 South Dakota Public Utilities Commission, 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.

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Natural Gas Operations

Federal

        FERC Order 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 NorthWestern, 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. NorthWestern Energy conducts limited interstate transportation in Montana that is subject to FERC jurisdiction, but the FERC has allowed the MPSC to set the rates for this interstate service.

Montana

        As a public utility, we are subject to MPSC jurisdiction when we issue, assume or guarantee securities, or when we create liens on our Montana properties. Rates for NorthWestern Energy's Montana natural gas supply are set by the MPSC. NorthWestern Energy uses an annual gas tracking mechanism in Montana for the recovery of gas supply costs, which we prepare and file annually with the MPSC. The filing sets gas cost rates based on estimated gas loads and gas costs for the upcoming tracking period and adjusts for any differences in the previous tracking year's estimates to actual information. The MPSC has utilized this process since 1979. We filed an annual gas cost tracker request in Montana in December 2001 for actual gas costs for the twelve month period ended October 31, 2001 and for projected costs for the twelve month period ended October 31, 2002. That request was finalized by order of the MPSC on October 10, 2002. On November 1, 2002, we filed an annual gas cost tracker request for actual gas costs for the twelve month period ended October 31, 2002 and for projected costs for the eight month period ended June 30, 2003. In our 2002 filing, we proposed to change the tracking year to July 1 through June 30 and therefore estimated our gas costs from November 1, 2002 through June 30, 2003. Our 2002 request is still pending with the MPSC. The only intervener in our recent request was the Montana Consumer Counsel, or MCC, who has filed testimony indicating that they have no issues with our gas costs or proposal. We expect that the MPSC will issue and order approving our request within approximately 60 days.

        In August 2000, The Montana Power Company filed a combined request for increased natural gas and electric rates with the MPSC. The Montana Power Company requested increased annual natural gas revenues of approximately $12.0 million, with a proposed interim annual increase of approximately $6.0 million. On November 28, 2000, the MPSC granted the former owner an interim natural gas rate increase of $5.3 million. On May 8, 2001, The Montana Power Company received a final order from the MPSC resulting in an annual delivery and gas storage service revenue increase of $4.3 million. Because the amount established in the final order was less than the interim order, The Montana Power Company began including a credit for the difference collected from November 2000 through May 2001, with interest, in its customers' bills over a six-month period starting October 1, 2001.

        In January 2001, The Montana Power Company submitted to the MPSC an annual gas cost tracker requesting an increase of approximately $51.0 million. At that time, the former owner also submitted a compliance filing for a credit of approximately $32.5 million associated with a sharing of the proceeds from the sale of gathering and production properties previously included in the natural gas utility's rate base. As a result, effective February 1, 2001, The Montana Power Company began collecting a net amount of $18.5 million in revenues over a one-year period. In September 2001, after all testimony addressing the amount of sharing had been filed with the MPSC, The Montana Power Company

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reached an agreement with intervening parties to increase the amount of the credit to $56.3 million. This $23.8 million increase, along with $4.0 million in interest from the date of sale, is being credited to customers' bills over a one to two-year period, which began February 1, 2002. The amount of this customer credit was funded by The Montana Power Company through a purchase price adjustment at the closing of the acquisition of the electric and natural gas transmission and distribution business by NorthWestern and had a balance of $16.0 million as of December 31, 2002.

South Dakota

        We are subject to the jurisdiction of the South Dakota Public Utilities Commission with respect to rates, terms and conditions of service, accounting records and other aspects of our natural gas distribution and transmission 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 South Dakota Public Utilities Commission and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the South Dakota Public Utilities Commission. A purchased gas adjustment provision in our natural gas rate schedules permits the 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 South Dakota Public Utilities Commission, 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

        The State of Nebraska currently has no centralized regulatory agency exercising jurisdiction over natural gas operations in that state; however, natural gas rates are subject to regulation by the municipalities in which gas utilities operate. Several legislative proposals have been introduced in the Nebraska Unicameral Legislature in its 2003 session to transfer jurisdiction over natural gas rates and terms and conditions of service to the Nebraska Public Service Commission, all with provisions that allow natural gas utilities to continue to negotiate with the cities they serve with regard to natural gas rates. At this time, it is uncertain whether such regulatory change will be implemented. Our retail natural gas tariffs, filed with the cities served, 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.

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 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. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. 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, our results of operations and financial condition could be adversely affected.

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    Environmental

        Our electric, natural gas and other business sectors are subject to extensive regulation imposed by federal, state and local government authorities in the ordinary course of day-to-day operations with regard to the environment, including air and water quality, solid waste disposal and other environmental considerations. The application of government requirements to protect the environment involves or may involve review, certification, issuance of permits or other similar actions or by government agencies or authorities, including but not limited to the United States Environmental Protection Agency, or the EPA, the Bureau of Land Management, the Bureau of Reclamation, the South Dakota Department of Environment and Natural Resources, the North Dakota State Department of Health, the Nebraska Department of Environmental Quality, the Iowa Department of Environmental Quality and the Montana Department of Environmental Quality, or the MDEQ, as well as compliance with court decisions.

        We did not incur any material environmental expenditures in 2002. We are committed to remaining in compliance with all state and federal environmental laws and regulations and taking reasonable precautions to prevent any incidents that would violate any of these rules.

        The Clean Air Act Amendments of 1990, which prescribe limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants, required reductions in sulfur dioxide emissions at our Big Stone plant beginning in the year 2000. We currently satisfy this requirement through the purchase of sub-bituminous coal, which contains lower sulfur content. The plant recently completed the replacement of a precipitator with an advanced hybrid particulate collector, at an approximate cost of $13.4 million. Roughly half of this cost will be paid for by the Department of Energy, and our project share of the remainder was approximately $1.2 million and was paid over a four-year period that ended in 2002. In 2000, the wall-fired boiler at our Neal 4 plant and the cyclone boilers located at our Big Stone and Coyote plants became subject to nitrogen oxide emission limitations. To satisfy these limits, the Neal 4 and Big Stone facilities purchase and burn sub-bituminous coal from the Powder River Basin, and the Coyote facility purchases and burns lignite coal. Low nitrogen oxide burners have been identified as additional possible control technology; however, installation of such burners has not yet been required. The Clean Air Act also contains a requirement for future studies to determine what, if any, limitations and controls should be imposed on coal-fired boilers to control emissions of certain air toxics, including mercury. Because of the uncertain nature the air toxic emission limits and the potential for development of more stringent emission standards in general, we cannot reasonably determine the additional costs we may incur under the Clean Air Act. Legislation has been introduced in the Congress to amend the Clean Air Act, including legislation that would adopt President Bush's "Clear Skies" proposals, or that would otherwise affect the regulatory programs applicable to emissions of sulfur oxide, nitrogen oxide, mercury, and possibly carbon dioxide. These proposals are all subject to the normal legislative process, and we cannot make any prediction about whether the proposals will pass, or the final terms of the legislation if it were to pass. Any such legislation, if it passed, would likely require administrative regulations to be adopted. We cannot reasonably determine whether any proposals would impose additional costs, or if so, what the magnitude of those costs would be.

        On January 2, 2001, BSP Otter Tail, the contract operator at Big Stone, received a Request for Information from the EPA, pursuant to Section 114 of the Clean Air Act. The request sought information related to Big Stone's current and past operations, modifications and repairs. The EPA has taken no action since BSP Otter Tail filed its final response on April 2, 2001. However, it is possible that the EPA could file an enforcement action against the facility as part of its New Source Review enforcement initiative against coal-fired power plants. We cannot be certain whether an action will be sought, and if sought, the effect of such an action on the cost of future compliance and operations.

        NorthWestern has met or exceeded the removal and disposal requirements for all equipment containing polychlorinated biphenyls, or PCBs, as required by state and federal regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter,

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dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

        The Comprehensive Environmental Response Compensation and Liability Act, or CERCLA, and some of its state counterparts require that we remove or mitigate adverse environmental effects resulting from the disposal or release of certain substances at sites that we own or previously owned or operated, or at sites where these substances were disposed. However, we cannot quantify costs associated with current site remediation efforts or future remediation efforts because of the following uncertainties:

•

We may not know all sites for which we are alleged or will be found to be responsible for remediation; and

•

We cannot estimate with a reasonable degree of certainty the total costs of remediation at sites where we have been identified as responsible for remediation.

        For sites where we currently are required to investigate and or clean up contamination, we do not expect the unknown costs to have a material adverse effect on our consolidated operations, financial position or cash flows.

        Two formerly operated manufactured gas plants located in Aberdeen and Mitchell, South Dakota, have been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System, or CERLIS, list as contaminated with coal tar residue. We are currently investigating these sites pursuant to a work plan approved by the EPA and the South Dakota Department of Environment and Natural Resources. At this time, we do not know whether any remediation is necessary at these sites. If, however, remediation is required at these sites, we cannot estimate with a reasonable degree of certainty at this time the total costs of clean up at these sites, but based upon our investigations to date, our current environmental liability reserves and environmental insurance, we do not expect cleanup costs to be material to NorthWestern. We also own a site in North Platte, Nebraska on which a former manufactured gas facility was located and which is under investigation for alleged soil and groundwater contamination. At present, we cannot estimate with a reasonable degree of certainty the total costs of remaining clean up at the site, but we do not expect clean up costs to be material.

        The Montana Power Company was identified as a Potentially Responsible Party, or a PRP, at the Silver Bow Creek/Butte Area Superfund Site. The Montana Power Company settled most of its liability in a Consent Decree approved by the United States District Court for the District of Montana and received contribution protection in the event other PRPs claim contribution for cleanup costs they expend. The Atlantic Richfield Company, or ARCO, continues to address contamination of the site. The Montana Power Company transferred approximately 30 acres of property owned by it and included within the boundary of the Silver Bow Creek/Butte Area Superfund Site to NorthWestern Energy, LLC, the entity that was acquired by NorthWestern in February 2002. NorthWestern Energy continues to operate a maintenance center on this property. We cannot estimate with a reasonable degree of certainty whether additional clean up will be required, but we do not expect any residual cleanup costs to be material. Any subsequent remediation costs for contaminants not covered by the settlement will be subject to the indemnification provisions between TouchAmerica Holdings, Inc. and NorthWestern, which are described below.

        Toxic heavy metals in the silts resting in Milltown Reservoir, which sits behind Milltown Dam, caused the EPA to identify Milltown Reservoir on its Superfund National Priority List. ARCO, as successor to the Anaconda Company, has been named as the party with responsibility for completing the remedial investigation and feasibility studies and conducting site cleanup, under the EPA's direction. The Montana Power Company did not undertake any direct responsibility in that regard, in light of a statutory exemption from liability under CERCLA in relation to the Milltown Dam. By virtue of its acquisition of The Montana Power Company's electric and natural gas transmission and distribution

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business and the Milltown Dam, Clark Fork and Blackfoot, L.L.C. succeeded to similar protection under this statutory exemption. ARCO has argued that the owner of the Milltown Dam should be considered a PRP and has threatened to challenge Clark Fork and Blackfoot, L.L.C.'s exempt status. ARCO and The Montana Power Company entered into a confidential settlement agreement to limit The Montana Power Company's and now Clark Fork and Blackfoot, L.L.C.'s potential liability and costs and ongoing operating expenditures, provided that the EPA selects a remedy that leaves the dam and sediments in place in its final Record of Decision. According to press reports, EPA staff have informally indicated that the agency may decide to require removal of the dam as part of the remedy to be selected. However, no draft decision has been issued for public comment. The final Record of Decision is expected out in the latter part of 2003. The EPA has indicated that it favors a remedy involving partial sediment and ultimate dam removal. In light of the EPA's position, ARCO and NorthWestern Energy have had discussions regarding a potential allocation and funding of the costs of the EPA's preferred remedy. Depending on the structure of any negotiated settlement with the EPA, ARCO and other parties, NorthWestern Energy may agree to fund some portion of its allocated share of the remedy costs in 2003. We have established a reserve of approximately $36.5 million at December 31, 2002, for liabilities related to the Milltown Dam and other environmental liabilities. The Company also secured a ten-year, $100 million environmental insurance policy, effective May 31, 2002, to mitigate the risk of future liabilities arising from a catastrophic failure of the Milltown Dam caused by an act of God.

        In 1985 and 1986, researchers found elevated levels of heavy metals in sediments in the reservoir behind the Thompson Falls Dam. The EPA declared the site a "No Further Action" site for purposes of CERCLA, but the MDEQ listed the reservoir as a Comprehensive Environmental Cleanup and Responsibility Act site, or a CECRA site, Montana's state equivalent of a CERCLA National Priority List site. The MDEQ identified the site as a "Low Priority Site" and because of the low probability of direct human contact and the lack of evidence of migration to groundwater supplies, no action has been required. Given the low priority designation for this site, we believe that the risk of material remediation is low. As discussed below, The Montana Power Company retained pre-closing environmental liability relating to this CECRA listing when it sold the Thompson Falls Dam to PPL Montana. We cannot estimate with a reasonable degree of certainty the total costs, if any, of cleanup at this site. We do not expect cleanup costs to be material.

        The Montana Power Company voluntarily cleaned up two sites where it formerly operated manufactured gas plants and was investigating a third at the time of our acquisition of The Montana Power, L.L.C. The Helena site was placed into the MDEQ's voluntary remediation program. While the site continued to experience exceedances of groundwater contamination levels, NorthWestern Energy determined that natural attenuation should address the problem. NorthWestern Energy requested closure of the site. The decision is pending. The Montana Power Company stated at the time of the acquisition that remediation was complete at a second site located in Missoula, and it had requested closure from the State for that site. A third former manufactured gas plant formerly owned by The Montana Power Company, located in Butte, was under investigation at the time of the acquisition. NorthWestern Energy continued the work and has now requested closure for the site. The decision is pending. We cannot estimate with a reasonable degree of certainty whether additional cleanup will be necessary or the total costs of such cleanup. However, we do not expect any of the outstanding cleanup costs to be material.

        As described above, The Montana Power Company retained certain environmental liabilities in connection with its sale of assets to PPL Montana. Under the terms of our acquisition of The Montana Power, L.L.C., we assumed the first $50 million of NorthWestern Energy LLC's pre-closing environmental liabilities, including these retained environmental liabilities. Touch America Holdings, Inc. assumed the next $25.0 million in costs. NorthWestern Energy LLC and Touch America Holdings, Inc. agreed to equally split costs that fall between $75.0 and $150 million. In light of the financial difficulties

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experienced by Touch America, we are uncertain as to the ability of Touch America to satisfy its contractual indemnification obligation.

        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 accurately predicted. However, we believe that we accrue an appropriate amount of costs and estimate reasonably foreseeable potential costs related to such environmental regulation and cleanup requirements. We do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

COMMUNICATIONS, NETWORK SERVICES AND DATA SOLUTIONS BUSINESS—EXPANETS

Ownership

        As of December 31, 2002, after impairment charges and recognition of our share of net losses, the net recorded book value of our aggregate investment in and advances to Expanets, which consisted of $364.1 million in equity and $205.7 million in intercompany indebtedness, was $89.7 million. In addition, we may have an obligation to honor the remaining $6.0 million in put rights related to certain minority interests. We controlled approximately 99% of the voting power of Expanets' issued and outstanding shares of capital stock as of December 31, 2002. See Note 2. Significant Accounting Policies—Minority Interests in Consolidated Subsidiaries included in Item 8 herein.

        As part of our turnaround plan, we announced in February 2003 that we do not intend to make any additional material investments in, or commitments to, Expanets while we examine strategic alternatives for the business, including the possible sale or disposition of the business or its assets.

Products and Services

        Expanets is a nationwide provider of networked communications and data services and solutions to small to mid-sized businesses. Expanets is Avaya's largest independent dealer for the wide range of Avaya products and software, including the PARTNER™ Advanced Communication System, Avaya™ IP Office, MultiVantage™, the MERLIN MAGIX™ Integrated System, Guestworks Systems and DEFINITY™ solutions and messaging solutions. Expanets is also a reseller of NEC America, Inc., Cisco Systems, Inc., Siemens Enterprise Networks, LLC, Toshiba America and Inter-Tel products. In June 2002, Expanets became a Cisco Gold Certified Partner and received Cisco's IP Telephony Specialization. Effective July 1, 2002, Expanets signed a revised distribution agreement that enabled it to market and sell NEC telephony products on a national basis. Through OEM relationships with other partners, Expanets also integrates and sells an Expanets' branded set of voice and data applications, such as Smart Connect™ and Smart Messaging™, as part of its Expanets Interaction Center. Expanets designs, procures, implements, maintains and monitors voice, video and data systems, which provide a wide range of communications tools for its customers. Expanets' service offerings include voice networking, data networking, internet connectivity, messaging systems, advanced call processing applications, computer telephony, network management and carrier services. Expanets' target customers are mid-market businesses with 20 to 1,000 end-users, where it enables those customers to focus on their core competencies while Expanets provides a single point of contact for access to specialized technical skills and rapid implementation of communications and data networking solutions. Expanets serves its installed customer base through the efforts of more than 3,250 team members located in more than 120 offices across the country.

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Relationship with Avaya and Problems with the EXPERT System

        Expanets was formed in 1997 and through December 31, 1999 had established operations in many major United States markets through the acquisition of 26 telecom and/or data services companies. In March 2000, Expanets purchased the Growing and Emerging Markets division, or GEM division, of Lucent Technologies' Enterprise Network Group, Lucent's primary distribution function for voice systems for U.S. small and mid-sized businesses. In September 2000, Lucent contributed its enterprise network business to Avaya, Inc., including the various agreements and instruments relating to Expanets. Through the GEM transaction, Expanets became, and continues to be, Avaya's largest dealer. Avaya became Expanets' primary vendor for products, maintenance and technical support services sold to Expanets' customers. The terms of the sale provided that under Transition Service Agreements, or TSAs, Avaya would provide Expanets with critical supporting systems such as accounting, billing, collection and maintenance services for substantial fees during a transitional period.

        During 2000 and 2001, Expanets worked with consultants to develop the EXPERT system, an enterprise information technology and management system that was intended to enable Expanets to terminate certain TSAs with Avaya and manage the substantial transaction volume assumed with the purchase of the GEM assets. Expanets implemented the EXPERT system for transactions related to the GEM purchase (more than 70% of Expanets' business), in late November 2001. The EXPERT system was not sufficiently tested prior to cut-over and Expanets began to experience significant problems upon implementation, including order entry and customer fulfillment, billing and collection functions, an inability to provide timely and complete billing detail with beginning and ending balances for a majority of Expanets' customers until May 2002, and numerous reporting deficiencies which prevented management from receiving critical accounts receivable and cash application data. Expanets was forced to resort to manual journal entries in many instances. As work on the EXPERT system progressed, Expanets determined that problems relating to data migration from Avaya's system, underlying problems with the accuracy of the Avaya database, as well as data migration scripting performed by Expanets, were contributing to the functional deficiencies Expanets was experiencing with the EXPERT system. As Expanets expanded its efforts to correct deficiencies in the EXPERT system, it encountered and continues to encounter additional substantial functional deficiencies. The combination of these issues resulted in substantial weaknesses in Expanets' internal controls and procedures during 2002.

        In March 2001, Expanets and Avaya completed a substantial restructuring of the GEM transaction to address concerns that had arisen in connection with certain customer referral and service obligations under the original transaction. Significant aspects of the restructuring included a more precise definition of the customer base to be serviced by each party, modifications to the Master Dealer Agreement, or MDA, under which Expanets purchases products from Avaya, and modification of a $35 million note held by Avaya to extend the payment deadline to March 31, 2005, and eliminate the payment of interest. As part of the restructuring, Avaya agreed to provide a secured $125 million short-term line of credit, due March 2002, to finance equipment purchases by Expanets.

        Because Expanets was unable to obtain an independent credit facility by March 2002, Avaya agreed to extend the credit line to December 31, 2002 with scheduled debt paydowns and NorthWestern agreed to purchase up to $50 million in inventory and accounts receivable from Avaya in the event of a default by Expanets. In addition, Avaya entered into an agreement with Expanets to supply technical customer support and maintenance services with defined service levels for the "Expanets Technical Assistance Center," or the ETAC Agreement, and terminated an earlier TSA for similar services that was substantially more expensive.

        During the fourth quarter of 2002, Expanets and Avaya engaged in discussions concerning various issues that had arisen between the parties regarding certain operating issues and disputes with respect to customer data migration, accuracy of customer data, and billing and collection management services stemming from the GEM transaction. While those discussions were pending, Avaya and Expanets

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extended the repayment deadline of the credit agreement on several occasions, to a final due date of March 13, 2003. On March 13, 2003, Expanets and Avaya restructured their relationship and, in exchange for mutual releases, resolved all outstanding issues between the parties. The principal terms of the new arrangement are:

•

The outstanding principal balance on the credit agreement of approximately $27 million has been further extended and is now due in three equal installments of approximately $9 million on each of January 1, April 1 and July 1, 2004. No new borrowings are permitted under the facility and our obligation to purchase inventory and accounts from Avaya in an amount equal to the outstanding balance at the time of default will remain in place until the balance is fully paid;

•

Avaya has cancelled the Expanets subordinated note in the face amount of $35 million due 2005 that was issued as partial consideration in the GEM acquisition. The subordinated note was non-interest bearing and had a carrying value of approximately $27 million as of December 31, 2002;

•

Expanets and Avaya revised their agreement to reduce the costs payable by Expanets for Avaya's support services for the Expanets Technical Assistance Center; and

•

Avaya relinquished all of its equity interests in Expanets represented by two series of preferred stock.

Operating Developments

        The downturn in the economy has impacted the telecommunications sector in particular and, as a result, traditional equipment sales and corresponding services have been slowed by reduced corporate capital spending. Expanets continues to see a soft market for the communications and information technology industries. In 2001, Expanets commenced a plan to streamline its management and cost structure. In 2002 and 2001, Expanets made significant changes in its executive and regional management structures to address operating challenges and reduce costs. During the first six months of 2002, Expanets hired a new chief executive officer, a new chief financial officer and a new chief information officer. In addition, in 2002 and 2001, a number of regional offices were consolidated to reduce costs. As part of our turnaround plan, we announced in February 2003 that we do not intend to make any additional material investments in, or commitments to, Expanets while we examine strategic alternatives for the business, including the possible sale or disposition of the business or its assets.

        There are a number of challenges Expanets must address during 2003. If Expanets is not able to resolve these issues effectively, its performance and liquidity will continue to be adversely affected. These challenges include:

•

Expanets will need to improve its internal controls and procedures, particularly the stability and functionality of the "EXPERT" system. Further delays in resolving performance issues of the EXPERT system and the costs of such system repairs, or the delays and costs of adopting alternative information management systems, could continue to have a material adverse effect on Expanets' operations and cash flow.

•

Expanets must become financially independent from NorthWestern, which includes obtaining an asset-based commercial credit facility or some other access to working capital to replace the Avaya line of credit and to provide operating capital to fund its day-to-day operations, preserving normal trade credit relationships, continuing its access to adequate bonding capacity for larger commercial projects and satisfying shareholder redemption obligations.

•

In order to pay the $27 million balance of the credit agreement with Avaya in the three equal installments scheduled in 2004, Expanets will need to generate sufficient cash from operations or obtain other sources of credit and working capital. In the event of a payment default, Avaya would have the right to foreclose on its collateral, consisting of Expanets' accounts receivable

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and inventory, and may declare a cross-default under the MDA and ETAC Agreement and cancel its non-competition agreement with Expanets.

•

Expanets plans to market a number of new solutions based on Internet Protocol, or IP, technology, which is gaining more general acceptance and momentum in the market. However, Expanets can provide no specific assurance that the market for this technology will continue to grow.

•

Expanets believes the Avaya products it sells are competitive in price and performance. However, a change in its relationship with Avaya or a change in Avaya's competitive position could adversely affect its performance.

•

Expanets must address and resolve negative customer satisfaction issues stemming from the performance deficiencies and billing inaccuracies of the EXPERT system, which has contributed to higher than anticipated erosion of Expanets' maintenance revenue and customer base. If the erosion of Expanets' maintenance and customer base continues at above normal levels, it will have a significant adverse affect on cash flow and operations.

•

Expanets may have difficulty attracting and retaining key employees, customers and vendors in light of operational challenges, market conditions and the possibility that the business will be sold.

Competition and Regulation

        The market served by Expanets in the communications, data services and network solutions industry is highly competitive. Many of Expanets' competitors in the communications business are small, owner-operated companies typically located and operated in a single geographic area. Expanets also faces competition in regional markets from divisions of the Regional Bell Operating Companies ("RBOCs"), other larger, companies engaged in providing commercial services in the service lines in which Expanets focuses, and nationally from the direct sales forces of various manufacturers.

        Expanets is subject to a number of regulations, including, among others, filing tariffs for long distance telecommunication services, permitting and licensing requirements, municipal codes and zoning ordinances and laws and regulations relating to consumer protection, occupational health and safety and protection of the environment. Expanets believes it has all permits and licenses necessary to conduct its operations and is in substantial compliance with applicable regulatory requirements.

Employees

        Expanets had 3,251 full-time team members as of December 31, 2002. Approximately 100 team members are covered by collective bargaining agreements. We believe Expanets' relationships with its employees to be adequate.

HVAC, PLUMBING AND RELATED SERVICES—BLUE DOT

Ownership

        As of December 31, 2002, after impairment charges and recognizing our share of net losses, the net recorded book value of our aggregate investment in and advances to Blue Dot, which consisted of $384.8 million in equity and $11.9 million in intercompany indebtedness, was $12.6 million. We controlled approximately 96% of the total voting power of Blue Dot's issued and outstanding capital stock as of December 31, 2002. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Indebtedness and Other Contractual Obligations" included in Item 7 herein and Note 2. "Significant Accounting Policies—Minority Interests in Consolidated Subsidiaries" included in Item 8 herein.

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        As part of our turnaround plan, we announced in February 2003 that we do not intend to make any additional material investments in, or commitments to, Blue Dot while we examine strategic alternatives for the business, including the possible liquidation of Blue Dot.

Products and Services

        Blue Dot operates and manages its business in two customer-focused divisions, residential services and commercial services. Blue Dot's business lines may be characterized as follows:

•

Residential services.  Residential services primarily include (i) emergency repairs of HVAC and plumbing systems in residential homes, (ii) replacement or the upgrade of HVAC and plumbing systems in residential homes, and (iii) preventive maintenance services relating to HVAC and plumbing systems in residential homes. To a lesser extent, Blue Dot provides electrical services, duct cleaning services, and custom door and window installations for existing residential homes.

•

Commercial Services.  Commercial services primarily include (i) installation of HVAC systems concurrently with new construction of residential homes or commercial buildings, (ii) replacement or the upgrade of HVAC systems in commercial buildings, (iii) emergency repairs of HVAC and plumbing systems in commercial buildings, and (iv) preventive maintenance services relating to HVAC and plumbing systems in commercial buildings. To a lesser extent, Blue Dot provides commercial sewer and drain cleaning services. From time to time, Blue Dot engages in light fabrication of parts used in connection with the commercial services it provides.

        Blue Dot companies have developed and maintained relationships with a variety of local and regional equipment dealers and parts suppliers that offer a wide selection of products from nationally recognized manufacturers. As is customary in the industry, Blue Dot companies help assure a continuous inventory of goods from suppliers by purchasing HVAC and plumbing equipment and supplies from manufacturers and dealers on a cash basis and on credit. In addition, some Blue Dot companies have entered into floor planning relationships with manufacturers and dealers of HVAC equipment and others.

Operating Developments

        Blue Dot Services Inc. was formed in 1997 and provides heating, ventilating, and air conditioning, or HVAC, services; plumbing services; and related services through its direct and indirect subsidiaries. Since its inception, Blue Dot expanded the number of markets in which it provides HVAC, plumbing and related services by acquiring numerous local and regional service providers. As of December 31, 2002, Blue Dot provided services from over 50 subsidiary entities that provide services from locations that are primarily situated in or near major metropolitan areas across the United States.

        During this period of aggressive growth, Blue Dot did not realize the expected benefits of integration and efficiencies of scale. In many cases, Blue Dot determined that products and services may be obtained at more competitive terms on a local or regional basis than could be obtained on an enterprise basis. As a result, Blue Dot has terminated certain centralization initiatives. Blue Dot will continue to help improve the quality of certain administrative and management services required by its subsidiaries by providing or arranging for these services to be provided on behalf of its subsidiaries. In addition, Blue Dot intends to implement and maintain certain uniform procedures and controls that its subsidiaries will be required to follow. For example, although Blue Dot does not operate on a fully integrated financial management and reporting information technology system, new management has implemented additional financial reporting policies and procedures to help improve the integrity and timeliness of financial information provided to Blue Dot's management.

        As a result of deterioration in Blue Dot's operations, Blue Dot hired a new chief executive officer in September 2001. Over the past 18 months, Blue Dot has appointed new senior managers, replaced certain location presidents, and redefined corporate and field responsibilities. As part of certain

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operations initiatives, Blue Dot identified approximately 44 locations as "core" and 16 as "non-core" to its ongoing operations in 2003. Blue Dot is currently in the process of seeking to improve its core locations and is in the process of selling or closing the non-core locations. As of March 31, 2003, Blue Dot has sold several of these non-core locations. Blue Dot does not expect to generate a substantial amount of funds through its sale of these non-core locations and to the extent Blue Dot receives any proceeds from the sale of these locations, Blue Dot expects to use these proceeds for working capital purposes or to repay indebtedness.

        During 2002, Blue Dot acquired five companies for a total combined purchase price of approximately $29.1 million. Four of the acquisitions made in 2002 were primarily commercial services businesses which were intended to expand and complement Blue Dot's commercial services platform. The other acquisition was primarily a residential plumbing business which has since been sold in 2003.

        On August 30, 2002, Blue Dot entered into a working capital credit facility with a commercial bank that provides $20 million of available credit for general corporate purposes and matures on August 31, 2005. The facility is collateralized by substantially all assets of Blue Dot and contains restrictive covenants prohibiting, among other things, the use of cash or proceeds from the credit facility by Blue Dot for various purposes including acquisitions, dividend payments to NorthWestern and acquiring outstanding shares of Blue Dot equity, as well as any capital expenditures unless funded by NorthWestern. The facility also prohibits the sale of certain assets, such as the non-core locations, without the consent of the bank and provides that a default will occur in the event that NorthWestern ceases to control Blue Dot. The facility is nonrecourse to us, but subordinates substantially all indebtedness owed to NorthWestern by Blue Dot to the obligations owed by Blue Dot under the credit facility. As of December 31, 2002, $16.0 million was outstanding on the facility and Blue Dot was in default with respect to its credit facility as a result of its failure to meet its minimum earnings before interest, taxes, depreciation and amortization, or EBITDA, requirement for the four quarters ending on December 31, 2002 and its failure to fund capital expenditures with funds provided by NorthWestern in advance as required under the facility and deliver certain reports. As of March 31, 2003, the credit facility was fully drawn in the amount of $20 million and Blue Dot was in default on certain other covenants as a result of (i) its failure to meet the minimum EBITDA requirement for the four quarters ending on March 31, 2003, (ii) its failure to fund certain additional capital expenditures with funds provided by NorthWestern in advance as required under the facility, (iii) its failure to pay up to $4.1 million in redemption obligations to certain holders of Series A Preferred Stock and Class C Common Stock and (iv) making certain interest payments on subordinated debt which were prohibited by the terms of the credit facility. Blue Dot is currently attempting to negotiate extensions, payment terms or other arrangements to satisfy its redemption obligations and is attempting to obtain a waiver of the existing defaults and modify various financial and other covenants of the facility, although no agreement has been reached and no waiver has been granted. We can not provide assurances that Blue Dot will be able to negotiate favorable repayment terms or obtain a waiver. See Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations—Description of Indebtedness and Other Contractual Obligations.

        Blue Dot faces several operating challenges, including:

•

overall reductions in volume and gross margin resulting from a general economic slow down, particularly at non-core locations and in the commercial new construction area;

•

disruption of its business, including the loss of key employees, customers and suppliers, and reduction in the value of the business or its assets as a result of NorthWestern's efforts to sell or dispose of Blue Dot or its assets and our unwillingness to provide further funds to Blue Dot;

•

lack of an integrated enterprise software system and reliance on manual controls and procedures;

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•

achieving financial independence from NorthWestern and addressing its severely constrained working capital and bonding capacity, including the unavailability of funds from its credit facility; and

•

material financial obligations of up to approximately $50 million and potential dilution resulting from obligations with respect to Blue Dot's Series A Preferred Stock and Class C Common Stock and the potential disruption of the business if Blue Dot is unable to meet its exchange obligations to its minority shareholders. Failure to honor these obligations will result in additional defaults under Blue Dot's credit facility. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Indebtedness and Other Contractual Obligations—Other Contractual Obligations" included in Item 7.

Competition and Regulation

        The HVAC and plumbing industry is highly fragmented, consisting primarily of small, owner-operated companies that operate in a single market and provide a limited range of services. Many of these smaller companies have lower overhead cost structures and may be able to provide their services at lower rates. Moreover, many homeowners have traditionally relied on individuals or small repair service companies with whom they have long-established relationships for a variety of home repairs.

        In addition, there are a number of national or regional HVAC and plumbing service companies that offer services similar to those provided by Blue Dot, and which may have or had acquisition strategies similar to that of Blue Dot. There are also a number of utilities that have entered or may enter the market to provide services similar to those provided by Blue Dot. Some manufacturers of HVAC and plumbing related equipment also constitute potential competitors. A number of national retail chains that sell HVAC and plumbing equipment for residential and commercial use may offer, either directly or through various subcontractors, installation, repair, and preventive maintenance services.

        Blue Dot is subject to a number of regulations, including permitting and licensing requirements, municipal codes and zoning ordinances, laws and regulations relating to consumer protection, occupational health and safety and protection of the environment. Blue Dot's policy is to obtain all material permits and licenses to conduct its operations. From time to time, individuals holding permits or licenses for a particular location may leave the business. In such instances, Blue Dot will rely on other licensed personnel, or during an interim period train or qualify personnel to obtain such license or recruit an individual with the appropriate license.

Seasonality and Cyclicality

        Demand for residential and commercial services is driven by a number of non-seasonal factors, particularly the aging of existing HVAC and plumbing systems; the increasing efficiency, sophistication of HVAC systems which tends to encourage upgrades; the installation of central air conditioning in older homes; and the increasing restrictions on the use of refrigerants commonly used in older HVAC systems.

        Demand for residential and commercial services is also subject to seasonal variation. Except in certain regions that experience cold weather, the demand for installations of new HVAC equipment can be substantially lower during the winter months. Demand for HVAC services generally varies based on weather conditions with demand generally being higher during periods of extremely cold or hot weather, such as the winter and summer months, and lower during periods of more mild weather, including the spring and falls months. As a result, Blue Dot expects its revenues and operating results to generally be lower in the first and fourth quarters of each year. Weather cycles, such as unusually mild winters or summers can also adversely impact revenues and operating results.

        In addition, the construction industry is highly cyclical. As a result, a portion of Blue Dot's business, especially new installation projects, may advance or decline in line with construction activity.

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Employees

        As of December 31, 2002, Blue Dot employed approximately 4,000 team members. Approximately 75 of Blue Dot's team members are represented by labor unions, but no Blue Dot team members are covered by collective bargaining agreements. We believe Blue Dot's relationship with its employees to be adequate.

Intellectual Property

        NorthWestern and each of its partner entities utilize a variety of registered and unregistered trademarks and servicemarks for their respective products and services. Common law and state unfair competition laws govern unregistered marks. We regard our trademarks and servicemarks and other proprietary rights as valuable assets and believe that they are associated with a high level of quality and have significant value in the marketing of our products. Our policy is to vigorously protect our intellectual property and oppose any infringement of our trademarks and servicemarks. NorthWestern's success is also dependent in part on our trade secrets and information technology, some of which is proprietary to NorthWestern, and other intellectual property rights. We rely on a combination of nondisclosure and other contractual arrangements, technical measures, and trade secret and trademark laws to protect our proprietary rights. Where appropriate, we enter into confidentiality agreements with our team members and attempt to limit access to and distribution of proprietary information.

ITEM 1A. EXECUTIVE OFFICERS OF THE REGISTRANT

        The following information is furnished with respect to the executive officers of NorthWestern Corporation.

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        The Chief Executive Officer, the President, the Chief Financial Officer, the Secretary and Treasurer are elected annually by the Board of Directors. Other officers may be elected or appointed by the Board of Directors at any meeting. All officers serve at the pleasure of the Board of Directors.

ITEM 2. PROPERTIES

        NorthWestern's executive offices are located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104, where we lease approximately 35,300 square feet of office space, pursuant to a lease that expires on June 30, 2003. We are currently in the process of renegotiating this lease. We anticipate that we will be able to renegotiate or extend this lease or secure additional space as necessary to support our operations. In February 2001, we executed a lease for approximately 14,000 square feet of office space at a building located at 4930 Western Avenue, Sioux Falls, South Dakota 57109. This lease expired April 3, 2003, at which time we consolidated our offices into the 125 S. Dakota Avenue facility.

        NorthWestern Energy's principal corporate office is owned and located at 600 Market Street W., Huron, South Dakota 57350. Substantially all of NorthWestern Energy's South Dakota and Nebraska facilities are owned. NorthWestern Energy's Montana executive offices are located at 40 East Broadway Street, Butte, Montana 59701. NorthWestern Energy leases other offices 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.

        Expanets' executive offices are located at 9780 Mt. Pyramid Court, Englewood, Colorado 80112, where Expanets leases office space. In February 2002, we executed a seven-year lease for approximately 36,000 square feet of office space at a building located at 12300 E. Arapahoe Road, Englewood, Colorado. Expanets occupies this space and makes payments directly to the Lessor. The commencement date of this lease was July 1, 2002. Expanets locates its information technology and intellectual property groups at the second location. Substantially all of Expanets' facilities are leased.

        Blue Dot's executive offices are located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104 where Blue Dot subleases approximately 7,500 square feet of office space from NorthWestern. Substantially all of Blue Dot's facilities are leased.

ITEM 3. LEGAL PROCEEDINGS

        Prior to 1999, The Montana Power Company was the largest, vertically integrated electric utility in the state of Montana, owning and operating generation, transmission and distribution facilities as well as operating a telecommunication business and other non-regulated assets such as oil and natural gas, coal, and independent power businesses. In 1999, The Montana Power Company sold its power

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generating assets to PP&L Montana, LLC. Thereafter, The Montana Power Company's subsidiary Entech, Inc. undertook a series of sales of The Montana Power Company's non-regulated energy businesses (i.e., its coal, oil and natural gas businesses), and its out-of-state independent power-production business, to several third parties (collectively, the "Entech Sales"). The sale of the power generating assets and the Entech Sales took place over a period of time from December 1999 to April 2001.

        On August 16, 2001, eight individuals filed a lawsuit in Montana State District Court, entitled McGreevey, et al. v. The Montana Power Company, et al., DV-01-141, 2nd Judicial District, Butte-Silver Bow County, MT, naming The Montana Power Company, all of its outside directors and certain officers, PPL Montana, and Goldman Sachs as defendants (the "Litigation"), alleging that The Montana Power Company and its directors and officers and investment bankers had a legal obligation and/or a fiduciary duty to obtain shareholder approval before consummating the sale of the electric generation assets to PPL Montana. The plaintiffs further allege that because The Montana Power Company shareholders did not vote to approve the sale, the sale of its generation assets is void and PPL Montana is holding these assets in constructive trust for the shareholders. Alternatively, the plaintiffs allege that The Montana Power Company shareholders should have been allowed to vote on the sale of the generation assets and, if an appropriate majority vote was obtained in favor of the sale, the objecting shareholders should have been given dissenters' rights. The plaintiffs have amended the complaint to add Milbank Tweed (legal advisors to The Montana Power Company and Touch America), The Montana Power, L.L.C., Touch America Holdings, Inc. and the purchasers of the energy-related assets and have claimed that The Montana Power Company and the other defendants engaged in a series of integrated transactions to sell all or substantially all of its assets and deprive the shareholders of a vote.

        After denying the original defendants' motions to dismiss the complaint, upon plaintiffs' motion, the court certified a class consisting of shareholders of record as of December 1999. The court has also, upon plaintiffs' motion, added Clark Fork and Blackfoot LLC as a successor to The Montana Power Company and NorthWestern as an additional defendant as a result of the sale of substantially all of the assets and liabilities from NorthWestern Energy LLC to NorthWestern. Recently, the case has been removed to federal court in Montana upon a petition by Milbank Tweed. Plaintiffs filed a motion to remand the action to state court. The parties are briefing the remand motion and the federal court after a hearing will decide whether or not the case remains in federal court. It is the position of all defendants that The Montana Power Company and its former directors and officers have fully complied with their statutory and fiduciary duties and no shareholder vote was required. Accordingly, all defendants are defending the suit vigorously. We also believe that we have both substantive and procedural defenses to this action and accordingly, we will vigorously defend against any assertion to the effect that we have any liability in this matter.

        In September 2000, The Montana Power Company established Touch America Holdings, Inc. as a new holding company with four subsidiaries, The Montana Power, L.L.C., Touch America, Inc., Tetragenics Company and Entech LLC (referred to as the "Restructuring"). Entech Inc. was merged into Entech LLC and the ownership of Entech LLC was distributed by The Montana Power, L.L.C. to Touch America Holdings, Inc. The Montana Power Company was merged into The Montana Power, L.L.C. with an exchange of The Montana Power Company common stock for Touch America Holdings, Inc. common stock on a one-for-one basis occurred. Certain assets and liabilities of The Montana Power Company subsequently were transferred to Touch America Holdings, Inc. Pursuant to a Unit Purchase Agreement signed on or about September 29, 2000, we acquired the former electric and natural gas transmission and distribution business of The Montana Power Company by purchasing the sole unit membership interest in The Montana Power, L.L.C. Subsequently, we renamed The Montana Power, L.L.C. as Northwestern Energy LLC. In November 2002, we acquired substantially all of NorthWestern Energy LLC's assets. Finally, NorthWestern Energy LLC was renamed again on November 20, 2002 to become Clark Fork and Blackfoot, L.L.C.

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        We believe that no shareholder vote was required for any of the transactions in question and that the shareholders had an opportunity to vote on the Touch America restructuring and NorthWestern's acquisition, which was fully approved by a supermajority of The Montana Power Company's shareholders in September 2001. In the event that we face liability, we believe that we have an indemnification claim against Touch America for adverse consequences resulting from that liability. In light of the financial difficulties experienced by the telecommunications industry, we are uncertain as to the ability of Touch America to satisfy its contractual indemnification claim arising from this litigation. At this early stage, however, we cannot predict the ultimate outcome of this matter or how it may affect our combined financial position, results of operations or cash flows.

        In 1999, The Montana Power Company entered into an Asset Purchase Agreement with PPL Montana pursuant to which The Montana Power Company agreed to sell, among other assets, its portion of the 500-kilovolt transmission system associated with Colstrip Units 1, 2, and 3 for $97.1 million, subject to the receipt of required regulatory approvals. As part of the Touch America reorganization described above, The Montana Power, L.L.C. acquired The Montana Power Company's rights under the Asset Purchase Agreement. In September 2002, Clark Fork and Blackfoot, L.L.C. brought suit in Montana State District Court to compel PPL Montana to perform its obligations under the Asset Purchase Agreement and to recover damages. The case has been removed to the Federal District Court in Butte, Montana. We have filed a motion for partial summary judgment on the issue of specific performance of PPL Montana's obligation to complete the purchase. That motion has been fully briefed and is awaiting decision. NorthWestern believes its claims are meritorious and we intend to vigorously prosecute this litigation. At this early stage of the litigation, however, we cannot predict the ultimate outcome of this matter or how it may affect our financial position, results of operations, or cash flows. In addition, the disposition of any recovery from this lawsuit will be subject to review by the MPSC.

        On or about March 7, 2003, plaintiff Dana Ross, individually and on behalf of a class of all others similarly situated, filed a complaint alleging breach of fiduciary duty and violations of federal securities fraud laws (including Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder) against Merle D. Lewis (the former Chairman and Chief Executive Officer of the Company), Kipp D. Orme (the Company's Vice President-Finance and Chief Financial Officer), and the Company. The lawsuit is entitled Dana Ross, et al. v. Merle D. Lewis, et al.; Case No. CIV03-4049, In the United States District Court of South Dakota, Southern Division. The putative class consists of all public investors who purchased common stock of NorthWestern from August 2, 2000 to December 13, 2002. Plaintiffs allege that defendants misrepresented NorthWestern's business operations and financial performance, overstated NorthWestern's revenue and earnings, among other things, by maintaining insufficient reserves for accounts receivables at Expanets, failed to disclose billing problems and lapses and data conversion problems, and failed to make full disclosures of problems (including the billing and data conversion issues) arising from the implementation of Expanets' EXPERT system. Plaintiffs' complaint alleges that NorthWestern's public statements, omissions, and failures to maintain adequate accounts receivables reserves artificially inflated NorthWestern's earnings and stock price, and that the class has been damaged as a result. The action seeks unspecified compensatory damages, rescission, and attorneys fees and costs as well as accountants and experts fees. The lawsuit has not yet been served. Given that it was only recently filed, we are not able to assess the likely outcome or risk of an adverse decision in this matter.

        On February 18, 2003 our Board authorized a Special Committee of the Board to evaluate Mr. Hylland's performance and conduct in connection with the management of the Company and its subsidiaries. The Board directed the Special Committee to make detailed findings regarding the evaluated conduct and to recommend to the Board the appropriate action, if any, to be taken with respect thereto. The Special Committee is nearing the completion of its evaluation. On April 10, 2003 we received a letter from Mr. Hylland asserting that there has occurred a fundamental change in connection with his employment under his employment agreement. We have provided to Mr. Hylland a

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notice that we have received his letter and will respond to him in due course. We have also notified Mr. Hylland that his notice may be defective for a number of reasons including failure to provide a reasonable time in which we have the right to cure. In any event, we dispute that a fundamental change has occurred and intend to vigorously defend any such claim.

        We and our partner entities are parties to various other pending proceedings and lawsuits, but in the judgment of our management, the nature of such proceedings and suits and the amounts involved do not depart from the routine litigation and proceedings incident to the kinds of business we conduct, and management believes that such proceedings will not result in any material adverse impact on us.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

        No matters were submitted to a vote of our security holders during the quarter ended December 31, 2002.

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Part II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

        Our common stock, which is traded under the ticker symbol NOR, is listed on the New York Stock Exchange. The following are the high and low sale prices for our common stock for each full quarterly period in the periods shown and the cash dividends paid per share during each period:

QUARTERLY COMMON STOCK DATA

        On April 10, 2003, the last reported sale price on the New York Stock Exchange for our common stock was $2.41.

        Consistent with our turnaround plan to increase liquidity and reduce debt, the Board of Directors decided to terminate the historical practice of paying an annual cash dividend. We do not anticipate paying any cash dividends for the foreseeable future. In addition, we are currently prohibited from paying dividends on our common stock under Delaware law. To the extent that payment of a cash dividend on our common stock becomes permissible under Delaware law, we would only be able to pay a cash dividend on our common stock to the extent that all required distributions on our mandatorily redeemable preferred securities of our subsidiary trusts had been made. Our senior secured term loan also prohibits the payment of dividends during any period of default.

        We have established four wholly owned, special-purpose business trusts, NWPS Capital Financing I, NorthWestern Capital Financing I, NorthWestern Capital Financing II and NorthWestern Capital Financing III, to issue common and preferred securities and hold subordinated debentures that we issue and The Montana Power Company established Montana Power Capital I (Trust) as a wholly owned business trust to issue common and preferred securities and hold subordinated debentures that it issued. We assumed the obligations of The Montana Power Company under the subordinated debentures that it issued to Montana Power Capital I November 15, 2002. The sole assets of these trusts are the investments in subordinated debentures, which are interest bearing. We have the right, on one or more occasions, to defer interest payments in the subordinated debentures for up to 20 consecutive quarterly periods unless a default under the subordinated debentures has occurred and is continuing. If we defer interest payments on the subordinated debentures, cash distributions on our trust preferred securities will also be deferred. During this deferral period, distributions will continue to accumulate on both the trust preferred securities and deferred distributions at their respective rates. During any period in which we defer interest payments on the subordinated debentures, we will not, with some exceptions, be permitted to pay any dividends or distributions in respect of our capital stock;

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redeem, purchase or make liquidation payments on our capital stock; make principal, premium or interest payments or repurchase or redeem any of our debt securities that rank equal with or junior to the subordinated debentures; or make any payments with respect to any guarantee of debt securities of any of our subsidiaries, including other guarantees, if such guarantee ranks equal with or junior to the subordinated debentures. Given our significant debt, our board of directors will review the appropriateness of each periodic interest payment under the subordinated debentures in light of, among other factors, the progress of our turnaround plan and our liquidity needs.

        Blue Dot may not pay any dividend or make any distribution to NorthWestern, except under certain circumstances, without the consent of the lenders under its credit facility.

Holders

        As of April 7, 2003 there were 10,322 holders of record of 37,396,762 outstanding shares of our common stock.

Securities Authorized for Issuance under Equity Compensation Plans

        The following table presents summary information about our equity compensation plans, including our employee stock ownership plan, our stock option and incentive plan and any individual stock option arrangements not arising under any plan. The table presents the following data on plans approved by stockholders and plans not so approved, all as of the close of business on December 31, 2002 (treating all employee stock purchase plan transactions occurring on such date on an as-settled basis):

(i)

the aggregate number of shares of our common stock subject to outstanding stock options, warrants and rights;



(ii)

the weighted-average exercise price of those outstanding stock options, warrants and rights; and



(iii)

the number of shares that remain available for future option grants, excluding the number of shares to be issued upon the exercise of outstanding options, warrants and rights described in (a) above.

For additional information regarding our stock option plans and the accounting effects of our stock-based compensation, please see Notes 2 and 17 to our Financial Statements included in Item 8 herein.

(1)

The Stock Option and Incentive Plan, as amended, provides that 12.5% of the outstanding shares of Common Stock of the Company, as of January 1^st of each year, are available for issuance under the plan.

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(2)

Under the Team Member Stock Purchase Plan, shares are acquired at the time of investment by the participating team member, at the applicable discount price.

ITEM 6. SELECTED FINANCIAL DATA

FIVE-YEAR FINANCIAL SUMMARY

(1)

The fixed charges exceeded earnings, as defined by this ratio, by $764.6 million, $138.1 million and $24.7 million in 2002, 2001 and 2000, respectively.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion and analysis should be read in conjunction with "Item 6. Selected Financial 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 23 of "Notes to Consolidated Financial Statements" of our consolidated financial statements, which are included in Item 8 herein. For information regarding our revenues, profits/losses and assets, see our consolidated financial statements included in Item 8 hereof.

OVERVIEW

        We operate our business in five reporting segments:

•

electric utility operations;

•

natural gas utility operations;

•

communications;

•

HVAC, plumbing and related services; and

•

all other, which primarily consists of our other miscellaneous service and non-energy related operations and activities that are not included in the other identified segments, together with the unallocated corporate costs and investments, and any eliminating amounts.

        Our financial condition has been significantly and negatively affected by the poor performance of our non-energy businesses and our significant indebtedness. NorthWestern reported losses on common stock for the year ended December 31, 2002, of $892.9 million or $30.04 per diluted share, compared with earnings on common stock of $37.5 million or $1.53 per diluted share in 2001. Full-year 2002 results were negatively impacted by $878.5 million in charges as further described below.

        In February 2003, we outlined the elements of a turnaround plan intended to strengthen our balance sheet and improve our financial performance. The primary elements of our turnaround plan are to focus on our core electric and natural gas utility business and a commitment to reduce our debt through the application of proceeds from the sale of non-core assets, including Expanets, Blue Dot, our Colstrip Transmission Line and the Montana First Megawatts generation project. Absent proceeds from the sale of non-core assets, significant improvements in the operating results of our non-energy businesses, restructuring of our debt or raising additional capital, we will not have the ability to materially reduce our debt and our ability to fund our operations and service our substantial indebtedness will be adversely affected.

        Consolidated revenues for 2002 were $2.0 billion, a 15.5 percent increase from $1.7 billion in 2001. Sales growth in 2002 was driven primarily by an increase in revenues from our newly acquired Montana electric and natural gas operations of $590.5 million as well as increased sales of $48 million, at Blue Dot, our heating, ventilation and air conditioning business, primarily from acquisitions. Consolidated revenues were adversely impacted by decreased revenues from Expanets of $321.6 million, our communications services business, due to deteriorating telecommunications markets and problems with its EXPERT system.

        Our electric and natural gas utility segments, combined, reported 2002 operating income of $145.0 million, compared with operating income of $45.9 million in 2001. Revenues for 2002 grew to $775.4 million, a substantial increase from revenues of $251.2 million in 2001. On February 15, 2002, we completed the acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company for $478.0 million in cash and the assumption of $511.1 million in existing debt and mandatorily redeemable preferred securities of subsidiary trusts of The Montana Power Company, net of cash received. Results for 2002 include 11 months of Montana utility operations. In 2002, our Montana utility operations contributed $113.1 million in operating income,

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with revenues of $562.6 million, excluding results from January 2002. South Dakota and Nebraska utility operations contributed $31.9 million in operating income in 2002, with revenues of $212.7 million.

        For 2002, Expanets reported an operating loss of $391.9 million, compared with an operating loss of $102.6 million in 2001. Expanets' revenues for 2002 were $710.5 million, compared with $1.03 billion in 2001. The decline in revenue was the result of a downturn in the economy generally and the telecommunications equipment market specifically, a focus on higher margin revenues and challenges with Expanets' EXPERT system implementation that have contributed to erosion of Expanets' customer base. Results for 2002 were also adversely impacted by goodwill and long-lived asset impairments taken in the fourth quarter of 2002 of $288.7 million and a $65.8 million increase in reserves and write-offs for billing adjustments, accounts receivable and direct write-offs relating to complications with Expanets' EXPERT enterprise software system.

        Blue Dot reported an operating loss in 2002 of $311.3 million, compared with an operating loss of $13.8 million in 2001. Blue Dot's results were impacted by goodwill and long-lived asset impairments in the fourth quarter of 2002 of $301.7 million and poor economic conditions. Revenues were $471.8 million in 2002, compared with revenues in 2001 of $423.8 million. The increase in revenues was primarily due to acquisitions made during 2001 and 2002.

        In our All Other segment, we had an operating loss in 2002 of $71.4 million, compared with an operating loss of $26.4 million in 2001. Revenues for the All Other segment in 2002 were $33.9 million, an increase of $16.9 million from 2001. The increase was primarily due to $27.9 million from the newly acquired Montana non-utility operations, offset by reduced revenues from the South Dakota and Nebraska non-utility voice and data networks business, which was transferred to Expanets mid-year.

        On August 20, 2002, NorthWestern purchased the lenders' interest in approximately $19.9 million of short-term debt, together with approximately $6.1 million in letters of credit, of CornerStone outstanding under CornerStone's credit facility, which NorthWestern had previously guaranteed. No further drawings may be made under this facility. In addition, NorthWestern is owed $13.5 million from CornerStone and NorthWestern also has $9.2 million in letters of credit outstanding on behalf of CornerStone. As of December 31, 2002, the net recorded value of our receivables from and letters of credit exposure related to CornerStone was an aggregate $21.1 million.

SIGNIFICANT CHARGES FOR 2002

        During 2002, we recorded the following charges aggregating approximately $878.5 million:

        Goodwill and Other Long-Lived Assets—Expanets and Blue Dot.    We established our annual review of goodwill as required by SFAS No. 142, as of October 1, 2002. Impairment charges under the requirements of SFAS No. 142 and SFAS No. 144 for our goodwill and other long-lived assets were $301.7 million for Blue Dot and $288.7 million for Expanets, including $69.6 million for the impairment of Expanets' EXPERT system. Various factors contributed to the significantly reduced valuations of

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Expanets and Blue Dot, including lower than expected performance, revised growth rate assumptions and reduced holding period assumptions, which negatively impacted the fair value of Expanets and Blue Dot.

        Discontinued Operations of CornerStone.    As a result of the deconsolidation transaction on November 1, 2002, we no longer have any economic interest in Cornerstone, other than the debt interests described above. During 2002, we recorded charges totaling $101.7 million for the write down of the value of our investment and financial arrangements in CornerStone and our share of net operating losses.

        Deferred Tax Allowance.    As a result of the lower than expected performance and significant charges associated with our non-utility businesses, we evaluated the realization of our net deferred tax assets and determined that a valuation allowance was appropriate due to the uncertainty of realizing certain tax benefits in the future, which resulted in a charge of $71.5 million (excluding a tax valuation allowance totaling $78.0 million relating to the impairment of Blue Dot's and Expanets' goodwill and other long-lived assets and Expanets' billing adjustments, accounts receivable write-offs and reserves). The deferred tax assets consisted primarily of net operating loss carry forwards and temporary differences associated with our non-utility businesses.

        Expanets Adjustments and Write-Offs.    Expanets recorded a reduction in revenues of $28.0 million for pending billing adjustments and recorded accounts receivable and other write-offs and related reserves of $37.8 million primarily related to complications with its EXPERT system billing and related data migration issues.

        Montana First Megawatts.    As of and at December 31, 2002, we determined that absent regulatory approval of the Montana First Megawatts' power sales contract with NorthWestern Energy, the value of the project was equal to the estimated salvage value of project equipment. Accordingly, we recorded an impairment charge of $35.7 million against our investment of approximately $78.4 million in the project. Due to adverse changes to the independent power generation development market, absent receipt of necessary regulatory approvals of the power sales contract, there is no assurance that we will be able to sell this asset at a favorable price, if at all, and therefore, we may be required to take additional charges.

        Retirement of Acquisition Term Loan.    In March 2002, we retired a $720 million term loan that was used for interim financing for the acquisition of the transmission and distribution business of The Montana Power Company. The recognition of deferred costs related to the interim financing resulted in an extraordinary loss of $13.4 million net of taxes.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

        Management'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. 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 and intangible assets, impairment of long-lived assets, revenue recognition, allowance for doubtful accounts, and minority interest in consolidated subsidiaries, 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's judgments and estimates.

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Goodwill and Indefinite-Lived Intangible Assets

        We believe that the accounting estimate related to determining the fair value of goodwill, and thus any impairment, is a "critical accounting 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 has had a significant impact on the assets reported on our balance sheet and our operating results. Management'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.

        SFAS No. 142 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 and indefinite-lived intangible assets for impairment at least annually 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 the impairment loss to recognize, we compare the implied fair value of the reporting unit's goodwill with its carrying value. Our reporting units are consistent with our reporting segments as indentified in Note 23 of "Notes to Consolidated Financial Statements" included in Item 8 herein.

        We adopted SFAS No. 142 effective January 1, 2002 and retained a third party appraisal firm who performed an evaluation and determined that no impairment charge was necessary at the date of adoption, and selected October 1 as the date for our annual goodwill impairment test. The annual independent third party valuations for Expanets and Blue Dot were completed as of October 1, 2002 using a discounted cash flow approach based on forward-looking information regarding market share, revenues and costs for each reporting unit. We also prepared an internal valuation for our Montana utility operations as of October 1, 2002. Various factors contributed to the significantly reduced valuations of Expanets and Blue Dot, including lower than expected performance, revised growth rate assumptions and reduced holding period assumptions, which negatively impacted the fair value of Expanets and Blue Dot. As a result, we determined that a substantial impairment to our investment in these companies had occurred and we recorded an impairment charge to goodwill and indefinite-lived intangible assets of $483.4 million during the fourth quarter of 2002.

Long-lived Assets

        We evaluate our property, plant and equipment and definite-lived intangible assets for impairment whenever indicators of impairment exist. SFAS No. 144 requires that if the sum of the undiscounted cash flows from a company's asset, without interest charges that will be recognized as expenses when incurred, 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, the amount of the impairment loss recognized represents the excess of the asset's carrying value as compared to its estimated fair value, based on management's assumptions and projections.

        We recorded impairment charges of $69.6 million to write down the carrying amount of Expanets' EXPERT system and $25.4 million to write down the carrying amount of certain Expanets definite-lived intangible assets to their estimated fair value. These assets were identified as being carried at values that may not be recoverable due to the significant EXPERT operating deficiencies; the non-utility investment restrictions placed on us by the Montana Public Service Commission, or the MPSC; and the unfavorable business climate within the telecommunications industry.

        We recorded an impairment charge of $35.7 million to write down the carrying amount of our investment in a 260-megawatt natural gas-fired generation project located in Great Falls, Montana. Based on certain events occurring during the fourth quarter of 2002, we have determined as part of our

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restructuring plan to divest of this project and the assets have been written down to expected realizable value.

        We recorded an impairment charge of $12.0 million to write off the carrying amount of Blue Dot property, plant and equipment and definite-lived intangible assets. These assets were identified as being carried at values that may not be recoverable, due to current and projected financial performance and to the non-utility investment restrictions placed on us by the MPSC.

Revenue Recognition

        Revenues are recognized differently depending on the type of revenue. For NorthWestern Energy's South Dakota and Nebraska operations, as prescribed by the respective regulatory authorities, electric and natural gas utility revenues are based on billings rendered to customers. Customers are billed on a monthly cycle basis. For NorthWestern Energy's Montana operations, as prescribed by the MPSC, operating revenues are recorded monthly on the basis of consumption or services rendered. 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.

        Communications and HVAC revenues are recognized when goods are delivered to customers or services are performed, except for revenues for services performed under certain material installation or service contracts, which are recognized in any given period based on the percentage of costs incurred to date in relation to total estimated costs to complete the contracts. Revenues at Expanets for certain other material and installation contracts are recognized on the completed contract method of accounting due to the inability to adequately estimate gross margins for these contracts. Certain judgments affect the application of our revenue recognition policy, primarily percentage of project completion. Revenue estimates in these areas are difficult to predict, and any shortfall in revenue or delay in recognizing revenue could cause our operating results to vary significantly from quarter to quarter and could materially impact future operating results. We continue to experience serious difficulties with the EXPERT system billing function. We provide a monthly reserve for billing adjustments at a rate in excess of industry standards, which we believe to be appropriate in our circumstances.

Allowances for Doubtful Accounts

        We maintain a general allowance for doubtful accounts based on our historical experience, along with additional customer-specific allowances. We regularly monitor credit risk exposures in our accounts receivable. In estimating the necessary level of our allowance for uncollectible accounts, management considers the aging of its accounts receivable, the creditworthiness of our customers, economic conditions within the customer's industry, and general economic conditions, among other factors. When these factors change, the estimates made by management also change, which in turn impacts the level of our allowance for uncollectible accounts. The lack of reliable detailed accounts receivable information from the EXPERT system has negatively impacted our ability to estimate the approximate level of our allowances for uncollectible accounts, which contributed to a substantial increase in our allowance for uncollectible accounts.

Regulatory Assets and Liabilities

        Our regulated operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process. 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, the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities would need to be evaluated. In addition, we would need to determine if there was any impairment to the carrying costs of deregulated plant and inventory assets.

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While we believe that our assumption regarding future regulatory actions is reasonable, different assumptions could materially affect our results.

Pension and Postretirement Benefit Plans

        With the acquisition of our Montana electric and natural gas transmission and distribution business from The Montana Power Company, our pension and other postretirement benefit obligations significantly increased. Our reported costs of providing pension and other postretirement benefits, as described in Note 13 of "Notes to the Consolidated Financial Statements" contained in Item 8, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

        Pension and other postretirement benefit costs, for example, are impacted by actual employee demographics (including age and compensation levels), the level of contributions we make to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of the plans may also impact current and future other postretirement benefit costs. Other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the postretirement benefit obligation and postretirement costs. Our expected rate of return on assets was 8.50% for 2002. A 6.50% discount rate was used to determine our post-retirement benefit obligation as of December 31, 2002.

        As a result of the factors listed above, significant portions of other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to pension plan participants.

        Our pension and other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension and other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension and other postretirement benefit costs.

Qualifying Facilities Liability

        With the acquisition of our Montana electric and natural gas transmission and distribution business from The Montana Power Company, we assumed a liability for costs associated with certain Qualifying Facilities, or QFs. The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our gross contractual obligation related to the QFs is approximately $1.9 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.5 billion through 2029. Upon completion of the purchase price allocation related to our acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company, we established a liability of $134.3 million, based on the net present value of the difference between our obligations under the QFs and the related amount recoverable. The determination of the discount rate used to establish this liability was a significant assumption. We determined the appropriate discount rate to be 8.75%, in accordance with Statement of Financial Accounting Concepts No. 7, Using Cash Flow Information and Present Value in Accounting Measurements. We believe that 8.75% approximates the rate we could have negotiated with an independent lender for a similar transaction under comparable terms and conditions as of the acquisition date.

Minority Interest in Consolidated Subsidiaries

        Substantially all of our acquisitions at Expanets and Blue Dot have involved the issuance of common and preferred stock in those subsidiaries to the sellers of the acquired businesses. In connection with certain acquisitions of Expanets and Blue Dot, the sellers can elect to exchange the

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stock of Expanets and Blue Dot for cash or in certain circumstances, at the election of NorthWestern, shares of common stock of NorthWestern that have been registered for resale, at a predetermined exchange rate. Our investments in Expanets and Blue Dot are principally in the form of senior preferred stock with voting control and a liquidation preference over such common and preferred stock. We are required to consolidate the financial results of Expanets and Blue Dot because of our voting control. The common stock issued to third parties in connection with acquisitions creates minority interests which are junior to our preferred stock interests. Operating losses at Expanets and Blue Dot have been allocated first to the common shareholders of each subsidiary in proportion to common equity ownership to the extent the allocation does not exceed the minority interest of such common shareholders in the equity capital of the subsidiary after giving effect to any put options or exchange agreements, and thereafter is allocated to the preferred shareholders of each subsidiary in the order of priority equal to the liquidation preference of each series of preferred stock. Exchange agreements totaling $6.0 million for Expanets and $3.9 million for Blue Dot remained outstanding and were included in minority interests as of December 31, 2002. The equity held by third parties of these entities is as follows:

        See also "Liquidity and Capital Resources—Other Contractual Obligations" for discussion of additional equity instruments held by third parties that are not reflected in Minority Interests.

        The Minority Interests in Net Loss of Consolidated Subsidiaries contained in our consolidated statements of income (loss) is the income (loss) of our subsidiaries which is allocable to minority interests. In order to determine the allocation of income (loss) to minority interests, preferred dividends and corporate services allocations are deducted from the income (loss) before minority interests reported in our segment disclosures in order to arrive at the Minority Interests in Net Loss of Consolidated Subsidiaries contained in our consolidated statements of income. The corporate allocations relate to certain services NorthWestern provides to its subsidiaries for management services, including insurance, legal, human resources and benefit administrative support for employee benefits, transaction structuring, financial analysis, tax services and information technology. These services are discussed in Note 2 "Significant Accounting Policies—Minority Interest in Consolidated Subsidiaries" to NorthWestern's annual consolidated financial statements. The preferred dividends relate to dividends on our 12% coupon Preferred Stock of Expanets and our 11% coupon Preferred Stock of Blue Dot. The preferred dividends and corporate allocations are eliminated in consolidation. The net income (loss) before minority interests and net income (loss) available to common equity holders reported in our segment disclosures includes the portion of interest expense on our $205.7 million intercompany balance due from Expanets which is allocable to third party minority interests.

        The following tables demonstrate the reconciliation of income (loss) before minority interests reported in NorthWestern's segment disclosures for its communications and HVAC segments, the only two segments that have Minority Interest, to Minority Interests in Net Loss of Consolidated Subsidiaries contained in its consolidated statements of income for the periods indicated. All amounts in boxes are reflected directly within NorthWestern's consolidated financial statements. All other amounts support the derivation of those numbers.

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        Preferred dividends for the year ended December 31, 2002 of $39.8 million and $43.4 million for Blue Dot and Expanets, respectively, which were either paid in kind through the issuance of additional preferred stock or credited against intercompany balances, represent increases of $11.6 million and $10.3 million, respectively, which reflect increased investments by NorthWestern in the preferred stock of each entity. Corporate allocations for 2002 of $2.1 million and $4.2 million for Blue Dot and Expanets, respectively, represent decreases of $1.0 million and $3.8 million, respectively, from amounts in 2001. The decreases reflect decreased services provided by NorthWestern, which are now performed by and directly expensed by each entity.

(1)

Expanets' loss before minority interests includes $9.5 million of after tax interest expense on amounts due to NorthWestern.

        Preferred dividends for the year ended December 31, 2001 of $28.2 million and $33.1 million for Blue Dot and Expanets, respectively, represent increases of $8.6 million and $7.2 million, respectively, which reflect increased investments by NorthWestern in the preferred stock of each entity. Corporate allocations for 2001 of $3.0 million and $8.0 million for Blue Dot and Expanets, respectively, represent increases of $0.7 million and $3.7 million, respectively, from amounts in 2000. The increase at Expanets is due to increased services provided by NorthWestern primarily related to the non-recurring transition and integration expenses related to the acquisition of the Lucent GEM assets. The increase at Blue Dot is due to continued increased involvement and corporate services provided by NorthWestern.

(1)

Expanets' loss before minority interests includes $4.4 million of after tax interest expense on amounts due to NorthWestern.

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(1)

Expanets' loss before minority interests includes $0.4 million of after tax interest expense on amounts due to NorthWestern.

        As of December 31, 2002, no remaining minority interest basis existed with respect to Blue Dot and Expanets against which losses could be allocated. Accordingly, any future losses at Blue Dot and Expanets will be recognized in our operating results. Different capital structures in the future or unanticipated future operating results, either positive or negative, could result in materially different results.

RESULTS OF OPERATIONS

        The following is a summary of our results of operations in 2002, 2001 and 2000. 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. Our "All Other" category primarily consists of our other miscellaneous service activities, which are not included in the other identified segments together with unallocated corporate costs. See "—Segment Information—All Other Operations" for a discussion of the items contained in our "All Other" category. Product and service category fluctuations highlighted at the consolidated level are more fully explained in the segment discussion.

Consolidated Earnings (Loss).

        Consolidated losses on common stock in 2002 were $892.9 million, compared to consolidated earnings on common stock in 2001 of $37.5 million. Diluted earnings per share, or EPS, in 2002 was $(30.04), a decline of $31.57, from 2001 results. The decline in earnings in 2002 is largely due to impairment charges of $301.7 million at Blue Dot, $288.7 million at Expanets and $35.7 million related to the Montana First Megawatts project. Also contributing to the loss were $101.7 million, net of taxes, of additional losses associated with the discontinued operations of CornerStone, $65.8 million related to billing adjustments and accounts receivable reserves and write-offs at Expanets, a deferred tax asset valuation allowance of $71.5 million, and an extraordinary charge of $13.4 million, net of taxes, related to refinancing debt. In addition, interest expense increased by $80.3 million, primarily related to financings to facilitate the acquisition of NorthWestern Energy's Montana operations. These amounts were offset partially by $30.7 million of increased earnings in our electric and natural gas operations due primarily to the acquisition of NorthWestern Energy's Montana operations. Consolidated earnings on common stock in 2001 were $37.5 million, a decline of $5.2 million, or 12.3%, from 2000 results. Consolidated earnings on common stock in 2001 were reduced by a $24.9 million restructuring charge ($12.1 million net of taxes and minority interests) taken in the fourth quarter. The 2001 restructuring charge reduced diluted EPS by $0.50 per share. The $24.9 million restructuring charge related principally to facility closure costs, employee termination benefits and related costs incurred in connection with a series of company wide initiatives targeting reductions in annualized selling, general and administrative expenses.

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Consolidated Operations.

        Consolidated revenues in 2002 were $1,991.5 million, an increase of $267.5 million, or 15.5%, from 2001. The increase in 2002 was due to an increase in revenues from the electric and natural gas operations of $524.2 million as a result of the inclusion of NorthWestern Energy's Montana operations, a $48.0 million increase in revenues at Blue Dot, primarily due to acquisitions, and a $16.9 million increase in revenues from our All Other operations as a result of the addition of certain non-utility operations acquired with NorthWestern Energy's Montana operations. This increase was offset in part by a decrease in revenues at Expanets of $321.6 million as a result of the downturn in the economy and the telecommunications industry, certain data migration and system implementation problems at Expanets and a decrease in revenues at NorthWestern Energy's South Dakota and Nebraska operations of $32.1 million as a result of warmer weather in their service areas in 2002 and wholesale energy price decreases. Consolidated revenues in 2001 were $1,724.0 million, an increase of $14.5 million, or 0.8%, from 2000 results. The increase in 2001 was primarily due to increased revenues in our electric and natural gas segments of $69.9 million and increased revenues at Blue Dot of $15.0 million. This increase was partially offset by a decline in revenues at Expanets of $72.0 million as a result of the downturn in the economy and the telecommunications industry in particular, primarily due to volume declines.

        Consolidated cost of sales in 2002 was $1,095.4 million, an increase of $26.1 million, or 2.4%, from 2001. NorthWestern Energy's Montana utility operations added $220.9 million in cost of sales and Blue Dot experienced a $38.7 million increase in cost of sales, which was partially offset by a $203.5 million decrease at Expanets, and a $24.3 million reduction in cost of sales at NorthWestern Energy's South Dakota and Nebraska utility operations. Consolidated cost of sales in 2001 was $1,069.4 million, a decline of $31.1 million, or 2.8%, from 2000 results. Expanets experienced a $92.5 million reduction in consolidated cost of sales. The reductions in cost of sales at Expanets were partially offset by increased cost of sales of $54.0 million in our electric and natural gas segments and increased cost of sales at Blue Dot of $7.0 million.

        Consolidated gross margin in 2002 was $896.1 million, an increase of $241.5 million, or 36.9%, from 2001. The increase was primarily due to $341.7 million in gross margin from the inclusion of NorthWestern Energy's Montana utility operations, an increase of $22.7 million in gross margin from All Other operations and a $9.3 million increase in gross margin at Blue Dot. These increases were offset in part by a $118.0 million decrease in gross margin at Expanets and a $14.2 million decrease in gross margins at our NorthWestern Energy's South Dakota and Nebraska utility operations. Consolidated gross margin in 2001 was $654.6 million, an increase of $45.6 million, or 7.5%, from 2000 results. Gross margin in 2001 increased across all of our segments. Expanets' gross margin increased $20.5 million, primarily as a result of the full year impact of the Lucent GEM business operations in 2001, which were acquired in April 2000. Gross margin in our electric segment increased $14.2 million, primarily as a result of increased wholesale electric margins during the first half of 2001, and gross margin in our natural gas segment increased $1.8 million. Blue Dot's gross margin increased $8.0 million as a result of acquisitions in 2001.

        Consolidated gross margin, as a percentage of revenues in 2002 was 45.0%, compared to 38.0% in 2001 and 35.6% in 2000. Increases in 2002 over 2001 were primarily provided by the inclusion of NorthWestern Energy's Montana electric, natural gas, and non-utility operations. Consolidated gross margin as a percentage of revenues in 2001 improved as a result of the gross margin gains described above, together with our efforts to reduce costs and increase higher-margin recurring service and maintenance revenues in our communications operations.

        Consolidated operating expenses in 2002, which includes selling, general and administrative expenses, or SG&A, goodwill and long-lived asset impairment charges, depreciation and amortization, were $1,525.7 million, an increase of $774.2 million, or 103.0%, from 2001. This increase was primarily

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due to goodwill and long-lived asset impairment charges of $301.7 million, $288.7 million and $35.7 million at Blue Dot, Expanets and All Other operations, respectively. Also contributing to this increase was the inclusion of $228.6 million in operating expenses, including $43.8 million of depreciation, from NorthWestern Energy's Montana utility operations. These increases were offset in part by a net decrease in SG&A, depreciation and amortization of $117.5 million at Expanets. Consolidated operating expenses in 2001 were $751.5 million, an increase of $146.8 million, or 24.3%, from 2000 results. Operating expenses increased in each of our segments in 2001 due in part to a $24.9 million restructuring charge related to our series of company wide initiatives targeting reductions in annualized selling, general and administrative expenses. Expanets incurred increased expenses of $92.6 million, excluding its portion of this restructuring charge of $5.9 million, related to additional Lucent GEM business operating costs together with additional non-capitalizable integration and transition costs. Blue Dot's operating expenses also increased $19.1 million, excluding its portion of this restructuring charge of $7.2 million, due to continued acquisition activities and infrastructure growth. The restructuring charges discussed above resulted in $3.3 million of the $6.2 million increase in operating expenses of our electric utility and $1.2 million of the $1.9 million increase in operating expenses of our natural gas segment. All Other operating expenses increased $6.6 million excluding the $7.2 million restructuring charge due to personnel additions and professional services to support our expanding subsidiary operations.

        Consolidated operating losses from continuing operations in 2002 were $629.6 million, an increase of $532.8 million from 2001. The increase in operating losses was primarily due to the impairment charges at Blue Dot, Expanets and All Other of $301.7 million, $288.7 million and $35.7 million, respectively, and a $14.0 million decrease in operating income at NorthWestern Energy's South Dakota and Nebraska utility operations, which was partially offset by the inclusion of $113.1 million of operating income from NorthWestern Energy's Montana utility operations. Consolidated operating losses from continuing operations in 2001 were $96.9 million, compared to consolidated operating income from continuing operations in 2000 of $4.3 million. The $101.2 million change in operating income was due to a $78.0 million increase in operating loss at Expanets, an $18.4 million decline in operating income at Blue Dot, and a $12.7 million increase in All Other operating loss. These losses were partially offset by an $8.0 million operating income increase within our electric segment.

        Investment losses and other in 2002 was $5.4 million, a decrease of $13.4 million from investment income and other of $8.0 million in 2001. The decrease was primarily due to capital losses on miscellaneous investments. Investment income and other in 2001 decreased slightly to $8.0 million from $9.0 million in 2000. Gains from stock sales during the fourth quarter of 2001 were partially offset by realized losses on the write-down of certain investments. Overall investment income was also negatively impacted by lower interest rates and overall stock portfolio performance during 2001.

        Consolidated interest expense in 2002 was $129.5 million, an increase of $80.3 million, or 163.0%, from 2001. The increase was primarily due to increased financings to facilitate the acquisition of NorthWestern Energy's Montana operations. Interest expense in 2001 was $49.2 million, an increase of $11.3 million, or 29.7%, from 2000 results. The increase in interest expense was primarily attributable to financings by Expanets, where interest expense increased $13.3 million, and was offset partially by a decrease in interest expense at Blue Dot resulting from reduced credit facility borrowings.

        Consolidated income tax benefit in 2002 was $0.8 million, a decrease of $41.7 million from 2001. The decrease in the tax benefit was primarily related to a valuation allowance against the deferred tax assets and current net operating losses of Expanets and Blue Dot. The 2002 benefit has been reduced by a valuation allowance comprised of $121.6 million against the net deferred tax assets of Expanets and $27.9 million against the net deferred tax assets of Blue Dot, due to the significant losses of these subsidiaries. The valuation allowance has been established because management believes it is more likely than not that these deferred tax assets will not be realized. Consolidated income tax benefit in 2001 was $42.5 million, an increase of $36.0 million over the income tax benefit in 2000. Over 50% of

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the increase resulted from the tax benefit at Expanets, which was the result of a significant increase in operating losses in 2001. Lower taxable income at Blue Dot as a result of operating losses further increased the benefit, as did higher All Other operating expenses. The income tax benefits were partially reduced by increased tax expense at our electric and natural gas segments.

        Minority interests represent the net income or loss, after preferred dividends and corporate allocations related to our preferred stock investments in Expanets and Blue Dot, which are allocable to common shareholders other than us. Minority interests in 2002 were $14.9 million, a decrease of $126.5 million, or 89.5%, from 2001. The decrease was due to the depletion of available minority interest basis against which to allocate losses of Expanets and Blue Dot. After March 31, 2002, all losses were fully allocated to NorthWestern. Minority interests in 2001 were $141.4 million, an increase of $73.6 million, or 108.6%, from 2000. All of the increase was due to Expanets, where losses increased substantially in 2001, which was partially offset by reduced allocations at Blue Dot due to reduction in available basis to absorb the losses. Due to adequate basis in 2001 and 2000, substantially all losses by Expanets and Blue Dot were allocated to minority interests. Based on the entities' capital structures at December 31, 2002, any future losses at Expanets and Blue Dot will be allocated to us. See "—Critical Accounting Policies and Estimates—Minority Interest in Consolidated Subsidiaries" for a discussion of the allocation of income (loss) to minority interests and the changes in such allocations during the periods discussed.

Electric Utility Segment Operations.

        Revenues from our electric utility operations in 2002 were $535.0 million, an increase of $428.0 million, or 400.1%, from 2001 results. This increase was almost exclusively attributable to the addition of NorthWestern Energy's Montana operations, effective February 1, 2002, which contributed $442.5 million of revenues for the year. The volume of wholesale and retail megawatt hours sold in 2002 for our Montana operations was 1.4 million and 6.7 million, respectively. In addition, our South Dakota operations contributed revenues of $92.5 million for 2002, which was a decrease of $14.5 million, or 13.5%, from 2001. This decrease in revenues was principally the result of a decrease of $16.1 million in wholesale electric revenues within the South Dakota operations due to market price declines. The volume of wholesale megawatt hours sold in 2002 for our South Dakota operations decreased by 6.2%, however, the volume of retail megawatt hours sold increased by 0.3%. Revenues from our electric utility operations in 2001 were $107.0 million, an increase of $20.4 million, or 23.6%, from 2000 results. The increase in revenues was principally the result of increased wholesale market prices for electricity. Revenues from our wholesale sales of electricity in 2001 were $13.6 million greater than the $9.3 million of revenues generated from such sales in 2000. The increase in wholesale sales revenues was principally due to unusual market conditions during the first half of 2001, and was partially offset by lower sales volume. The volume of wholesale megawatt hours sold in 2001 decreased by 3.4%; however, the volume of retail megawatt hours sold in 2001 increased by 4.4%. Revenues from retail sales of electricity increased by 8.9% in 2001, from $77.3 million in 2000 to $84.2 million in 2001. The increase in retail sales revenue in 2001 was principally due to a growing customer base combined with higher fuel costs that are passed through to customers.

        Cost of sales for our electric utility operations in 2002 was $205.6 million, an increase of $182.6 million, or 791.9%, from 2001 results. This increase was nearly all due to the addition of NorthWestern Energy's Montana operations, which increased costs by $182.0 million. In addition, our South Dakota operations experienced a $0.6 million increase in costs related to the increase in sales volume. The cost of sales for our electric utility operations in 2001 was $23.1 million, an increase of $6.3 million, or 37.4%, from 2000 results. The increase in cost of sales in 2001 was due principally to retail fuel cost adjustments and increased volumes.

        Gross margin in 2002 was $329.4 million, an increase of $245.5 million, or 292.5%, over the 2001 gross margin of $83.9 million. This increase was primarily due to the contribution of $260.5 million in

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gross margin from NorthWestern Energy's Montana operations. Partially offsetting this increase was a decrease in gross margin by our South Dakota operations of $15.0 million, or 17.9%, as a result of a substantial decrease in market prices for wholesale electricity as compared to the unusually high market prices in 2001. Overall gross margin as a percentage of revenues in 2002 was 61.6%, as compared to 78.5% in 2001. This decrease was the result of the substantial decline in wholesale electric margins from market price fluctuations and the influence of NorthWestern Energy's lower margin Montana operations as compared to our South Dakota operations. Gross margin in 2001 was $83.9 million, an increase of $14.2 million, or 20.3%, over the 2000 gross margin of $69.8 million. The increase in gross margin in 2001 resulted primarily from the unusual wholesale market conditions and the 4.4% increase in retail sales. Gross margin as a percentage of revenues in 2001 was 78.5%, compared to 80.6% in 2000, a decrease primarily as a result of increased fuel costs in 2001.

        Operating expenses, consisting of selling, general and administrative (SG&A) and depreciation expenses, were $218.3 million in 2002, an increase of $174.1 million, or 393.3%, over the 2001 results. This increase was nearly all due to the addition of NorthWestern Energy's Montana operations, which increased SG&A costs by $141.9 million and increased depreciation expense by $35.4 million. Partially offsetting this increase was a decrease in SG&A of $3.5 million by our South Dakota operations, resulting primarily from operational efficiencies, a reduction in benefit costs, the establishment of a capital lease for our lease programs, and the occurrence in 2001 of a restructuring charge. Operating expenses in 2001 were $44.3 million, an increase of $6.2 million, or 16.3%, from 2000 results. This increase was primarily caused by a restructuring charge of $3.3 million, together with small increases in allocated power plant maintenance costs associated with increased generation, higher team member benefits expenses, increased customer service costs and higher depreciation related to additional investments in power plants. Higher operating expenses in 2001 were partially offset by lower transmission and distribution expenses.

        Operating income in 2002 was $111.1 million, an increase of $71.4 million, or 180.0%, over 2001. The increase was attributable to the addition of approximately $83.2 million in operating income from NorthWestern Energy's Montana operations, while the South Dakota operations experienced a decrease of $11.8 million in operating income from the absence of unusually high margin wholesale electric sales in 2002 countered, in part, by lower operating expenses in 2002. Operating income in 2001 was $39.7 million, or $43.0 million before restructuring charges, representing an increase of $8.0 million, or 25.1%, over 2000. The increase in operating income was a result of increased higher margin wholesale sales revenue, partially offset by higher operating expenses in 2001.

Natural Gas Utility Segment Operations.

        Revenues from our natural gas utility operations in 2002 were $240.3 million, an increase of $96.1 million, or 66.6%, from 2001 results. Revenues for the period reflect the inclusion of NorthWestern Energy's Montana operations, which contributed $120.1 million in revenues. In addition, our South Dakota operations contributed revenues of $120.2 million for 2002, which was a decrease of $24.0 million, or 16.7%, from 2001. This decrease was principally the result of a drop in commodity prices reflected within the South Dakota operations during 2002 compared to 2001, and a decrease in volumes as a result of warmer weather in the Nebraska and South Dakota service territories in 2002 than in 2001. Revenues from natural gas sales in 2001 were $144.2 million, an increase of $49.5 million, or 52.2%, from 2000 results. The increase was largely attributable to higher market prices for natural gas and a slight increase in the volume of sales.

        Cost of sales for our natural gas utility operations in 2002 was $133.1 million, an increase of $14.1 million, or 11.8%, from the 2001 results. Cost of sales for the period reflect the inclusion of NorthWestern Energy's Montana operations, which contributed $38.9 million in cost of sales, and a decrease in cost of sales from our South Dakota business of $24.9 million, or 20.9%. This decrease occurred primarily as a result of lower commodity prices and reduced retail volumes from warmer

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weather in 2002 than in 2001. Cost of sales in 2001 was $119.1 million, an increase of $47.7 million, or 66.8%, from 2000 results. The increase in cost of sales was a result of the increased market prices for natural gas in 2001 and, to a lesser extent, the slight increase in our volume of sales.

        Gross margin in 2002 was $107.2 million, an increase of $82.0 million, or 326.2%, over the 2001 gross margin of $25.2 million. This increase was nearly all due to the contribution of $81.2 million in gross margin by NorthWestern Energy's Montana operations. In addition, our South Dakota operations experienced a $0.8 million increase in margins due to increased volumes in the non-regulated gas segment. Overall gross margin as a percentage of revenues in 2002 was 44.6%, as compared to 17.4% in 2001, resulting primarily from the higher margin impact from the Montana operations. The higher margins from the Montana operations are principally due to NorthWestern owning the natural gas transmission system in Montana on which we collect tariff revenues and margins, as compared to South Dakota and Nebraska operations where third parties own the transmission systems and NorthWestern pays these costs which are then passed on to ratepayers as a component of the natural gas costs. Gross margin in 2001 was $25.2 million, an increase of $1.8 million, or 7.7%, from 2000 results. However, gross margin as a percentage of revenues decreased to 17.4% in 2001 from 24.7% in 2000. The increase in gross margin in 2001 was due to increased sales volumes and higher market prices for natural gas in 2001. Because the higher market prices for natural gas were passed along to consumers, the increase in gas commodity prices did not affect gross margin, but did have a positive impact on revenues and, therefore, adversely affected the gross margin percentage.

        Operating expenses in 2002 were $73.3 million, an increase of $54.4 million, or 286.8%, over 2001 results. SG&A expenses increased $45.0 million in 2002, primarily due to $42.9 million in additional expenses attributable to NorthWestern Energy's Montana operations, while the South Dakota operations' SG&A expenses increased by $2.1 million. Depreciation expense was $12.6 million in 2002, an increase of $9.3 million over 2001. This increase was also primarily due to the addition of NorthWestern Energy's Montana operations, which increased depreciation by $8.3 million, along with an increase of $1.0 million from our South Dakota operations. Operating expenses in 2001 were $19.0 million, an increase of $1.9 million, or 11.0%, from 2000 results. The increase was due principally to a $1.2 million restructuring charge related to a series of company wide initiatives targeting reductions in annualized selling, general and administrative expenses and small increases in team member benefit costs, customer care costs, and service expenses.

        Operating income in 2002 was $33.9 million, an increase of $27.7 million, or 446.7%, from 2001, primarily due to the addition of NorthWestern Energy's Montana operations, which contributed $30 million in operating income, while operating income from the South Dakota operations declined by $2.3 million. Operating income in 2001 was $6.2 million, or $7.4 million before restructuring charges, compared to operating income in 2000 of $6.3 million. The increase in operating income in 2001 before restructuring charges reflected gross margin increases, but was partially offset by increased operating expenses.

Communications Segment Operations

        Operating revenues at Expanets in 2002 were $710.5 million, a decrease of $321.6 million, or 31.2%, from 2001. The decline in revenue was the result of a downturn in the economy generally and the telecommunications equipment market specifically, a focus on higher margin revenues and continuing problems with Expanets' EXPERT system implementation that have contributed to erosion of Expanets' customer base. Expanets recorded a reduction in revenues of $28.0 million for pending billing adjustments.

        Cost of sales in 2002 was $444.5 million, a decrease of $203.5 million, or 31.4% from 2001. The decrease was primarily due to lower sales volume and a technical assistance call center agreement signed with Avaya in March 2002 which reduced costs by approximately $25.9 million during the year

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ended December 31, 2002. Cost of sales in 2001 was $648.0 million, a decline of $92.5 million, or 12.5%, from 2000 results. The decline in cost of sales was attributable to a shift in sales mix from equipment sales to higher-margin service sales and a decline in sales volumes.

        Gross margin in 2002 was $265.9 million, a decrease of $118.1 million, or 30.7%, from 2001. Gross margin dollars decreased as the result of a decrease in revenue. As a percentage of revenues, gross margin increased slightly to 37.4% of operating revenues as compared to 37.2% in 2001. Gross margin in 2001 was $384.0 million, an increase of $20.5 million, or 5.6%, from 2000 results. As a percentage of revenues, gross margin increased from 32.9% in 2000 to 37.2% in 2001. Gross margin dollars increased, in spite of an overall decline in operating revenues, as the result of increased solutions and services sales. The gross margin percentage improvement was a result of the increased mix of higher margin recurring service revenues as compared to lower margin equipment sales.

        Operating expenses in 2002 were $657.8 million, a decrease of $171.3 million, or 35.2%, from 2001. Selling, general and administrative expenses in 2002 were $314.0 million, a decrease of $123.4 million, or 28.2% from 2001. This decrease was a result of the full year effect of the reduction of approximately 1,300 team member positions in 2001. In addition, current year operating expenses decreased as certain transition service agreements, or TSAs, with Avaya expired or were terminated. Under these TSAs, Avaya provided critical supporting systems such as accounting and information technology until Expanets could complete the necessary infrastructure to provide such services internally. Also contributing to the decrease, Expanets receives payments from Avaya under the terms of a maintenance fee agreement to help Avaya preserve its maintenance customer base for customers of Expanets who have maintenance agreements with Avaya. These amounts reduced operating expenses by $42.8 million in 2002 and $32.0 million in 2001. Included in the amount recognized in 2002 was a true up payment of $2.4 million from Avaya and an additional $10.4 million that had previously been deferred as of December 31, 2001, pending the determination of Avaya's actual experience. In addition, Expanets reduced accrued expenses established as of December 31, 2001 related to vendor settlements, bonus accruals and other items by $11.2 million during 2002. The decrease in selling, general and administrative expenses was partially offset by $37.4 million in bad debt expense and other receivable related charges and $31.2 million of additional expense associated with information technology costs for the operation and repair of the EXPERT system. Depreciation and amortization costs increased approximately $5.9 million in 2002 as the capitalized costs of the EXPERT system were depreciated starting in the first quarter of 2002. Operating expenses in 2001 were $486.5 million, an increase of $98.5 million, or 25.4%, from 2000 results. Selling, general and administrative expenses in 2001 were $437.4 million, an increase of $86.5 million, or 24.6%, from 2000 results. The increase in selling, general and administrative expenses in 2001 was primarily a result of the additional transition and integration and other operating expenses related to the Lucent GEM business acquisition beginning in the second quarter of 2000.

        Operating losses in 2002 were $391.9 million, an increase of $289.3 million from 2001 results, primarily due to a decline in the telecommunications equipment market and the $288.7 million in impairment charges discussed above. Operating losses in 2001 were $102.6 million, a decline of $78.0 million from 2000 results, primarily due to the general downturn in the economy and in the communications market in particular, together with the additional integration/transition and other operating expenses incurred as a result of the GEM acquisition.

HVAC Segment Operations

        Operating revenues in 2002 were $471.8 million, an increase of $48.0 million, or 11.3% from 2001 results. Units acquired in 2002 and 2001 contributed $41.8 million in revenues in 2002. The remaining increase of $6.2 million represents a same unit growth rate of 1.5%. Operating revenues from non-core same units, which are operating locations designated by management of Blue Dot for immediate divestiture or closure due to significant operating issues or continuing deterioration of performance,

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were $74.0 million, a decrease of $12.6 million, or 14.5%, from 2001 results. The decline in revenues from the non-core units are due to soft overall market conditions in addition to individual circumstances which include: increased competition in Dallas; a shift in business focus from commercial to residential in San Antonio; disruption caused by labor issues in Detroit; changes in management at certain locations; and the continual impact of poor integration of businesses in New Jersey. Operating revenues in 2001 were $423.8 million, an increase of $15.0 million, or 3.7%, from 2000 results. Operations from acquisitions completed during 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in the fourth quarter of 2000 contributed approximately $25.0 million in revenues, however, revenues at three previously acquired locations declined $26.4 million during 2001. Internal growth within the remainder of the HVAC business generated the remaining revenue increase.

        Cost of sales in 2002 was $306.7 million, an increase of $38.7 million, or 14.4%, from 2001 results. Units acquired in 2002 and 2001 incurred costs of $28.3 million in 2002. Cost of sales in same units increased $11.3 million or 4.2%. This increase is primarily attributable to increased competition, compounded by soft market conditions. Cost of sales from non-core same units were $47.2 million, a decrease of $8.6 million, or 15.5% from 2001 results. This decrease is generally in line with the decrease in revenues noted from these same operating units. Cost of sales in 2001 was $268.0 million, an increase of $7.0 million, or 2.7%, from 2000 results. The acquisition and operations of locations in 2001 and the inclusion of the operations for the full year in 2001 of the locations acquired in the fourth quarter of 2000 increased costs by approximately $13.7 million. Costs from additional locations were offset, however, by $16.2 million in reduced cost of sales in connection with division closings and restructurings at three non-core locations. The remaining increase in cost of sales was due to internal growth in other locations.

        Gross margin in 2002 was $165.2 million, an increase of $9.3 million, or 6.0%, from 2001 results. Units acquired in 2002 and 2001 contributed $15.6 million to gross margin in 2002. Gross margin in same units decreased $5.2 million or 3.4%. Gross margin from non-core same units were $26.7 million, a decrease of $3.9 million, or 12.8% from 2001 results. Gross margin in 2001 was $155.8 million, an increase of $8.0 million, or 5.4%, from 2000 results. The acquisition and operations of locations in 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in late 2000 contributed approximately $11.3 million to gross margin in 2001, while certain non-core locations lowered gross margin $10.2 million. The remainder of the increase in gross margin in 2001 was due to internal growth in the previously acquired locations.

        Gross margin as a percentage of revenues in 2002 decreased from 36.8% to 35.0%. Units acquired in 2002 and 2001 contributed gross margin as a percentage of revenues of 35.5%, while gross margin as a percentage of revenues from same units decreased from 36.7% to 35.0%, primarily due to general economic conditions, a tougher competitive environment and increased operating costs.

        Operating expenses in 2002 were $476.5 million, an increase of $306.9 million from 2001 results. The primary reason for this increase was goodwill and long-lived asset impairment charges of $301.7 million. These impairment charges were recorded during the fourth quarter of 2002 to write off the carrying value of goodwill, fixed assets and intangible assets based on the fair value of Blue Dot, determined in accordance with SFAS No. 142 and SFAS No. 144, respectively. The charges are composed of $289.6 million for goodwill, $11.4 million for fixed assets and $0.7 million for intangible assets. Selling, general and administrative expenses in 2002 were $166.3 million, an increase of $13.1 million, or 8.6%, from 2001 results. Approximately $13.3 million of the expenses were incurred in connection with acquisitions in 2002 and the inclusion of the operations for the full year in 2002 of the acquisitions made in late 2001. Expenses increased $5.2 million in 2002 related to the sale-leaseback of a significant portion of Blue Dot's vehicle fleet. Expenses also increased $3.5 million in 2002 at the corporate level related to transition costs of relocating the corporate office, outside consulting, and additional costs of adding team members to support field operations and newly acquired locations.

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Depreciation and amortization expenses in 2002 were $8.5 million, a decrease of $7.9 million, due to implementation of SFAS No. 142 related to the non-amortization of goodwill and reduced depreciation expense of $3.8 million related to the sale-leaseback of a significant portion of the company's vehicle fleet, partially offset by continued acquisition activity and capital expenditures. Operating expenses in 2001 were $169.6 million, an increase of $26.3 million, or 18.4%, from 2000 results. Selling, general and administrative expenses in 2001 were $153.2 million, an increase of $23.7 million, or 18.3%, from 2000 results. Approximately $8.2 million of the additional expenses were incurred in connection with acquisitions in 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in late 2000. Expenditures also increased $2.7 million in 2001 at the corporate level for salaries and benefits of additional team members to support field operations. The remaining increase in expenses was attributable to the growth of previously acquired locations. Blue Dot recorded a $7.2 million restructuring charge in 2001, which related primarily to severance and related team member benefits. Depreciation and amortization expenses in 2001 increased 18.9% due to the continued acquisition activity and capital expenditures.

        Operating losses in 2002 were $311.3 million, an increase of $297.5 million from 2001 results primarily due to the impairment charges discussed in the previous paragraph. Prior to giving effect to these impairment charges, acquisitions in 2002 and the inclusion of the operations for the full year in 2002 of the acquisitions made in 2001 increased earnings by approximately $1.8 million. Prior to giving effect to these impairment charges, operating losses in 2002 from same units was $11.9 million, an improvement of $2.3 million or 16.1% from 2001 results. Prior to giving effect to these impairment charges, operating losses from non-core same units were $8.7 million, an improvement of $1.1 million, or 11.3% from 2001 results. The combination of a more competitive climate, increasing operating costs, transition costs related to the relocation of the corporate office resulted in the operating losses in 2002. Operating losses in 2001 were $13.8 million, a decline of $18.4 million from 2000 results. Acquisitions in 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in 2000 increased earnings by approximately $3.1 million, but the restructuring charge of $7.2 million, decline in operating income within three non-core locations, margin shortfalls and an overall increase in operating expenses resulted in the net decline and operating loss in 2001.

All Other Operations

        All Other primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments, and any eliminating amounts. The miscellaneous service activities principally include non-utility businesses engaged in voice and data networks and systems, and a portfolio of services to residential and business customers, including product sales and maintenance contracts in areas such as home monitoring devices and appliances. In addition, the 2002 results include the non-utility operations from the newly acquired Montana business. Those activities include an underground pipe and line locating service as well as a portfolio of other services to residential and business customers.

        Revenues for the segment in 2002 were $33.9 million, an increase of $16.9 million, or 100%, from 2001. The increase was due to $27.9 million from the newly acquired Montana non-utility operations offset by reduced revenues from the South Dakota and Nebraska non-utility voice and data networks business, which was transferred to Expanets mid-year. Revenues in 2001 were $16.9 million, an increase of $1.6 million, or 10.7%, from 2000 results. The growth in 2001 was attributable to a small acquisition closed in December 2000, which was partially offset by business restructurings and reductions within certain other service activities.

        Cost of sales in 2002 was $5.5 million, a decrease of $5.8 million, or 51.2%, from 2001. The decrease was primarily due to the mid-year transfer of the South Dakota and Nebraska non-utility voice and data networks business. Cost of sales in 2001 was $11.2 million, an increase of $0.4 million, or 4.0%, from 2000 results. The increase was a result of the aforementioned acquisition offset by decreased costs from reductions in other service activities.

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        Gross margin in 2002 was $28.4 million, an increase of $22.7 million, or 397.7%, from 2001. The increase was primarily due to the newly acquired Montana non-utility operations offset by transfer of the previously mentioned South Dakota and Nebraska non-utility voice and data networks business to Expanets. Gross margin in 2001 was $5.7 million, an increase of $1.2 million from 2000 results. As a percentage of revenues, gross margin improved from 29.4% in 2000 to 33.7% in 2001 to 83.8% in 2002. The increase in 2002 resulted primarily from the newly acquired underground line locating service business.

        Operating expenses in 2002 were $99.8 million, an increase of $67.7 million, or 210.5%, from 2001. The increase was primarily due to $35.7 million asset impairment charges with respect to the investment in the Montana First Megawatts project and operating expenses from the newly acquired underground line locating service business and to the recognition of expenses of approximately $5.9 million related to the anticipated termination of NorthWestern's Stock Ownership Plan. Operating expenses in 2001 were $32.1 million, an increase of $13.9 million, or 76.4%, from 2000 results. The increase was due principally to $7.3 million of restructuring charges related to a series of company wide initiatives targeting reductions in annualized selling, general and administrative expenses, increased salaries, benefits and relocation expenses related to additional personnel in the corporate offices, additional costs from the acquisition, increased professional services expenses, and an increase in certain other benefit plan expenses.

        Operating losses in 2002 were $71.4 million, an increase of $45.0 million, or 170.1%, from 2001. The increase was primarily due to the previously mentioned asset impairment charges. Losses in 2001 were $26.4 million, compared to losses of $13.7 million in 2000. The $12.7 million increase in operating losses in 2001 was attributable to the restructuring charges together with growth in corporate operating expenses, which were partially offset by an increase in gross margin.

LIQUIDITY AND CAPITAL RESOURCES

        The success of our turnaround plan is dependent upon reducing our debt. Absent the receipt of significant proceeds from the sale of non-core assets, the raising of additional capital or a restructuring of our debt, we will not have the ability to materially reduce our debt or meet our significant maturing debt obligations beginning in 2005, and our ability to fund our operations and service our substantial indebtedness will be adversely affected.

        As of December 31, 2002, cash and cash equivalents were $45.6 million, compared to $34.8 million at December 31, 2001. On April 7, 2003, cash and cash equivalents were approximately $95 million. The increase in cash is principally the result of the net proceeds received from the closing of our new senior secured term loan net of other debt principal payments and working capital needs. Our principal sources of liquidity for the year ended December 31, 2002 were cash from operations and cash provided by financing activities, including the sale of new debt and equity securities and borrowings under our former senior credit facility.

        We realized net positive cash inflows from operations of $34.0 million in 2002, $83.2 million in 2001, and $34.7 million in 2000. Net cash provided by operating activities in 2002 was composed of a net loss of $863.9 million adjusted for non-cash items of $952.5 million, net cash provided by changes in operating assets and liabilities of $5.7 million and cash used for changes in net assets of discontinued operations of $60.2 million. The increase in cash flows in 2002 was due in part to a $42.0 million decrease in accounts receivable and a $35.8 million decrease in other current assets, offset primarily by a $50.7 million decrease in accounts payable and an $80.6 million decrease in cash due to changes in regulatory assets and liabilities. The increase in cash flows in 2001 was due in part to a $63.5 million increase in accrued expenses, a $51.0 million increase in accounts payable, a $32.3 million decrease in net assets of discontinued operations and a $6.4 million decrease in accounts receivables which were partially offset by a $19.0 million increase in other current assets and a $16.0 million increase in inventories. In 2002, we used our cash from operations and $631.0 million in cash provided from

58

financing activities, to fund $654.3 million in investment activities, including our acquisitions and capital expenditures. In 2001, we used our cash from operations, together with $8.6 million in existing cash and cash equivalents and $91.3 million in cash provided from financing activities, to fund $183.1 million in investment activities, including our acquisitions and capital expenditures. In 2000, we used a portion of our cash from operations, together with $150 million in cash provided from financing activities, to fund $163.9 million in investment activities, including our acquisitions and capital expenditures.

        Cash flows used in investing activities in 2002 were $654.3 million, an increase of $471.2 million from 2001. The increase was primarily due to the acquisition of our Montana utility operations. Cash flows used in investing activities of $183.1 million in 2001 increased $19.2 million over 2000 investing activities. The increase was principally a result of increased growth of property, plant and equipment capital expenditures. Cash flows provided by financing activities in 2002 were $631.0 million, an increase of $539.7 million from 2001. The increase was primarily due to the issuance of $738.1 million in senior notes and other long-term debt, $123 million in net line of credit borrowings, $117.8 million in net proceeds from the issuance of preferred securities of subsidiary trusts and $81 million in net proceeds from the issuance of our capital stock, offset primarily by repayment of $313.5 million in long-term debt. Cash flows provided by financing activities of $91.3 million in 2001 declined $58.7 million compared to $150 million of financing cash inflows in 2000. The decrease is attributable to a decline in net debt issuances and repayments and an increase in cash used to repurchase subsidiary minority interests, offset by proceeds from common stock issuances in 2001.

        During 2001 and 2002, we raised cash proceeds from the following offerings of our securities and new debt facilities.

•

We completed a 3.68 million share common stock offering, including an overallotment option, in October 2001. The offering raised $74.9 million of net proceeds, after expenses and commissions. Approximately $35.0 million of these net proceeds were contributed to Blue Dot for the redemption of certain preferred stock and common stock held by former owners of these businesses pursuant to existing agreements and the remainder was used for general corporate purposes, including reducing short term debt and amounts drawn under our old credit facility.

•

On December 21, 2001, NorthWestern Capital Financing II sold 4.0 million shares of its 8¹/4% trust preferred securities and on January 15, 2002, sold an additional 270,000 shares of its 8¹/4% trust preferred securities pursuant to an overallotment option. We received approximately $102.9 million in net proceeds from the offering, which we used for general corporate purposes and to repay a portion of the amounts outstanding under our old credit facility. The 8¹/4% trust preferred securities will be redeemed either at maturity on December 15, 2031, or upon early redemption.

•

On January 31, 2002, NorthWestern Capital Financing III sold 4.0 million shares of its 8.10% trust preferred securities, and on February 5, 2002, sold an additional 440,000 shares of its 8.10% trust preferred securities pursuant to an overallotment option. We received approximately $107.4 million in net proceeds from the offering, which we used for general corporate purposes and to repay a portion of the amounts outstanding under our old credit facility. The 8.10% trust preferred securities will be redeemed either at maturity on January 15, 2032, or upon early redemption.

•

On February 15, 2002, in connection with our recently completed acquisition of The Montana Power Company's energy distribution and transmission business, we assumed $511.1 million of debt and preferred stock net of cash received from The Montana Power Company and we entered into a $720 million term loan and drew down a $19.0 million swing line commitment under our $280 million revolving credit facility to fund our acquisition costs and repay borrowings of $132.0 million outstanding under our existing recourse bank credit facility. The $511.1 million of assumed debt and preferred stock includes various series of mortgage bonds,

59

pollution control bonds and notes that bear interest rates between 5.90% and 8.95%. These include both secured and unsecured obligations with maturities that range from 2003 to 2026.

•

On March 13, 2002, we issued $250 million of our 7⁷/8% senior notes due March 15, 2007, and $470 million of our 8³/4% senior notes due March 15, 2012, which resulted in net proceeds to us of $713.9 million. We applied these net proceeds together with available cash to fully repay and terminate the $720 million term loan portion of our credit facility. On March 28, 2002, we entered into two fair value hedge agreements, each of $125.0 million, to effectively swap the fixed interest rate on our $250 million five-year senior notes to floating interest rates at the three month London Interbank Offered Rate plus spreads of 2.32% and 2.52%, effective as of April 3, 2002. These fair value hedge agreements were settled on September 17, 2002 resulting in $17.0 million of proceeds and an unrecognized gain to us. The unrecognized gain is recorded in Other Non-Current Liabilities and will be recognized as a reduction of interest expense over the remaining life of the notes. On the nine remaining coupon payments on the five-year notes, the amortization of the gain equates to a $1.9 million interest savings per coupon payment, effectively lowering the annual interest rate on the five-year notes to 6.3%.

•

On October 8, 2002, we completed a 10 million share common stock offering. The offering raised $81.0 million of net proceeds, after expenses and commissions. The net proceeds were used for general corporate purposes, including reducing amounts drawn under our credit facility.

        Capital expenditures for property, plant and equipment for the years ended December 31, 2002, 2001 and 2000, were $115.9 million, $163.9 million, and $61.4 million, respectively. We estimate that our capital expenditures for 2003 will be approximately $60 million for our regulated business and $23 million for our unregulated businesses. Our capital expenditures are continually examined and evaluated and may be revised in light of changing business operating conditions, variation in sales and other business factors. Our future investment in any non-utility entity, including Blue Dot, CornerStone or Expanets, is limited to $10 million without the approval of the MPSC, pursuant to an order issued in connection with approval of our senior secured term loan. With the approval of the MPSC, we may make secured loans of up to $30 million for Expanets and $20 million for Blue Dot under the order, but we do not intend to do so. We expect our capital expenditures for our regulated business to approximate $60 million in each of years 2004 through 2007.

        As of December 31, 2002, NorthWestern had long-term borrowings of approximately $2.1 billion. Through March 31, 2003, we have:

•

Repaid $15.0 million aggregate principal amount of maturing Montana Secured Medium Term Notes.

•

Repaid approximately $11.2 million on Expanets' credit facility with Avaya. The remaining outstanding balance on this facility of approximately $27.1 million was formally extended by Avaya and is due in three equal installments of approximately $9.0 million on each of January 1, April 1 and July 1, 2004.

•

Agreed with Avaya to cancel the Expanets subordinated note in the face amount of $35.0 million due 2005 that was issued as partial consideration in the GEM acquisition. The subordinated note was non-interest bearing and had a carrying value of approximately $27.0 million as of December 31, 2002.

•

Repaid and terminated our $280 million credit facility, of which the outstanding balance at December 31, 2002 was approximately $255.0 million and which was fully drawn, including back-up letters of credit, on the date of repayment, with net proceeds received on a $390 million secured term loan closed during February 2003.

After such repayments, as of March 31, 2003, we now have approximately $2.2 billion in long-term borrowings, with maturities during the balance of 2003 of approximately $9.0 million, which excludes $16 million related to the Blue Dot credit facility, currently in default, which is non-recourse to us. In 2004, we have approximately $42.3 million in maturities, including approximately $27.1 million under Expanets' credit agreement with Avaya, for which we have an obligation to purchase inventory and receivables in an amount equal to the outstanding balance in the event of a default by Expanets.

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        The following table shows our contractual cash obligations and commercial commitments as of December 31, 2002:

(1)

In addition, as of December 31, 2002, NorthWestern had letters of credit totaling $20.4 million outstanding under its $280 million revolving credit facility. This facility was terminated and repaid in full on February 10, 2003. This facility was repaid with a portion of the proceeds from our new $390 million senior secured term loan, which we drew down on February 10, 2003 and which matures on December 1, 2006. We have adjusted the maturity schedule of the amounts outstanding under our $280 million revolving credit facility at December 1, 2002 to match the maturity schedule under our new $390 million senior secured term loan. The entire outstanding balance under the senior secured term loan matures on December 31, 2006, expected to be approximately $378 million, net of scheduled amortization. We have also included the interest payments on our senior secured term loan in the interest payments reflected in this table.

(2)

These Montana Secured Medium Term Notes matured and were repaid in their entirety on January 27 and 28, 2003.

(3)

This facility had an outstanding balance of $27.1 million as of March 31, 2003. Amounts repaid under this facility may not be reborrowed. If Expanets defaults under this facility, we may be obligated to purchase inventory and accounts from Avaya in an amount equal to the outstanding balance of the facility.

(Footnotes continued on the next page.)

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(Footnotes continued from the preceding page.)

(4)

Subsequent to December 31, 2002, we reached an agreement with Avaya to settle certain claims and to restructure the terms of Avaya's investments in Expanets' equity and debt securities. In connection with such agreement, Expanets paid down the balance of its credit facility to approximately $27.1 million, which was deferred until 2004 and will be repaid in equal payments on January 1, 2004, April 1, 2004 and July 1, 2004. Further, Expanets' non-interest bearing note in the face amount of $35.0 million which was carried on Expanets' books at a value of approximately $27.0 million at December 31, 2002 and is included in Other debt, various, was forgiven by Avaya. See Item 1. "Business—Communications, Network Services and Data Solutions Business—Expanets—Operating Developments" for further details of this agreement.

(5)

The capital lease obligations are principally used to finance equipment purchases. These leases have various implicit interest rates, which range from 2.0% to 16.1%. NorthWestern has a financial commitment related to certain vehicles under operating leases by Expanets and Blue Dot, in the event of default and subsequent failure to cure such default. At December 31, 2002 the amount of this financial commitment is approximately $24.7 million.

(6)

As discussed in "Utility Regulation—Electric Operations—Montana", with the acquisition of our Montana operations we assumed a liability for expenses associated with certain Qualifying Facilities Contracts, or QFs. The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our gross contractual obligation related to the QFs is approximately $1.9 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.5 billion. We have established a liability as of the date of the acquisition of $134.3 million, which represents the net present value, utilizing a discount rate of 8.75%, of the difference between our obligations under the QFs and the related amount recoverable in rates. The obligation and payments reflected on this schedule represent the amortization of this liability.

(7)

As discussed in "Electric Operations—Electric Supply" and "Natural Gas Operations—Natural Gas Supply", we have entered into various power purchase commitments, largely purchased power, coal and natural gas supply, electric generation construction and natural gas transportation contracts. These commitments range from one to thirty years.

        Each of the debt agreements, mandatorily redeemable preferred securities of subsidiary trust and capital and operating leases described in the above-referenced table, as well as other contractual obligations including the Blue Dot exchange agreements and the obligations under the Defined Benefit Pension and Postretirement Benefit Plan are described under the caption "Description of Indebtedness and Other Contractual Obligations."

        For our utility only operations, which excludes Blue Dot, Expanets, and all other unregulated entities, and absent proceeds from the sale of non-core assets, we estimate the following for the years 2003 and 2004 ($ are approximate and in millions):

(1)

The 2003 amount includes a net decrease in working capital of approximately $45 million and interest payments of approximately $140 million. The 2004 amount includes a net decrease in working capital of approximately $15 million and interest payments of approximately $140 million.

(2)

These amounts are comprised of capital expenditures.

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(3)

The 2003 amount represents the net total of our currently anticipated financing activities for 2003 and is comprised of the following:

We have the right to defer payment of our trust preferred dividend payments for up to 20 consecutive quarters. The 2004 amount includes trust preferred dividend payments of approximately $30 million, and other debt payments of approximately $9 million.

        Based on our current plans and business conditions, we expect that our available cash, cash equivalents and investments, together with amounts generated from operations, will be sufficient to meet our cash requirements for at least the next twelve months. However, due to a decrease in cash and cash equivalents during 2004, we believe that we may need additional funding sources or proceeds from the sale of non-core assets, by the end of 2004 or early in 2005. Commencing in 2005, we face substantial debt reduction payments. Absent the receipt of significant proceeds from the sale of non-core assets, the raising of additional capital or a restructuring of our debt, we will not have the ability to reduce our debt or meet our maturing debt obligations. Even if we are successful in selling some or all of our non-core assets, we will have to restructure our debt or seek new capital.

        The principal elements of our turnaround plan will be to focus on our core electric and natural gas utility businesses and to commit to reduce our debt. In that regard,

•

We do not intend to make any additional significant investments in, or commitments to, Expanets and Blue Dot while we examine strategic alternatives for these businesses, including the sale or disposition of each of these businesses or their assets;



•

We are seeking to enforce a contract for the sale of our Colstrip Transmission line, and we propose to sell certain of our non-core assets, including our Montana First Megawatts project;



•

We intend to review all corporate overhead and significantly reduce expenditures; and



•

We have departed from our historical practice of paying dividends on our common stock.

Description of Indebtedness and Other Contractual Obligations

        Senior Notes.    The Senior Notes are two series of unsecured notes that we issued in 2002 in connection with our acquisition of NorthWestern Energy LLC. These senior notes mature in 2007 and 2012.

        Senior Unsecured Debt.    The Senior Unsecured Debt is a general obligation that matures in 2028. We issued this debt in November 1998, and the proceeds were used to repay short-term indebtedness and for general corporate purposes.

        Senior Secured Term Loan.    In February 2003, we closed and received funds from a $390 million senior secured term loan, which is secured by $280 million of First Mortgage Bonds secured by substantially all of our Montana utility assets and $110 million of First Mortgage Bonds secured by substantially all of our South Dakota and Nebraska utility assets. The net proceeds from this facility were used to repay $260 million outstanding plus approximately $20 million in letters of credit and terminate our prior working capital facility, which had a $280 million revolving line of credit, and provided ongoing liquidity to the Company. Our prior credit facility, which bore interest at a variable

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rate tied to the London Interbank Offered Rate plus a spread of 1.5% based on our credit ratings and accrued interest at 2.88% per annum as of December 31, 2002, was repaid and terminated on February 10, 2003.

        Our new senior secured term loan bears interest at a variable rate tied to the Eurodollar rate, with a floor of 3.0%, plus a spread of 5.75% or at the prime rate, with a floor at 4.00%, plus a spread of 4.75%. Our new senior secured term loan expires on December 1, 2006, although we must make quarterly amortization payments equal to $975,000 commencing on March 31, 2003. The credit agreement with respect to our senior secured term loan contains a number of representations and warranties and imposes a number of restrictive covenants that, among other things, limit our ability to incur indebtedness and make guarantees, create liens, make capital expenditures, pay dividends and make investments in other entities.

        In addition, we are required to maintain certain financial ratios for NorthWestern and its subsidiaries, excluding Blue Dot, Expanets and CornerStone (the "Borrower"), including:

•

net worth, as defined, on the last day of each fiscal quarter of at least $616.0 million plus 50% of cumulative net income (but not losses) from each quarter commencing with the quarter ending March 31, 2003 ($785.1 million at December 31, 2002);



•

a funded debt to total capital ratio, as defined, on the last day of each fiscal quarter of no greater than 72.5% (69.1% at December 31, 2002);



•

a ratio of utility business earnings before interest, taxes, depreciation and amortization, or EBITDA(1), to consolidated recourse interest expense (which excludes non-cash interest expense) for the prior four fiscal quarters of at least 1.40 to 1.00 (2.25 at December 31, 2002);