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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