UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

ý		ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003
OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission File Number: 0-692

NORTHWESTERN CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		46-0172280
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

125 S. Dakota Avenue, Sioux Falls, South Dakota		57104
(Address of principal executive offices)		(Zip Code)

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

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

(Title of each class)

(Name of each exchange on which registered)

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

Common Stock, $1.75 par value, and related Common Stock Purchase Rights

Preferred Stock, Par Value $100

Company Obligated Mandatorily Redeemable Security of Trust Holding Solely Parent Debentures, $25.00 liquidation

(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 30, 2003, the aggregate market value of the voting common stock held by nonaffiliates of the registrant was $75,360,190, computed using the last sales price of $2.00 per share of the registrant’s common stock on June 30, 2003, the last business day of the registrant’s most recently completed second fiscal quarter, as reported by the New York Stock Exchange.

As of March 12, 2004, 37,680,095 shares of the registrant’s common stock, par value $1.75 per share, were outstanding.

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

Documents Incorporated by Reference

None

INDEX

Part I.		Page
Item 1.	Business	5
Item 2.	Properties	21
Item 3.	Legal Proceedings	21
Item 4.	Submission of Matters to a Vote of Security Holders	24
Part II.		25
Item 5.	Market for Registrant’s Common Equity and Related Shareholder Matters	25
Item 6.	Selected Financial Data	27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	48
Item 9A.	Controls and Procedures	48
Part III.		50
Item 10.	Directors and Executive Officers of the Registrant	50
Item 11.	Executive Compensation	52
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	59
Item 13.	Certain Relationships and Related Transactions	60
Item 14.	Principal Accountants Fees and Services	60
Part IV.		61
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	61
Signatures		72
Index to Financial Statements		F-1

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Annual Report on Form 10-K regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference herein relating to management’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. On September 14, 2003, NorthWestern Corporation filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Our subsidiaries, including Netexit, Inc. (f/k/a Expanets Inc.) and Blue Dot Services, Inc., (Blue Dot) are not party to the Chapter 11 case.

Words or phrases such as “anticipates,” “may,” “will,” “should,” “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 projections will be achieved. Factors that may cause such differences include but are not limited to:

(i) our common stock will be cancelled and our trust preferred securities will likely be restructured in a manner that will eliminate or very substantially reduce any remaining value. We have previously stated that the planned sale of noncore assets is not expected to change our view that our common stock has no value. Accordingly, we urge that appropriate caution be exercised with respect to existing and future investments in any of our liabilities and/or securities;

(ii) our ability to successfully develop, prosecute, confirm and consummate a plan of reorganization, emerge from bankruptcy as a going concern and avoid liquidation under the U.S. Bankruptcy Code;

(iii) risks associated with third parties seeking and obtaining Bankruptcy Court approval for the appointment of a Chapter 11 trustee or to convert the case to a Chapter 7 proceeding;

(iv) our ability to operate pursuant to the terms of our $85 million debtor-in-possession financing facility arranged by us with Bank One, N.A. (the DIP Facility) and other financing and contractual arrangements;

(v) our ability to obtain Bankruptcy Court approval with respect to material motions in the Chapter 11 proceeding from time to time;

(vi) our ability to obtain the support of the official committee of unsecured creditors and other stakeholders of the company for a plan of reorganization, which may be difficult in light of our likely inability to preserve any material value in our common equity and our trust preferred securities, or satisfy a material amount of our current unsecured debt, in a plan of reorganization;

(vii) our ability to offset the negative effects that the filing for reorganization under Chapter 11 has had, or may have, on our business, management and employees including constraints placed on available capital;

(viii) our ability to obtain and maintain normal terms with vendors and service providers;

(ix) our ability to maintain contracts, including leases, that are critical to our operations;

(x) the potential adverse impact of the Chapter 11 case on our liquidity or results of operations;

(xi) our ability to develop a long-term strategy and our ability to fund and execute our business plan;

(xii) our ability to avoid or mitigate material uninsured monetary judgments, or other adverse judgments, against us in (1) the shareholder class action lawsuit relating to the disposition of the generating and energy-related assets by The Montana Power Company, excluding our acquisition of the electric and natural gas transmission and distribution business formerly held by The Montana Power Company, together with ERISA litigation regarding The Montana Power Company ESOP and 401(k) plan and (2) existing shareholder and derivative litigation or any additional litigation and regulatory action, including the initiation by the Securities and Exchange Commission (SEC) of a formal investigation, in connection with the restatement of our 2002 quarterly financial statements, any of which could have a material adverse affect on our liquidity, results of operations and financial condition;

General Factors

(xiii) our ability to fully address and correct weaknesses in our internal controls and to thereafter maintain an effective internal controls structure;

(xiv) our ability to attract, motivate and/or retain key employees;

(xv) potential additional adverse federal, state, or local legislation or regulation or adverse determinations by regulators, including the final order of the Montana Public Service Commission (MPSC) disallowing the recovery of $6.2 million of natural gas costs we incurred during the past tracker year, and an interim order fixing the recovery price during the next tracker year, which has had and could continue to have a material adverse affect on our liquidity, results of operations and financial condition;

(xvi) unscheduled generation outages, maintenance or repairs which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs;

(xvii) unanticipated changes in commodity prices or in fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, in combination with reduced availability of trade credit, may reduce revenues or may increase operating costs, each of which would adversely affect our liquidity;

(xviii) increases in interest rates will increase our cost of borrowing;

(xix) adverse changes in general economic and competitive conditions in our service territories; and

(xx) certain other business uncertainties related to the occurrence of natural disasters, war, hostilities and the threat of terrorist actions.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is a part of the disclosure included in Item 7 of this Report 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, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of inaccurate assumptions or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Annual Report on Form 10-K, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of a forward-looking statement in this Annual Report on Form 10-K or other public communications that we might make as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

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

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.

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 608,000 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. In February 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. 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. The former NorthWestern Energy, LLC has been renamed “Clark Fork and Blackfoot, LLC.” Our utility operations are regulated primarily by the Montana Public Service Commission, or MPSC, the Nebraska Public Service Commission, or NPSC, the South Dakota Public Utilities Commission or SDPUC, and the Federal Energy Regulatory Commission, or FERC.

On September 14, 2003 (the “Petition Date”), we filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court) under case number 03-12872 (CGC). Pursuant to Chapter 11, we retain control of our assets and are authorized to operate our business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Included in the consolidated financial statements are subsidiaries that are not party to the Chapter 11 case and are not debtors. See additional discussion related to our bankruptcy filing under Item 7, Management’s Discussion and Analysis.

We operate our business in three reporting segments:

• electric utility operations;

• natural gas utility operations;

• all other, which 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.

For additional information related to our industry segments, see Note 24 of “Notes to Consolidated Financial Statements,” included in Item 8 herein.

We also have made significant investments in three nonenergy businesses, which have adversely impacted our overall results of operations, financial condition and liquidity. We have divested of substantially all of the assets of, or our interest in, these businesses:

• Expanets, a provider of networked communications and data services and solutions to medium sized businesses;

• Blue Dot, a provider of air conditioning, heating, plumbing and related services; and

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

We were incorporated in Delaware in November 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 documents with, or otherwise furnish them to, the SEC. Our internet Website and those of our subsidiaries and the information contained therein or connected thereto are not intended to be incorporated into this Annual Report on Form 10-K and should not be considered a part of this Annual Report on Form 10-K.

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 covers approximately 107,600 square miles, representing approximately 73% of Montana’s land area, as of December 31, 2003, and includes approximately 786,000 people according to the 2000 census. We also transmit electricity for nonregulated entities owning generation facilities, other utilities and power marketers in Montana. In 2003, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 28%, 36%, 12%, and 24% of our Montana electric 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, 2003, 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 nonaffiliated 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 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, 2003, we delivered electricity to approximately 305,000 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, 2003. Our Montana electric distribution system consisted of approximately 19,700 miles of overhead and underground distribution lines and approximately 334 transmission and distribution substations as of December 31, 2003.

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. 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 more than 57,600 customers in 108 communities in South Dakota as of December 31, 2003. In 2003, by category, residential commercial and industrial, wholesale, and other sales accounted for approximately 38%, 50%, 9% and 3% of our South Dakota 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, 2003. We have interconnection 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 interconnection and pooling arrangements enable us to arrange purchases or sales of substantial quantities of electric power and energy with other pool members and to participate in the 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. The SDPUC, pursuant to the South Dakota Public Utilities Act, assigned the South Dakota service territory to us effective March 1976. Pursuant to that law, we have the exclusive right 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 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, the total control area peak demand was approximately 1,442 megawatts, the average daily load was approximately 972 megawatts, and more than 8,355,978 megawatt hours were supplied to choice and default supply customers during the year ended December 31, 2003. In our South Dakota service territory, peak demand was approximately 272 megawatts, the average daily load was approximately 136 megawatts, and more than 1,192,772 megawatt hours were supplied during the year ended December 31, 2003.

Electricity Supply

Montana

Pursuant to Montana Law, we are obligated to provide default supply electric service to those customers not allowed to choose their electricity supplier. In this role, we purchase substantially all of the capacity and 5.9 million megawatt hours of energy requirements for the default supply from third parties. We have power-purchase agreements with PPL Montana for 300 megawatts of firm base-load and 150 megawatts of unit-contingent on peak energy. We also purchase power from 13 “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 winter peak capacity. We have secured additional contracts from Thompson River Co-gen, LLC for up to 14 megawatts of base-load coal/waste-coal supply and Tiber Montana for 5 megawatts of seasonal base-load hydro supply. NorthWestern has recently submitted an Electric Default Supply Resource Procurement Plan, which fully details the resource requirements, analysis and proposed resources to meet the default supply load requirements. The resources include gas-fired generation from Basin Creek Power Services, LLC of 50 megawatts, 130 megawatts with Montana First Megawatts, our affiliate, and approximately 140 megawatts from two wind projects. In addition, we have entered into short-term fixed price energy purchases to fulfill the default obligation and provide rate stability. These contracted and proposed projects are sufficient to meet the default supply load requirements through June 30, 2007, with minimal price volatility. For more information about our obligations as a result of deregulation in Montana during the statutory transition period, see “Utility Regulation—Montana.”

The MPSC approved base-load supply, along with open market purchases is being recovered through a monthly electricity cost tracking process pursuant to which rates are based on estimated electricity loads and electricity costs for the upcoming tracking period and are reviewed and adjusted by the MPSC for any differences in the previous tracking year’s estimates to actual information. This process is similar in many respects to the cost recovery process that has been utilized in Montana, South Dakota and other states for natural gas purchases for residential and commercial customers. The MPSC reviews our ongoing responsibility to prudently administer our 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 12 to

15 months following the recommencement of construction activities. We estimate total construction, development and related costs will be approximately $180 million inclusive of our existing investment. As part of our restructuring, we are attempting to sell this project. In an effort to facilitate the timely sale of the Montana First Megawatts project, we filed the power sales agreement with the Federal Energy Regulatory Commission (FERC) on August 18, 2003, requesting that the FERC accept for filing the cost-based power sales agreement between Montana Megawatts I, LLC and its affiliate, NorthWestern Energy. A late motion to intervene and protest was filed by the MPSC and The Montana Consumer Counsel, or MCC. On October 17, 2003, the FERC issued an order conditionally accepting the power sales agreement, subject to suspension for a designated period, to permit resolution of certain concerns voiced by the MPSC and MCC in their filing. We are currently working with the MPSC, MCC, FERC staff and the FERC-appointed settlement judge to resolve the documented MPSC and MCC concerns in a timely manner. We have written our investment in this project down to an estimated salvage value of $30 million. 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. To the extent a dispatchable resource component is included in the planned default supply procurement plan and the Montana First Megawatts project is never completed, we will likely fill the portion of the supply portfolio through a formal Request For Proposal (RFP) process.

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. Due to our financial condition, our affiliate was unable to secure a source of power to cover its contractual obligation subsequent to June 30, 2003. Based on the uncertainty of supply, as of July 1, 2003, the two customers elected to secure their power supply needs from the Montana default supply. Shortly thereafter, the customers notified our affiliate that they would seek damages to compensate them for their increased power supply costs. Our affiliate reached a settlement with its two customers on October 27, 2003, and subsequently paid $1.5 million in full settlement of its remaining contractual obligations.

We lease a 30% share of Colstrip Unit 4, a 750 megawatt gross-capacity coal-fired power plant located in southeastern Montana through our unregulated Colstrip Unit 4 Lease Management Division. 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 and Marketing and to Puget Sound Energy under agreements expiring December 20, 2010. On January 23, 2004, we entered into Amendment #2 to the Duke Energy Power Purchase Agreement, which modified the economic terms of the power sales arrangement to our benefit. This amendment was approved by the Bankruptcy Court on February 23, 2004.

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 proportionate share of the electricity generated in our jointly owned plants and are responsible for a proportionate share of the operating expenses, based upon our ownership interest. Most of the power allocated to us from these facilities is distributed to our South Dakota customers, although in 2003, approximately 19% of the power was sold in the wholesale market. Our facilities had a total net summer peaking capacity in 2003 of approximately 312 megawatts.

Name and Location of Plant	Fuel Source	Our Ownership Interest		Our Share of 2003 Peak Summer Demonstrated Capacity	% of Total 2003 Peak Summer Demonstrated Capacity

Big Stone Generating Station, located near Big Stone City in northeastern South Dakota	Sub-bituminous coal	23.4	%	106.58 megawatts	34.2	%
Coyote I Electric Generating Plant, located near Beulah, North Dakota	Lignite coal	10	%	42.70 megawatts	13.7	%
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa	Sub-bituminous coal	8.7	%	55.90 megawatts	17.9	%
Miscellaneous combustion turbine units and small diesel units (used only during peak periods)	Combination of fuel oil and natural gas	100	%	106.65 megawatts	34.2	%

Total Capacity				311.83 megawatts	100	%

We have entered into an agreement 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 Midcontinent Area Power Pool members are subject to the jurisdiction of the FERC.

The 2003 peak demand in our South Dakota service areas was approximately 272 megawatts, and the average daily load in South Dakota during 2003 was approximately 136 megawatts. The 2003 Midcontinent Area Power Pool accredited capacity including the required 15% reserve margins was approximately 293 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 base-load 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, 2003. Our natural gas and fuel oil peaking units provided the balance of generating capacity. We have no interests in nuclear generating plants. The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. There remains upward pressure on coal prices, which may result in modest increases in costs to our customers due to fuel adjustments in our rates. The average cost by type of fuel burned is shown below for the periods indicated:

	Cost per Million BTU for the Year Ended December 31,						Percent of 2003 Megawatt Hours Generated
Fuel Type	2003		2002		2001		Percent of 2003 Megawatt Hours Generated

Sub-bituminous-Big Stone	$	1.34	$	1.24	$	1.07	54.40	%
Lignite-Coyote*	.79		.66		.75		18.23
Sub-bituminous-Neal	.77		.80		.71		27.22
Natural Gas	6.68		6.68		4.26		0.075
Oil	2.04		2.04		5.16		0.075

* Includes pollution control reagent.

During the year ended December 31, 2003, the average delivered cost per ton of fuel for our base-load plants was $25.77 at Big Stone, $14.76 at Coyote and $13.22 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.

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.

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 2003, approximately 3.0% 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 2003, our costs for services under this contract totaled approximately $3.62 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 245,000 commercial and residential customers in Montana, South Dakota and Nebraska as of December 31, 2003. 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 distribute natural gas to nearly 163,000 customers located in 109 Montana communities as of December 31, 2003. 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 four 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 provide service to approximately 28,000 customers as of December 31, 2003. Our natural gas distribution system consists of approximately 3,500 miles of underground distribution pipelines as of December 31, 2003.

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, 2003. NorthWestern Energy’s Montana peak capacity was approximately 300 million cubic feet per day during the year ended December 31, 2003. Our Montana natural gas transmission system consisted of more than 2,000 miles of pipeline, which vary in diameter from two inches to 20 inches, and served more than 130 city gate stations as of December 31, 2003. NorthWestern Energy has connections in Montana with five major, nonaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, Encana and Havre Pipeline. Seven compressor sites provide more than 42,000 horsepower, capable of moving approximately 300 million cubic feet per day during the year ended December 31, 2003. 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 185 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 71 million cubic feet of remaining reserves as of December 31, 2003.

South Dakota and Nebraska

We provide natural gas to approximately 82,000 customers in 59 South Dakota communities and four Nebraska communities as of December 31, 2003. 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 five years, five 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. Included in the five franchises mentioned above is the City of Kearney, Nebraska. Our franchise with Kearney was scheduled to expire in the fall of 2003 but was extended, and we are negotiating a new franchise with the City. We have approximately 2,100 miles of distribution gas mains in South Dakota and Nebraska as of December 31, 2003. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska, and in South Dakota provide natural gas sales to a number of large volume customers delivered through the distribution system of an unaffiliated natural gas utility company.

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 under cost-based rates to customers in our Montana service territories that have not chosen other suppliers.

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 service territory based on MMBTU sold. In South Dakota, we also transport natural gas for two gas-marketing firms currently serving 160 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 6.7 million MMBTU of third-party transportation volume on our South Dakota distribution system and approximately 0.93 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 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), 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, 2003, were approximately 21.3 million MMBTU. We have contracted with more than 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, 2003, were approximately 5.4 million MMBTU. We have contracted with Tenaska Marketing Ventures, Inc. in South Dakota to manage transportation, storage and procurement of supply in order to minimize cost and price volatility to our customers.

Our Nebraska natural gas supply requirements for the year ended December 31, 2003, were approximately 5.7 million MMBTU. Our Nebraska natural gas supply, storage and pipeline requirements are fulfilled primarily through a third-party contract with ONEOK Energy Marketing and Trading, LP

To supplement firm gas supplies in South Dakota and Nebraska, we also contract for firm natural gas storage services to meet the heating season and peak day requirements of our natural gas customers. We also maintain and operate two propane-air gas peaking units with a peak daily capacity of approximately 6,400 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, 2003, we had 1,269 employees in our energy division, NorthWestern Energy. Of these, our Montana operations had 960 employees in its electric and gas utilities business, 374 of whom were covered by collective bargaining agreements involving six unions. In addition, our South Dakota and Nebraska operations had 309 employees in its electric gas and utilities business, 179 of whom were covered by the System Council U-26 of the IBEW.

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, the transmission of electric energy in interstate commerce and the setting of wholesale electric rates. As such, we are required to submit annual filings of certain financial information on the FERC Form No. 1 Annual Report of Major Electric Utilities, Licensees and Others. In addition, on December 23, 2003, FERC issued Order 2001-E, requiring quarterly filings of certain financial information on the FERC Form No. 3-Q, Quarterly Financial Report of Electric Companies, Licensees, and Natural Gas Company’s, effective beginning with the first quarter 2004 filing.

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, then we would execute a transmission operating agreement with RTO West prior to startup of the RTO West operation. 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 we do not anticipate any material change in the size or timing of the transmission-related revenue stream as a result of participation in RTO West. At this time, it is uncertain when or if RTO West will begin operations.

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.

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. In April 2003, FERC issued a white paper related to the SMD NOPR, which paper reflected some of the comments made to FERC in the NOPR process. This paper proposed certain changes, but did not materially alter the proposed rules. 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.

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. We do know that the SMD NOPR was very unpopular across substantial portions of the country, in particular in the Pacific Northwest where we operate. In the energy bill anticipated to be considered by Congress, there is language prohibiting FERC from finalizing the SMD rules before the end of 2006. We cannot predict with certainty the impact the future SMD-related proceedings will have on the Company’s earnings, revenues or prices.

On July 24, 2003, FERC issued Order 2003 on Standardization of Generation Interconnection Procedures and Agreements. The final rule, which was effective January 20, 2004, requires public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file standard procedures and a standard agreement for interconnecting generators larger than 20 MW. FERC believes that Order 2003 will prevent undue discrimination, preserve reliability, increase energy supply, and lower prices for customers by increasing the number and variety of new generators that will compete in the wholesale electricity market. While the Order requires that new generators fund the cost of transmission system upgrades needed to integrate their new generation, the generator will receive a credit over five years equal to the funding it advances for any transmission upgrades. That ultimately places the burden of the new transmission investment on us. It is reasonable to assume that regulators will allow recovery of such investment from customers, but that is not certain. The impact this order will have on the Company’s earnings, revenues or prices will depend on the number of new generators that interconnect to the Company’s system in the future, the extent of the transmission upgrades required by those generators, and ultimate regulatory treatment of those investments.

On November 25, 2003, FERC issued Order 2004 on Standards of Conduct. In Order 2004, FERC adopts standards of conduct that apply uniformly to interstate gas pipelines and public utilities (jointly referred to as Transmission Providers) that are currently subject to the gas and electric standards of conduct in Part 161 and Part 37 of FERC’s regulations respectively. The new standards of conduct will govern the relationship between regulated Transmission Providers and their Energy Affiliates, and they will eliminate the loop hole in the current regulations that do not cover a Transmission Provider’s relationship with Energy Affiliates that are not marketers of merchant affiliates. The Company is a Transmission Provider because it is a public utility currently subject to Part 37 of FERC’s regulations. We do, however, appear to meet the definition of Energy Affiliate in the new standards of conduct. Because of the burden of the bankruptcy and certain other regulatory proceedings, the Company has been granted a 60-day extension to file its plan for compliance and to be in compliance with the new standards of conduct. It is possible that compliance with Order 2004 may require some level of reorganization of certain Company operations. Although we cannot predict with certainty the impact Order 2004 may 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 we provide 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 $13.9 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. We, as successor to The Montana Power Company, appealed but a FERC decision issued on January 28, 2004, affirmed the original decision.

The limited liability company that formerly held our Montana transmission and distribution assets has been renamed “Clark Fork and Blackfoot, LLC.” 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 2008, and we

are currently seeking to extend that license until 2009. 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, LLC gave the FERC its notice to seek renewal of the license in 2003. In the event the FERC license was terminated, the FERC may require that the dam be removed. If Clark Fork and Blackfoot, LLC does not receive the license extension, then it might be required to relinquish the license, cease operating the dam and remove the structures as early as 2008. Based on estimates received from our environmental consultants, management believes that the cost of such removal would be approximately $10 million.

One of the principal legislative initiatives of the Bush administration is the adoption of comprehensive federal energy legislation. In 2003, an energy bill was passed by the U.S. House of Representatives but was not voted on by the U.S. Senate. The energy bill, as currently written, would repeal the Public Utility Holding Company Act of 1935 (PUHCA), create incentives for the construction of transmission infrastructure, encourage but not mandate standardized competitive markets and expand the authority of the FERC to include overseeing the reliability of the bulk power system. We cannot predict whether comprehensive energy legislation will be adopted and, if adopted, the final form of that legislation. We would expect that comprehensive energy legislation would, if adopted, significantly affect the electric utility industry and its businesses.

Montana

Our 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. As a public utility, we are also subject to MPSC jurisdiction when we issue, assume, or guarantee securities, or when we create liens on our Montana properties. As such, we are required to submit annual filings of certain financial information on the MPSC Annual Report of Electric, Natural Gas, and Propane Utilities.

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 pretax 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 pretax 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 QF costs in 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. On June 12, 2003, the MPSC approved the next annual tracking period amount of $17.4 million to be effective July 1, 2003. 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 $1.8 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.4 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 funded credits to Montana electric distribution customers. The account was applied on a per kilowatt hour basis which began on July 1, 2002, with a term of one year. On June 12, 2003, the MPSC approved the elimination of the Electric Sale Credit effective July 1, 2003.

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 would be able to choose their electric supplier during a transition period through June 30, 2007. Under this legislation, during this transition period, we were designated to serve as the “default

supplier” for customers who have not chosen an alternate supplier. The Montana Restructuring Act provided for the full recovery of costs incurred in procuring default supply contracts during this transition period. 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 and extended the transition period through July 1, 2007. In November 2002, Referendum 117 was passed, repealing HB 474 and reinstating a transition period ending on June 30, 2007. Two new electric energy bills, HB 509 and SB 247, were passed by the 2003 Montana Legislature. Collectively, these two bills establish us as the permanent default supplier, extend the transition period to July 1, 2027, require smaller customers to remain default supply customers, and establish a specific set of requirements and procedures that guide power supply procurements and their cost recovery. Compliance with these procurement procedures should mitigate the risk of nonrecovery of our costs of acquiring electric supply.

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 73% of the annual energy requirements, principally covered by PPL Montana and QF supply contracts. On January 23, 2004, NorthWestern filed with the MPSC its first biannual Electric Default Supply Resource Procurement Plan, which fulfills the requirements established by law and describes the planning we are performing on behalf of its electric default supply customers to acquire a balanced, cost-effective resource portfolio. The immediate needs are for resources that address the variable portion of the load. We plan to present several contracts to the MPSC for approval in 2004, which meet these variable requirements. 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.

On June 16, 2003, we filed an annual electric supply cost tracker request with the MPSC for actual electric supply costs for the 12-month period ended June 30, 2003, and for projected costs for the 12-month period ended June 30, 2004. On July 15, an interim order was approved by the MPSC for the projected electric supply cost.

South Dakota

We are subject to the SDPUC 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 SDPUC and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the SDPUC. Our electric rate schedules provide that we may pass along to all classes of customers qualified increases or decreases in costs related to fuel used in electric generation, purchased power, energy delivery costs and ad valorem taxes.

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

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

Natural Gas Operations

Federal

FERC Order 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. We conduct 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

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

Rates for our Montana natural gas supply are set by the MPSC. We use a monthly gas tracking mechanism in Montana for the recovery of gas supply costs, which we prepare and file monthly 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 rolling 12-month period’s estimates to actual cost information.

We filed an annual gas cost tracker request in Montana in December 2001 for actual gas costs for the 12-month period ended October 31, 2001, and for projected costs for the 12-month period ended October 31, 2002. Our December 2001 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 12-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. That request was finalized by order of the MPSC on July 3, 2003, with the exception of disallowing $6.2 million of our purchased gas costs as having been imprudently incurred. We filed a motion for reconsideration regarding the disallowance of purchased gas cost with the MPSC on July 14, 2003, which was denied. We filed suit in Montana state court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. At this time, no briefing schedule has been set in this matter.

On June 2, 2003, we filed an annual gas cost tracker request with the MPSC for the projected gas costs for the 12-month period ending June 30, 2004. The MPSC granted an interim order on July 3, 2003, for the projected gas cost adjusted for 4,200 MDKT at a fixed price of $3.50 as opposed to the market price submitted in the original filing, which was at a higher price. If our average forecast price over the next 6 months actually occurs, the disallowance on a 4,200 MDKT at market price would result in the Company undercollecting approximately $4.5 million for the period July 1, 2003 through June 30, 2004.

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 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, was credited to customers’ bills over approximately a two-year period, which began February 1, 2002. This customer credit was fully refunded by December 2003.

South Dakota

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

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

Nebraska

Beginning in the spring of 2003, our natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated in the State of Nebraska by the Nebraska Public Service Commission (NPSC). High volume customers are not subject to such regulation but can file complaints if they allege discriminatory treatment. Under the State Natural Gas Regulation Act, effective May 30, 2003, for a regulated natural gas utility, like NorthWestern, to propose a change in rates to its regulated customers, it is required to file an application for a rate increase with the NPSC and with the communities in which it serves customers. The utility may negotiate with those communities for a settlement with regard to the rate change, or it may proceed to have the NPSC review the filing and make a determination. While the utility and the communities are negotiating a settlement, the utility can commence charging the requested rate, as interim rates subject to refund, 60 days after the filing of the increase request. If the utility and the communities are unable to reach a settlement, then the matter is transferred to the NPSC for its review and further proceedings. The interim rates become final and no longer subject to refund if the NPSC has not taken final action within 210 days after the matter is referred to the NPSC.

Since enactment of the State Natural Gas Regulation Act, our initial tariffs, representing rates in effect at the time the law was approved, have been accepted by the NPSC, and the NPSC has adopted certain rules governing the terms and conditions of service of regulated natural gas utilities. Additional rulemaking proceedings will be undertaken in 2004. Our retail natural gas tariffs provide residential, general service and commercial and industrial options, as well as firm and interruptible transportation service. A purchased gas adjustment clause provides for adjustments based on changes in gas supply and interstate pipeline transportation costs.

Seasonality and Cyclicality

Our electric and gas utility businesses are seasonal businesses, and weather patterns can have a material impact on their operating performance. Because natural gas is used primarily for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Demand for electricity is often greater in the summer and winter months 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.

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 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 orders and decisions.

We did not incur any material environmental expenditures in 2003. 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. 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 of 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 implements President Bush’s “Clear Skies”

proposal, or 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 passed, would likely require the adoption of administrative regulations. We cannot reasonably determine whether any proposals would impose additional costs, or if so, the timing or magnitude of those costs.

The EPA is conducting an enforcement initiative at a number of coal-fired power plants across the United States in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. In connection with this initiative, the EPA has requested information from us regarding certain of our South Dakota operations under Section 114(a) of the Clean Air Act (Section 114). The EPA has issued similar requests to certain power plants previously owned by the Montana Power Company, including the Corrette and Colstrip power plants, the latter of which we continue to lease a 30% interest in Unit #4. The Section 114 information requests required that we provide responses to specific EPA questions regarding certain projects and maintenance activities that the EPA believes could have violated the New Source Performance Standard and New Source Review requirements of the Clean Air Act. The EPA contends that power plants are required to update emission controls at the time of major maintenance or capital activity. We believe that maintenance and capital activities performed at our power plants are generally routine in nature and are typical for the industry. We have complied and continue to comply with these information requests and the EPA has not filed an enforcement action against us, but we cannot predict the outcome of this investigation at this time. Should the EPA determine to take action, the resulting additional costs to comply could be material.

We have 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, 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. As previously disclosed in our third quarter 10-Q, we engaged the services of a third-party environmental consulting firm to perform a comprehensive evaluation of our historical and current utility operations. Based upon the results of this evaluation, we have increased our environmental reserve by $7.4 million. Based upon information available to our consultants at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation, however, may be subject to change as a result of the following uncertainties:

• We and our third-party consultant may not know all sites for which we are alleged or will be found to be responsible for remediation; and

• Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of 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 CERCLIS, list as contaminated with coal tar residue. We are currently investigating these sites pursuant to work plans approved by the EPA and the South Dakota Department of Environment and Natural Resources. At this time, we know that no material remediation is necessary at the Mitchell location. However, at this time we, anticipate that remediation will likely be necessary at the Aberdeen site in the future. We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. The EPA has conducted site screening investigations at these sites for alleged soil and groundwater contamination. At present, we cannot estimate with a reasonable degree of certainty the total costs of any cleanup at these sites. However, based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and our belief that we will be able to recoup prudently incurred costs in rates, we do not expect cleanup costs at these sites 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 incur. 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. We continue 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, was 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 provided to the holder of the Milltown Dam license. By virtue of its acquisition of The Montana Power Company’s electric and natural gas transmission and distribution business and the Milltown Dam, Clark Fork and Blackfoot, LLC succeeded to similar protection under this statutory exemption. ARCO, however, has argued that the owner of the Milltown Dam should be considered a PRP and threatened to challenge Clark Fork and Blackfoot, LLC’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, LLC’s potential liability under such a challenge and limit 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. The EPA formally released for public comment a proposed remedial plan for the Milltown Reservoir, which would require us to voluntarily agree to take down the Milltown Dam and remove the related power generation facility as part of an overall remedy to address heavy metal contamination in the Milltown Reservoir. The EPA plans to issue its final Record of Decision in spring 2004. In light of the EPA’s stated position, we executed a confidential settlement agreement with ARCO on September 10, 2003, which, among other things, caps our maximum contribution towards the remediation of the Milltown Reservoir superfund site. Previously, NorthWestern and ARCO executed a settlement agreement which caps our potential liability for remediation of the Milltown site at no more than $10 million. We are currently seeking approval of this settlement agreement from the Bankruptcy Court. The amount of our expected contribution has been fully accrued in the accompanying financial statements. Commencing the month following Bankruptcy Court approval and each month thereafter, we will pay $500,000 into an escrow account until our total agreed upon amount is funded. No interest will accrue on the unpaid balance due ARCO. The escrow account will remain funded until a final, nonappealable consent decree is entered by the United States District Court. If, however, we are unable to negotiate an acceptable consent decree with the interested parties, we may terminate the settlement agreement with ARCO, which will trigger the return of the escrowed funds to us. The settlement agreement provides us with appropriate ARCO releases and indemnifications. There can be no assurance that the Bankruptcy Court will approve the proposed settlement with ARCO. Moreover, the settlement agreement does not affect or impact any rights, claims, or causes of action that the United States or the State of Montana may have against us arising from our ownership and operation of the Milltown Dam facility. The Company also secured a 10-year, $100 million environmental insurance policy, effective May 31, 2002, to mitigate the risk of future environmental 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 preclosing 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 in Butte and Helena, Montana where it formerly operated manufactured gas plants and had investigated a third in Missoula, Montana at the time of our acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company. Only the Butte and Helena, Montana sites were placed into the MDEQ’s voluntary remediation program for cleanup due to the existence of minor exceedences in groundwater of regulated pollutants. We believe that natural attenuation should address the problems at these sites. The investigation conducted at the Missoula site did not require entry into the MDEQ voluntary remediation program, but required preparation of a groundwater monitoring plan. Monitoring of groundwater continues at all of the Montana manufactured gas plant sites. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may become necessary in the future to prevent contamination from migrating offsite. Therefore, continued monitoring of groundwater at this site is necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty what the costs of additional cleanup will be for such groundwater remediation at Helena, or whether additional cleanup will be required at the Butte and Missoula sites. However, based upon the information available to date, our current environmental liability reserves and applicable insurance coverage, we do not expect cleanup costs at these sites to be material.

In April 1998, the Montana Power Company identified and reported a release of hydrocarbons during the replacement of a dispensing unit associated with an underground storage tank located at its Helena Operating Center. Impacted soils were removed and groundwater monitoring wells were installed. With the acquisition of the Montana Power Company, we succeeded to the liability associated with the site. To date, hydrocarbons remain detectable at low levels in groundwater and soil vapor extraction efforts are underway to remove the contaminants. We do not expect 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 electric and natural gas transmission and distribution business of The Montana Power Company, we assumed the first $50 million of NorthWestern Energy LLC’s preclosing environmental liabilities, including these retained environmental liabilities. Touch America Holdings, Inc. assumed the next $25 million in costs. NorthWestern Energy LLC and Touch America Holdings, Inc. agreed to equally split costs that fall between $75 and $150 million. In light of the bankruptcy filing by Touch America, we do not believe Touch America will be able 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. As of December 31, 2003, we have a reserve of approximately $43.9 million to cover all estimated environmental liabilities. We anticipate that as environmental costs become fixed and determinable we will seek insurance coverage and/or rate recovery, therefore we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

Intellectual Property

NorthWestern utilizes a variety of registered and unregistered trademarks and service marks for their respective products and services. Common law and state unfair competition laws govern unregistered marks. We regard our trademarks and service marks 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 protect our intellectual property and oppose any infringement of our trademarks and service marks. 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 employees and attempt to limit access to and distribution of proprietary information.

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, 2005.

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.

ITEM 3. LEGAL PROCEEDINGS

On September 14, 2003, we filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware under case number 03-12872 (CGC). We will continue to manage our properties and operate our business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with Sections 1107(a) and 1108 of Chapter 11. As a result of the Chapter 11 filing, attempts to collect, secure or enforce remedies with respect to most prepetition claims against us are subject to the automatic stay provisions of Section 362(a) of Chapter 11. The description of our bankruptcy proceedings appearing in this Report at Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview, is incorporated herein by reference.

We, and certain of our present and former officers and directors, were named as defendants in numerous complaints purporting to be class actions which were filed in the United States District Court for the District of South Dakota, Southern Division, alleging violations of Sections 11, 12 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder. The complaints contained varying allegations, including that the defendants misrepresented and omitted material facts with respect to our 2000, 2001, and 2002 financial results and operations included in its filings with the SEC, press releases, and registration statements and prospectuses disseminated in connection with certain offerings of debt, equity, and trust preferred securities. The complaints seek unspecified compensatory damages, rescission, and attorneys’ fees and costs as well as accountants’ and experts’ fees. In June 2003, the complaints were consolidated in the United States District Court for the District of South Dakota and given the caption In re NorthWestern Corporation Securities Litigation, Case No. 03-4049, and Carpenters Pension Trust for Southern California, Oppenheim Investment Management, LLC, and Richard C. Slump were named as co-lead plaintiffs (the “Lead Plaintiffs”). In July 2003, the Lead Plaintiffs filed a consolidated amended class action complaint naming NorthWestern, NorthWestern Capital Financing II and III, Blue Dot, Expanets, certain of our present and former officers and directors, along with a number of investment banks that participated in the

securities offerings. The amended complaint alleges that the defendants misrepresented and omitted material facts concerning the business operations and financial performance of NorthWestern, Expanets, Blue Dot and CornerStone, overstated NorthWestern’s revenues and earnings by, among other things, maintaining insufficient reserves for accounts receivable at Expanets, failing to disclose billing problems and lapses and data conversion problems, failing to make full disclosures of problems (including the billing and data conversion issues) arising from the implementation of Expanets’ EXPERT system, concealing losses at Expanets and Blue Dot by improperly allocating losses to minority interest shareholders, maintaining insufficient internal controls, and profiting from improper related-party transactions. We, and certain of our present and former officers and directors, were also named as defendants in two complaints purporting to be class actions which were filed in the United States District Court for the Southern District of New York, entitled Sanford & Beatrice Golman Family Trust, et al. v. NorthWestern Corp., et al., Case No. 03CV3223, and Arthur Laufer v. Merle Lewis, et al., Case No. 03CV3716, which were brought on behalf of the purchasers of our 7.20%, 8.25%, and 8.10% trust preferred securities which were offered and sold pursuant to our registration statement on Form S-3 filed on July 12, 1999. The plaintiffs’ claims are based on similar allegations of material misrepresentations and omissions of fact relating to the registration statement in violation of Sections 11 and 12 of the Securities Act of 1933 and they seek unspecified compensatory damages, rescission and attorneys’, accountants’ and experts’ fees. In July 2003, Arthur Laufer v. Merle Lewis, et al. was transferred to the District of South Dakota and consolidated with the consolidated actions pending in that court. In September 2003, Sanford & Beatrice Golman Family Trust, et al. v. NorthWestern Corp., et al. was also transferred to the District of South Dakota. The actions have been stayed as to NorthWestern Corporation due to its bankruptcy filing. In October 2003, Expanets, Blue Dot, and certain of NorthWestern’s present and former officers and directors filed motions to dismiss the consolidated amended class action complaint for failure to state a claim, which are currently pending in the District of South Dakota.

Certain of our present and former officers and directors and NorthWestern, as a nominal defendant, have been named in two shareholder derivative actions commenced in the United States District Court for the District of South Dakota, Southern Division, entitled Deryl Lusty, et al. v. Richard R. Hylland, et al., Case No. CIV034091 and Jerald and Betty Stewart, et al. v. Richard R. Hylland, et al., Case No. CIV034114. These shareholder derivative lawsuits allege that the defendants breached various fiduciary duties based upon the same general set of alleged facts and circumstances as the federal shareholder suits. The plaintiffs seek unspecified compensatory damages, restitution of improper salaries, insider trading profits and payments from NorthWestern, and disgorgement under the Sarbanes-Oxley Act of 2002. In July 2003, the complaints were consolidated in the United States District Court for the District of South Dakota and given the caption In re NorthWestern Corporation Derivative Litigation, Case No. 03-4091. In October 2003, the action was stayed pending a ruling on defendants’ motions to dismiss in the related securities class action, In re NorthWestern Corporation Securities Litigation. On November 6, 2003, the Bankruptcy Court entered an order preliminarily enjoining the plaintiffs in In re NorthWestern Corporation Derivative Litigation from prosecuting the litigation against NorthWestern, its subsidiaries and its current and former officers and directors until further order of the Bankruptcy Court.

On February 7, 2004, the parties to the above consolidated securities class actions and consolidated derivative litigation, together with certain other affected persons and parties, reached a tentative settlement of the litigation. Among the terms of the proposed settlement, we, Expanets, Blue Dot and other parties and persons will be released from all claims relating to these cases, a settlement fund in the amount of $41 million (of which approximately $37 million would be contributed by our directors and officers liability insurance carriers, and $4 million would be contributed from other persons and parties) will be established for the benefit of class members, and, if Netexit seeks bankruptcy protection, the plaintiffs would have a $20 million liquidated securities claim against Netexit. The proposed settlement is subject to the occurrence of several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding, approval of the proposed settlement by the federal District Court for the District of South Dakota, where the consolidated class actions are pending, and approval by the Bankruptcy Court of our plan of reorganization. If for any reason these conditions do not occur and the settlement is not approved, we intend to vigorously defend against these lawsuits. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern, NorthWestern Communications Solutions, Expanets and Blue Dot. This action follows the SEC’s requests for information made in connection with the previously disclosed SEC informal inquiry into questions regarding the restatements and other accounting and financial reporting matters. In addition, a NorthWestern director was interviewed by representatives of the Federal Bureau of Investigation (FBI) concerning certain of the allegations made in the class action securities and derivative litigation matters. Northwestern has not been contacted by the FBI and has not been advised that NorthWestern is the target of its investigation. We are cooperating with the SEC’s investigation and intend to cooperate with the FBI if we are contacted in connection with its investigation. We understand that the FBI or the Internal Revenue Service (IRS) may have contacted former and current employees of ours or of our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters. We cannot predict whether or not any other governmental inquiry or investigation will be commenced, nor can we predict the outcome of the SEC, FBI, IRS or any other governmental inquiry or investigation or related litigation or proceeding.

the power facility. We intend to vigorously defend against these adversary proceedings. In the opinion of management, the amount of ultimate liability with respect to these adversary proceedings will not materially affect our financial position or results of operations or our ability to timely confirm a plan of reorganization.

Expanets and NorthWestern have been named defendants in two complaints filed with the Supreme Court of the State of New York, County of Bronx, alleging violations of New York’s prevailing wage laws, breach of contract, unjust enrichment, willful failure to pay wages, race, ethnicity, national origin and/or age discrimination and retaliation. In the complaint entitled Felix Adames et al. v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, County of Bronx, Index No. 8664-04, which has not yet been served upon Expanets, fourteen former employees of Expanets seek damages in the amount of $27,750,000, plus interest, penalties, punitive damages, costs, and attorney’s fees. In the complaint entitled Wayne Belnavis and David Daniels v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, County of Bronx, Index No. 8729-04, which has not yet been served upon Expanets, two former employees of Expanets seek damages in the amount of $12,500,000, plus interest, penalties, punitive damages, costs, and attorney’s fees. We intend to vigorously defend against the allegations made in these complaints. Though the filing of the complaint may violate the automatic stay provisions of the U.S. Bankruptcy Code and maybe subject to the claims process of the bankruptcy proceeding, we cannot currently predict the impact or resolution of these claims or reasonably estimate a range of possible loss, which could be material, and the resolution of these claims may harm our business and have a material adverse impact on our financial condition.

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al, now pending in federal court in Montana. The lawsuit, which was filed by the former shareholders of The Montana Power Company (most of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of The Montana Power Company), claims that the disposition of various generating and energy-related assets by The Montana Power Company were void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern Corporation is named as a defendant due to the fact that we purchased Montana Power LLC, which plaintiffs claim is a successor to The Montana Power Company. We intend to vigorously defend against this lawsuit. On November 6, 2003, the Bankruptcy Court approved a stipulation between NorthWestern and the plaintiffs in McGreevey, et al. v. The Montana Power Company, et al. The stipulation provides that litigation, as against Northwestern, Clark Fork & Blackfoot LLC, the Montana Power Company, Montana Power LLC and Jack Haffey, shall be temporarily stayed for 180 days from the date of the stipulation. Pursuant to the stipulation and after providing notice to Northwestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

In Northwestern Corporation vs. PPL Montana, LLC vs. Northwestern Corporation and Clark Fork and Blackfoot, LLC, No. CV-02-94-BU-SHE, (D. MT), the Company is pursuing claims against PPL Montana, LLC due to its refusal to purchase the Colstrip transmission assets which under the Asset Purchase Agreement (“APA”) executed by and between The Montana Power Company (“MPC”) and PP&L Global, Inc. (“PPL Global”), NorthWestern claims PPL Montana, LLC (“PPL”) (PPL Global’s successor-in-interest under the APA) is required to purchase the Colstrip transmission assets for $97.1 million. PPL has also asserted a number of counterclaims against NorthWestern and Clark Fork based in large part upon PPL’s claim that MPC and/or NorthWestern Energy breached two Wholesale Transition Service Agreements and certain indemnification obligations under the APA in the approximate amount of $40 million. PPL has moved the Bankruptcy Court for relief from the automatic stay to pursue its counterclaims. PPL also filed a proof of claim against NorthWestern’s bankruptcy estate. NorthWestern has objected to PPL’s motion to lift the automatic stay and has also filed a motion to transfer the venue of the entire litigation to the United States District Court for the District of Delaware, where it would ultimately be referred to the United States Bankruptcy Court for the District of Delaware so as to resolve the litigation as part of NorthWestern’s pending bankruptcy reorganization. PPL has objected to such motion and a hearing is scheduled on NorthWestern’s motion in March 2004.

We are also one of several defendants in a class action lawsuit entitled In Re Touch America ERISA Litigation, which is currently pending in federal court in Montana. The lawsuit was filed by participants in the former Montana Power Company retirement savings plan and alleges that there was a breach of fiduciary duty in connection with the employee stock ownership aspects of the plan. The federal court has recently entered orders indefinitely staying the ERISA litigation because of Touch America Holdings Inc.’s bankruptcy filing. We intend to vigorously defend against these lawsuits. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

We, and certain of our former officers and directors, were named as defendants in certain complaints filed against CornerStone Propane Partners, LP and other defendants purporting to be class actions filed in the United States District Court for the Northern District of California by purchasers of units of CornerStone Propane Partners alleging violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder. Through November 1, 2002, we held an economic equity interest in a subsidiary that serves as the managing general partner of CornerStone Propane Partners, LP. Certain former officers and directors of NorthWestern who are named as defendants in certain of these actions have also been sued in their capacities as directors of the managing general partner. These complaints allege that defendants sold units of CornerStone Propane Partners based upon false and misleading statements and failed to disclose material information about CornerStone Propane Partners’ financial condition and future prospects, including overpayment for acquisitions, overstating earnings and net income, and that it lacked adequate internal controls. All of the lawsuits have now been consolidated and Gilbert H. Lamphere has been named as lead plaintiff. The actions have been stayed as to NorthWestern Corporation due to our bankruptcy filing. On October 27, 2003, the plaintiffs filed an amended consolidated class action complaint. The new complaint does not name NorthWestern as a defendant, although it alleges facts relating to NorthWestern’s conduct. Certain of our former officers and directors are named as defendants in the amended consolidated complaint. The plaintiffs seek compensatory damages, prejudgment and post judgment interest and costs, injunctive relief, and other relief. We intend to vigorously defend against these lawsuits. On November 6, 2003, the Bankruptcy Court entered an order approving a stipulation between NorthWestern and plaintiffs in this litigation. The stipulation provides that litigation as against NorthWestern shall be temporarily stayed for 180 days from the date of the stipulation. Pursuant to the stipulation and after providing notice to Northwestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition

or ability to timely confirm a plan of reorganization.

We were named in a complaint filed against CornerStone Propane GP, Inc., CornerStone Propane Partners LP and other defendants in a lawsuit entitled Leonard S. Mewhinney, Jr. v. Northwestern Corporation in the circuit court of the city of St. Louis, state of Missouri. The complaint alleges that the plaintiff purchased units of Cornerstone Propane Partners, LP between March 13, 1998 and November 29, 2001, and that NorthWestern owned and controlled all or the majority of stock or other indicia of ownership of Cornerstone Propane, GP, Inc. and all other entities that were the general partners of Cornerstone Propane Partners, LP. According to the plaintiff, NorthWestern, Cornerstone Propane GP, Inc., Coast Gas, Inc. and Cornerstone Propane Partners, LP breached fiduciary duties to the plaintiff by engaging in certain misconduct, including mismanaging Cornerstone Propane Partners, LP and transferring its assets for less than market value and other activities. The complaint further alleges that the defendants fraudulently failed to disclose material information regarding the value of units of Cornerstone Propane Partners, LP and violated the Florida Securities Act in connection with the sale of such units. The plaintiff seeks compensatory damages, punitive damages and costs. The complaint was amended to add a state class action claim. All defendants filed a petition to remove the case to the federal court in St. Louis, Missouri, but the federal court granted plaintiffs motion to remand. The case has now been stayed against NorthWestern due to our bankruptcy filing. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

Certain of our former officers and directors, and CornerStone Propane Partners, LP, as a nominal defendant, are among other defendants named in two derivative actions commenced in the Superior Court for the State of California, County of Santa Cruz, entitled Adelaide Andrews v. Keith G. Baxter, et al., Case No. CV146662 and Ralph Tyndall v. Keith G. Baxter, et al., Case No. CV146661. These derivative lawsuits allege that the defendants breached various fiduciary duties based upon the same general set of alleged facts and circumstances as the federal unitholder suits. The plaintiffs seek unspecified compensatory damages, treble damages pursuant to the California Corporations Code, injunctive relief, restitution, disgorgement, costs, and other relief. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

On April 30, 2003, Mr. Richard Hylland, our former President and Chief Operating Officer, filed a demand for arbitration of contract claims under his employment agreement, as well as tort claims for defamation, infliction of emotional distress and tortuous interference and a claim for punitive damages. Mr. Hylland is seeking relief in an amount of $25 million, plus interest, attorney’s fees, costs, and punitive damages. Mr. Hylland has also filed claims in our bankruptcy case similar to the claims in his arbitration demand. We dispute Mr. Hylland’s claims and intend to vigorously defend the arbitration and object to Mr. Hylland’s claims in our bankruptcy case. On May 6, 2003, based on the recommendations of the Special Committee of the Board formed to evaluate Mr. Hylland’s performance and conduct in connection with the management of NorthWestern and its subsidiaries, the Board determined that Mr. Hylland’s performance and conduct as President and Chief Operating Officer warranted termination under his employment contract. This arbitration has been stayed due to our bankruptcy filing.

On August 12, 2003, the MCC filed a Petition for Investigation, Adoption of Additional Regulatory Controls and Related Relief with the MPSC. On August 22, 2003, the MPSC issued an order initiating an investigation of NorthWestern Energy relating to, among others, finances, corporate structure, capital structure, cash management practices, and affiliated transactions. The relief sought includes adoption of new regulatory controls that would specifically apply to NorthWestern, including additional reporting, cost allocation and financing rules and requirements, and examination of affiliate transactions necessary to ensure that we are not operating our energy division, and will not in the future operate, in a manner that would prejudice our ability to furnish reasonably adequate service and facilities at reasonable and just charges as required under Montana law. A procedural schedule was set in January 2004 with a hearing tentatively scheduled for June 2004. We cannot determine the impact or resolution of this petition, however, any action taken by the MPSC to increase the regulatory controls under which we operate may have a material affect on our liquidity, operations and financial condition. If we are unable to comply with any MPSC orders in a timely manner, then we may become subject to material monetary penalties and fines. We are working with the MCC to provide requested information in a timely manner, but we have reserved the right to contest whether this proceeding is stayed as a result of our bankruptcy filing.

We are also subject to various other legal proceedings and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these actions will not materially affect our financial position or results of operations or ability to timely confirm a plan of reorganization.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of our security holders during the quarter ended December 31, 2003.

Part II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS

On September 15, 2003, in connection with our Chapter 11 filing, the New York Stock Exchange (NYSE) suspended trading in and subsequently delisted our common stock and all five series of our trust preferred securities. On October 10, 2003, the SEC issued an order granting the application of the NYSE to delist our common stock and trust preferred securities. We now participate in the Over-the-Counter Bulletin Board Quotation Service maintained by National Association of Securities Dealers, Inc., or the OTCBB. The OTCBB is an electronic quotation medium for securities traded outside of the Nasdaq Stock Market, and prices for our common stock are published on the OTCBB under the trading symbol NTHWQ.PK. The first trade of our common stock on the OTCBB occurred on October 6, 2003. The OTCBB market is extremely limited and the prices quoted are not a reliable indication of the value of our common stock. We do not believe that our common stock currently has any value.

The following table sets forth the high and low bid prices for our common stock for each quarter during the last two fiscal years and the cash dividends paid per share during each period. The quotations set forth below reflect interdealer prices, without retail mark-up, mark-downs, or commissions and may not represent actual transactions:

QUARTERLY COMMON STOCK DATA

	Prices				Cash Dividends Paid
	High		Low		Cash Dividends Paid
2002
First Quarter	$	23.64	$	20.35	$	.3175
Second Quarter	22.30		14.20		$	.3175
Third Quarter	16.90		8.40		$	.3175
Fourth Quarter	9.79		4.30		$	.3175
2003
First Quarter	6.18		1.41		—
Second Quarter	3.09		1.65		—
Third Quarter	2.12		0.15		—
Fourth Quarter	0.32		0.08

On March 8, 2004, the last reported sale price on the OTCBB for our common stock was $0.12.

We terminated the historical practice of paying cash dividends during the first quarter of 2003. Our existing common stock will be cancelled in connection with the adoption of our plan of reorganization.

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. The sole assets of these trusts are the investments in subordinated debentures, which are interest bearing. In connection with our bankruptcy filing, these trusts were terminated pursuant to their terms and the subordinated debentures are subject to compromise.

Holders

As of March 8, 2004, there were 7,465 holders of record of 37,680,095 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. Our outstanding stock options and restricted stock have no value and will be cancelled in connection with the adoption of our plan of reorganization. The table presents the following data on plans approved by shareholders and plans not so approved, all as of the close of business on December 31, 2003 (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 4 and 19 to our Financial Statements included in Item 8 herein.

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (1) (c)

Equity compensation plans approved by security holders
(1) Stock Option and Incentive Plan	1,359,188	$	15.81	1,782,074

Restricted Stock	283,333	4.40		—
Equity compensation plans not approved by security holders
None	N/A	N/A		N/A
Total	1,642,521			1,782,074

(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.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data has been derived from our consolidated financial statements and should be read in conjunction with the consolidated financial statements and notes thereto and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other financial data included elsewhere in this report. The historical results are not necessarily indicative of results to be expected for any future period. During 2003 we committed to a plan to sell or liquidate our interest in Expanets and Blue Dot and accounted for our interest in these subsidiaries as discontinued operations. In 2002 we disposed of our interest in CornerStone and accounted for the disposal as discontinued operations. Accordingly, the financial data below has been restated for fiscal years 1999 through 2002.

FIVE-YEAR FINANCIAL SUMMARY

	2003			2002			2001			2000			1999
	(in thousands except per share data)
Financial Results
Operating revenues	$	1,027,437		$	783,744		$	255,151		$	188,390		$	161,708

Income (loss) from continuing operations	(71,582		)	(9,356		)	4,175			3,349			13,581

Basic earnings (loss) per share from continuing operations	(2.31		)	(1.29		)	(.11		)	(.15		)	.29

Diluted earnings (loss) per share from continuing operations	(2.31		)	(1.29		)	(.12		)	(.15		)	.29

Dividends paid per common share	—			1.27			1.21			1.13			1.05

Financial Position (as of December 31)
Total assets	$	2,444,511		$	2,785,061		$	2,641,685		$	2,898,070		$	1,956,761

Long-term debt, including current portion and amount subject to compromise	1,784,236			1,668,431			583,651			514,347			316,406

Preferred stock not subject to mandatory redemption	—			—			3,750			3,750			3,750

Preferred stock subject to mandatory redemption	365,550			370,250			187,500			87,500			87,500

Ratio of earnings to fixed charges (1)	—			—			—			—			1.38

(1) The fixed charges exceeded earnings, as defined by this ratio, by $86.6 million, $77.8 million, $9.5 million and $4.1 million in 2003, 2002, 2001 and 2000 respectively.

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 24 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

Our financial condition has been significantly and negatively affected by the poor performance of our nonenergy businesses and our significant indebtedness. In early 2003, we undertook a series of steps designed to refinance, reduce and extend the maturities of our debt. Notwithstanding these efforts, our financial position continued to deteriorate, principally due to the poor performance of our non-utility subsidiaries and our leveraged condition. As a result of these developments, in June 2003, we announced that we would seek to fundamentally restructure our capital, and announced that we had retained legal and financial advisors to assist us in these efforts. We ultimately decided to seek to reorganize under Chapter 11 of the Federal Bankruptcy Code.

On September 14, 2003 (Petition Date), we filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court under case number 03-12872 (CGC). Pursuant to Chapter 11, we retain control of our assets and are authorized to operate our business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Included in the consolidated financial statements are subsidiaries that are not party to the Chapter 11 case and are not debtors. The assets and liabilities of such nondebtor subsidiaries are not considered to be material to the consolidated financial statements or are included in discontinued operations.

In connection with any plan of reorganization, our common stock will be cancelled and our mandatorily redeemable preferred securities of subsidiary trusts (trust preferred securities) will be restructured in a manner that will eliminate or very substantially reduce any remaining value with respect to such trust preferred securities. We have previously stated that the planned sale of noncore assets, including Expanets and Blue Dot, is not expected to change our view that our common stock has no value. Accordingly, we urge that appropriate caution be exercised with respect to existing and future investments in any of our liabilities and/or securities.

On September 15, 2003, in connection with our Chapter 11 filing, the New York Stock Exchange (NYSE) suspended trading and subsequently delisted our common stock and all series of our trust preferred securities. On October 10, 2003, the SEC issued an order granting the application of the NYSE to delist our common stock and trust preferred securities. As a result of the delisting of our securities, there can be no assurance that a liquid trading market for those securities will continue.

As a result of our Chapter 11 filing, we operate our business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code, the Federal Rules of Bankruptcy Procedure and applicable court orders. All vendors are being paid for all goods furnished and services provided after the Petition Date under the supervision of the Bankruptcy Court. As a debtor-in-possession, we are authorized to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the approval of the Court, after notice and an opportunity for a hearing.

Our ability to continue as a going concern is predicated upon numerous issues, including our ability to achieve the following:

• having a plan of reorganization confirmed by the Bankruptcy Court in a timely manner;

• being able to successfully implement our business plans and otherwise offset the negative effects that the Chapter 11 filing has had and may continue to have on our business, including the impairment of vendor relations;

• operating within the framework of our DIP Facility, including limitations on capital expenditures and financial covenants, our ability to generate cash flows from operations or seek other sources of financing and the availability of projected vendor credit terms; and

• attracting, motivating and/or retaining key executives and associates.

These challenges are in addition to those operational, regulatory and other challenges that we face in connection with our business as a regional utility.

On September 16, 2003, following first day hearings held on September 15, 2003, the Bankruptcy Court entered orders granting

us authority to, among other things, pay prepetition and postpetition employee wages, salaries, benefits and other employee obligations, pay selected vendors and other providers for the postpetition delivery of goods and services, continue bank accounts and existing cash management system, and continue existing forward power contracts and enter into additional similar contracts in the ordinary course of business. On November 7, 2003, the Bankruptcy Court entered a final order to approve access of up to $85 million of the $100 million debtor-in-possession financing facility arranged by the company with Bank One, N.A. (DIP Facility). In December 2003, we reduced the commitment to $85 million under this facility. The DIP Facility expires on September 12, 2004, and bears interest at a variable rate tied to the Eurodollar rate plus a spread of 3.00% or at the prime rate plus a spread of 1.00%. The DIP Facility will provide a source of liquidity during the course of our bankruptcy, but requires that we maintain certain other financial covenants and restricts liens, indebtedness, capital expenditures, dividend payments and sales of assets. As of December 31, 2003, we had $15.2 million in letters of credit outstanding and no borrowings under the DIP Facility.

We reached an agreement with the lenders holding claims under our senior credit facility agented by Credit Suisse First Boston (CSFB) in October 2003 to reduce the interest rate of our $390 million prepetition credit facility. The amended credit facility provides advantages to NorthWestern, including lower interest expense and allowing reinstatement upon NorthWestern’s emergence from Chapter 11. At NorthWestern’s option, the amended credit facility bears interest at a variable rate tied to the Eurodollar rate, plus a spread of 5.50%, or at an alternate base rate, as defined by the amended credit facility, plus a spread of 3.50%. There is no longer a minimum floor for the Eurodollar rate or the alternate base rate. As a result of this amendment, we estimate annualized interest expense will be reduced by approximately $6 million to $8 million.

The Chapter 11 filing triggered defaults, or termination events, on substantially all of our debt and lease obligations, and certain contractual obligations. As such, we have classified all of our secured debt as current as of December 31, 2003. Subject to certain exceptions under the Bankruptcy Code, our Chapter 11 filing automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against us or our property to recover on, collect or secure a claim arising prior to the Petition Date. Thus, for example, creditor actions to obtain possession of our property, or to create, perfect or enforce any lien against our property, or to collect on or otherwise exercise rights or remedies with respect to a prepetition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

On November 4, 2003, we filed our schedules and statements of financial affairs with the Bankruptcy Court, setting forth, among other things, the assets and liabilities of the Company. These schedules were amended on December 2, 2003. In October 2003, the Bankruptcy Court set January 15, 2004 as the deadline for all of our creditors, except governmental units, to file proofs of claim against our estate. The Bankruptcy Court set April 15, 2004 as the deadline for all of our governmental unit creditors to file proofs of claim against our estate. Any holder of a claim that fails to file a timely proof of claim on or before the applicable bar date is forever barred from asserting such claim against us, our successors or our property, and shall not be treated as a creditor for purposes of voting on or receiving distributions or notices under a plan of reorganization. A total of approximately 1,031 claims were scheduled and filed against our estate with an aggregate asserted liability of approximately $8.8 billion as of January 15, 2004. The foregoing claims may include, among other things, invalid, overstated, objectionable and duplicative claims. We also have numerous executory contracts and other agreements that could be assumed or rejected during the Chapter 11 proceedings. In the event we choose to reject an executory contract or unexpired lease, parties affected by these rejections may file claims with the court-appointed claims agent as proscribed by the Bankruptcy Code and/or orders of the Bankruptcy Court. Unless otherwise agreed, the assumption of an executory contract or unexpired lease will require us to cure all prior defaults under such executory contract or lease, including all prepetition liabilities, some of which may be significant. We expect that liabilities that will be subject to compromise through the Chapter 11 process will arise in the future as a result of the rejection of additional executory contracts and/or unexpired leases, and from the determination of the Bankruptcy Court (or agreement by parties in interest) of allowed claims for items that we now claim as contingent or disputed. Conversely, we would expect that the assumption of additional executory contracts may convert some liabilities shown on our financial statements as subject to compromise to postpetition liabilities.

In January 2004, we filed a motion to approve amendments to an existing Employee Incentive Plan. We believe that the commencement of the Chapter 11 case engendered uncertainty among our employees, particularly our critical senior and mid-level management employees. Accordingly, to prevent the departure of management and its employees, and possible disruption of our operations and reorganization efforts, we amended our existing Employee Incentive Plan to provide incentives to employees and to reduce costs. The Bankruptcy Court approved the amendments to our Employee Incentive Plan in February 2004.

To successfully exit Chapter 11, we will need to propose, and obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization would resolve, among other things, the debtor’s prepetition obligations, set forth the revised capital structure of the newly reorganized entity and provide for its corporate governance subsequent to exit from bankruptcy. Under the Chapter 11 proceedings, the rights of and ultimate payments to prepetition creditors, rejection damage claimants and equity investors may be substantially altered. This could result in claims being allowed and/or satisfied in the Chapter 11 proceedings at less (possibly substantially less) than 100% of their face value, and we anticipate the interests of our equity investors will be cancelled. Substantially all prepetition liabilities are subject to settlement under a plan of reorganization to be voted upon by our prepetition creditors and approved by the

Bankruptcy Court. In January 2004, the Bankruptcy Court extended our exclusive period to file a plan of reorganization through and including March 12, 2004, and extended the time to solicit votes on our plan of reorganization through and including May 11, 2004. We filed our initial plan of reorganization on March 12, 2004. Although our plan of reorganization provides for our emergence from bankruptcy as a going concern, there can be no assurance at this time our plan of reorganization will be confirmed by the Bankruptcy Court or that any such plan will be implemented successfully. We have incurred, and will continue to incur pending emergence, significant costs associated with the reorganization.

The United States Trustee for the Bankruptcy Court has appointed an official committee of unsecured creditors (Creditors’ Committee). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court and may take positions on matters that come before the Bankruptcy Court. There can be no assurance that the Creditors’ Committee will support our positions or our plan of reorganization, and disagreements between us and the Creditors’ Committee could protract the Chapter 11 case, could negatively impact our ability to operate during the Chapter 11 case and could prevent our emergence from Chapter 11.

As a result of the Chapter 11 filing, the liquidation of liabilities are subject to uncertainty. While operating as a debtor-in-possession under the protection of the Bankruptcy Code, and while subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in the consolidated financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in the consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

In October 2003, we were authorized to complete the sale of Expanets’ assets. On November 25, 2003, Expanets closed on an Asset Purchase and Sale Agreement to sell substantially all the assets and business of Expanets to Avaya, Inc. (Avaya) and retained certain specified liabilities. Thereafter, Expanets was renamed Netexit, Inc. (Netexit), which will continue as a non-operating company until it affairs can be wound down in accordance with its lending agreements, its corporate charter and provisions of Delaware law. Under the terms of the agreement, a $4 million “break-up fee” was paid to a third party originally involved in the transaction and Avaya paid Netexit cash of approximately $50.8 million, and assumed debt of approximately $38.1 million. In addition, Avaya deposited approximately $13.5 million and $1.0 million into escrow accounts to satisfy certain specified liabilities that were not assumed by Avaya, and certain indemnification obligations of Netexit, respectively. Avaya also reduced cash paid at closing by approximately $44.6 million as a working capital adjustment, pending the determination of a final closing balance sheet. On February 24, 2004, Avaya submitted its proposed final calculation of the working capital adjustment asserting that there was a working capital shortfall at Expanets of approximately $48.8 million at closing, and claiming that Avaya should retain the entire holdback amount plus an additional $4.2 million. Netexit disputes this calculation and believes that pursuant to the terms of the asset purchase agreement Netexit is owed additional cash ranging from $10 million to $20 million (resulting in potential net cash proceeds to Netexit of $60.8 million to $70.8 million). The dispute over the working capital adjustment is subject to an arbitration process, which is expected to be decided in May 2004. Pending resolution of the final balance sheet, the determination of the expenses that Netexit must pay in connection with the sale, and the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit. If Netexit cannot wind-down its affairs in an orderly manner pursuant to applicable provisions of Delaware law, it may be forced to file bankruptcy. We have recognized an estimated loss on disposal of approximately $49.3 million based on the terms of the sale and our expectation of the additional amount to be received from Avaya. An additional loss may arise based on the results of the arbitration process and other claims discussed above.

Blue Dot sold 48 businesses during 2003, repaid its credit facility from sales proceeds and terminated the facility. As of December 31, 2003, Blue Dot had 14 remaining businesses. (Subsequent to December 31, 2003, Blue Dot has sold 6 additional businesses as of March 1, 2004.) Blue Dot anticipates selling substantially all of its remaining businesses by June 30, 2004. We hope to receive in excess of $15 million in cash from Blue Dot during the liquidation of the operations; provided however, this assumes satisfactory resolutions to remaining stock obligations, potential or pending litigation, insurance and bonding reserves, and no new material additional claims or litigation. Furthermore, it assumes that the remaining businesses produce their projected cash proceeds and receivables from various sold locations are collectible.

We are also attempting to sell the Montana First Megawatts generation project. In an effort to facilitate the timely sale of the Montana First Megawatts project and its ultimate development at its current location in Great Falls, Montana, we filed the power sales agreement with the FERC on August 18, 2003, requesting that the FERC accept for filing the cost-based power sales agreement between Montana Megawatts I, LLC and its affiliate, NorthWestern Energy. A late motion to intervene and protest was filed by the MPSC and the MCC. On October 17, 2003, the FERC issued an order conditionally accepting the power sales agreement, subject to suspension for a designated period, to permit resolution of certain concerns voiced by the MPSC and MCC in their filing. We are currently working with the MPSC, MCC, FERC staff and the FERC-appointed settlement judge to resolve the documented MPSC and MCC concerns in a timely manner.

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, qualifying facilities liabilities, impairment of long-lived assets and revenue recognition, among others. Actual results could differ from those estimates.

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

Goodwill

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 (October 1) and more frequently when indications of impairment exist. Accounting standards require that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, we compare the implied fair value of the reporting unit’s goodwill with its carrying value.

Qualifying Facilities Liability

Certain Qualifying Facilities, or QFs, require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. As of December 31, 2003, our gross contractual obligation related to the QFs is approximately $1.8 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable though rates authorized by the MPSC, totaling approximately $1.4 billion though 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 Measures. 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. In computing the liability, we have also had to make various estimates in relation to contract costs, capacity utilization, and recoverable amounts. Actual utilization and regulatory changes may significantly impact our results of operations. In light of the executory nature of the QF power sales agreements and certain out-of-market pricing and escalation terms, we are evaluating our options with respect to continued purchases under these contracts.

Long-lived Assets

We evaluate our property, plant and equipment 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, then 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.

During the second quarter of 2003, we recorded an additional impairment charge of $12.4 million due to further decline in the estimated realizable value of our investment in our Montana First Megawatts project. We had previously recorded an impairment charge of $35.7 million during the fourth quarter of 2002.

Revenue Recognition

Revenues are recognized differently depending on the various jurisdictions. For our 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 our 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.

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, including our estimate of amounts recoverable for natural gas and default electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. If any part of our operations become no longer subject to the provisions of SFAS No. 71, 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.

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

Pension and Postretirement Benefit Plans

Our reported costs of providing pension and other postretirement benefits 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 pension and other postretirement benefit costs. Pension and 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.

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

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.

RESULTS OF OPERATIONS

The following is a summary of our results of operations in 2003, 2002 and 2001. 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. The results of operations for the year ended December 31, 2002, include the results of our Montana operations since February 1, 2002, the effective date of the acquisition.

Overall Consolidated Results

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Consolidated losses on common stock in 2003 were $128.7 million compared to $892.9 million in 2002. This decrease is primarily due to impairment and other charges of $878.5 million and decreased losses after impairment and other charges from our discontinued communications segment of approximately $32.0 million. This was offset by a $31.0 million increase in operating expenses, primarily due to increased legal and other professional fees related to our reorganization efforts and bankruptcy filing along with a $49.6 million increase in interest expense.

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Consolidated losses on common stock in 2002 were $892.9 million compared to earnings on common stock of $37.5 million in 2001. The loss is primarily due to impairment and other charges of $878.5 million and increased interest expense of $70.3 million, offset

by an approximately $29.3 million increase in earnings related to the addition of our Montana operations.

Electric Utility Segment Operations.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Revenues in 2003 were $673.1 million, an increase of $139.1 million, or 26.1%, from 2002 results. The January 2003 results of our Montana operations contributed approximately $47.8 million of this increase. In addition, revenues from February through December 2003, as compared to the same period in 2002, increased approximately $91.3 million, primarily due to an $80.2 million increase in revenue recovered for purchased power supply costs. As these costs are also reflected in cost of sales, there is no gross margin impact. Also contributing to the increase was $10.8 million due to a 3.8% increase in retail volumes and the addition of Montana customers that moved back to retail from customer choice. In addition, wholesale revenues increased $1.8 million due to a 0.7% increase in wholesale volumes and a 43.1% increase in average wholesale price from our South Dakota operations. A $1.4 million decrease in other revenue primarily due to Montana choice customers moving back to retail partially offset these increases.

Cost of sales in 2003 was $312.8 million, an increase of $107.1 million, or 52.1%, from 2002 results. The January 2003 results of our Montana operations contributed approximately $23.9 million of this increase. Purchased power supply costs, which are recovered in rates, increased for February through December 2003, as compared to 2002, by $80.2 million as a result of new power supply agreements effective July 1, 2002. In addition, retail and wholesale costs increased $2.2 million due to the increased volumes discussed above.

Gross margin in 2003 was $360.3 million, an increase of $32.0 million, or 9.7%, over the 2002 gross margin of $328.3 million. The January 2003 results of our Montana operations contributed $23.9 million of this increase. Higher retail and wholesale volume sales and higher average wholesale price resulted in an increase of $8.0 million, or 2.5%, for the period of February through December of 2003 as compared to 2002. Margins as a percentage of revenues decreased to 53.5% for 2003, from 61.5% for 2002. Gross margin as a percentage of revenue is impacted by the fluctuations that occur in power supply costs, which are collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they have no actual impact on gross margin amounts.

Operating, general and administrative expenses for 2003 were $184.5 million, an increase of $14.8 million, or 8.7%, over 2002. The January 2003 results of our Montana operations contributed approximately $12.2 million of this increase. The additional increase of $2.6 million was primarily due to higher property taxes and increased employee benefit costs, partially offset by a reduction in our environmental reserve. Depreciation for 2003 was $54.5 million, an increase of $5.6 million over 2002. The January 2003 results of our Montana operations contributed approximately $3.7 million of this increase.

Operating income in 2003 was $121.4 million, an increase of $11.7 million, or 10.6%, from 2002. The January 2003 results of our Montana operations contributed approximately $8.1 million of this increase. The remaining increase was primarily attributable to the increased margins discussed above.

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Revenues in 2002 were $533.9 million, an increase of $426.9 million, or 399.0%, from 2001 results. This increase was almost exclusively attributable to the addition of our Montana operations, effective February 1, 2002, which contributed $441.4 million of revenues for the year. The volume of wholesale and retail megawatt hours sold in 2002 for our Montana operations were 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%.

Cost of sales 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 our 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.

Gross margin in 2002 was $328.3 million, an increase of $244.4 million, or 291.1%, over the 2001 gross margin of $83.9 million. This increase was primarily due to the contribution of $259.4 million in gross margin from our 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 61.5%, 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 lower margin Montana operations as compared to our South Dakota operations.

Operating, general and administrative expenses were $169.7 million in 2002, an increase of $142.0 million, or 512.0%, over the

2001 results. This increase was nearly all due to the addition of our Montana operations. Depreciation for 2002 was $48.9 million, an increase of $35.7 million primarily due to the addition of our Montana operations.

Operating income in 2002 was $109.7 million, an increase of $70.0 million, or 176.4%, over 2001. The increase was attributable to the addition of approximately $81.8 million in operating income from our Montana operations, while the South Dakota operations experienced a decrease of $11.8 million in operating income, primarily from the absence of unusually high margin wholesale electric sales in 2002.

Natural Gas Utility Segment Operations

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Revenues in 2003 were $344.8 million, an increase of $105.0 million, or 43.8%, from 2002 results. The January 2003 results of our Montana operations contributed approximately $20.4 million of this increase. Revenues for February through December 2003, as compared to the same period in 2002, increased $84.6 million due in part to a $25.3 million increase in gas supply costs. As these costs are also reflected in cost of sales, there is no gross margin impact. Also contributing to this increase was a $59.9 million increase in wholesale and retail revenues. Wholesale revenues increased due to a 10% increase in volumes resulting from the addition of ethanol plant customers and a 43.4% increase in gas prices in Nebraska. Retail revenues increased as a result of sales to other utilities, partially offset by a 1% decrease in volumes. As the revenue from sales to other utilities benefits our general business customers, these sales are also included in cost of sales, thereby having no impact on gross margin.

Cost of sales in 2003 was $235.0 million, an increase of $101.9 million, or 76.5%, from 2002 results. The January 2003 results of our Montana operations contributed approximately $9.5 million of this increase. Cost of sales for February through December 2003, as compared to the same period in 2002, increased $92.4 million. Gas supply costs increased $33.3 million, including a $6.2 million write-off of supply costs as a result of a July 3, 2003, interim order from the MPSC disallowing the recovery of certain gas supply costs. The MPSC also rejected a motion for reconsideration filed by us on July 14, 2003. We filed suit in Montana state court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. Assuming our average forecast price over the next six months occurs, the disallowance on the volumes at the imputed price compared to market price would be approximately $2.8 million for the period July 1, 2003, through June 30, 2004. In addition, wholesale and retail costs increased $59.1 million due to the increased wholesale volumes and the higher retail sales for resale discussed above.

Gross margins for 2003 were $109.7 million, or $3.1 million higher as compared to 2002. The January 2003 results of our Montana operations contributed approximately $10.9 million of this increase. Margins for February through December 2003, as compared to the same period in 2002, decreased $7.8 million primarily due to the MPSC’s disallowance of $6.2 million in gas supply costs. Margins as a percentage of revenues decreased to 31.8% for 2003 from 44.5% for 2002. Gross margin as a percentage of revenue is impacted by the fluctuations that occur in retail costs, which are collected from customers through rates.

Operating, general and administrative expenses for 2003 were $72.7 million, an increase of $12.5 million, or 20.7%, from results in 2002. The January 2003 results of our Montana operations contributed approximately $3.5 million of this increase. The remaining increase was primarily due to an increase in our environmental reserve based on the results of a third-party evaluation. Depreciation expense increased $1.5 million over depreciation for 2002. The January 2003 results of our Montana operations contributed approximately $1.0 million of this increase.

Operating income in 2003 was $23.0 million, compared to income of $33.9 million in the same period 2002. The January 2003 results of our Montana operations contributed an increase of approximately $6.4 million, which was offset by the MPSC’s disallowance of $6.2 million in gas supply costs and an increase to our environmental reserve.

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Revenues in 2002 were $239.8 million, an increase of $95.6 million, or 66.3%, from 2001 results. Revenues for the period reflect the inclusion of our Montana operations, which contributed $119.6 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.

Cost of sales 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 our 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 weather in 2002 than in 2001.

Gross margin in 2002 was $106.7 million, an increase of $81.5 million, or 324.1%, over the 2001 gross margin of $25.2 million. This increase was nearly all due to the contribution of $80.7 million in gross margin by our Montana operations. In addition, our South Dakota operations experienced a $0.8 million increase in margins due to increased volumes in the nonregulated gas segment. Overall gross margin as a percentage of revenues in 2002 was 44.5%, 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.

Operating, general and administrative expenses in 2002 were $60.2 million, an increase of $45.7 million, or 314.0%, over 2001 results primarily due to the addition of our Montana operations. 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 our Montana operations.

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 our Montana operations, which contributed $30 million in operating income, while operating income from the South Dakota operations declined by $2.3 million.

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 unregulated businesses offering a portfolio of services to residential and business customers, including product sales and maintenance contracts in areas such as home monitoring devices and appliances.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Revenues for the segment in 2003 were $9.6 million compared to $10.0 million in 2002. Cost of sales in 2003 was $2.8 million, which was consistent with 2002. Gross margin in 2003 was $6.8 million compared to $7.2 million in 2002.

Operating expenses in 2003 were $72.5 million, a decrease of $3.3 million, or 4.4%, from 2002. The decrease was primarily due to lower asset impairment charges of $23.3 million with respect to the investment in the Montana First Megawatts project offset by an increase in legal and professional fees of approximately $11.7 million and reorganization expenses of $8.3 million.

Operating losses in 2003 were $65.7 million, a decrease of $2.9 million, or 4.2%, from 2002. The change was primarily due to the changes in operating expenses discussed above.

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

Revenues for the segment in 2002 were $10.0 million compared to $3.9 million in 2001. Cost of sales in 2002 was $2.8 million, a decrease of $0.7 million from 2001. Gross margin in 2002 was $7.2 million compared to $0.5 million in 2001. The increase in revenues and gross margin is due to the addition of the unregulated portions of our Montana operations.

Operating expenses in 2002 were $75.8 million, an increase of $47.3 million from 2001. The increase was primarily due to a $35.7 million asset impairment charge related to the investment in the Montana First Megawatts project, increased expenses related to employee benefit plans, and additional operating expenses due to the addition of our Montana operations, offset by a restructuring charge in 2001.

Operating losses in 2002 were $68.6 million, an increase of $40.6 million from 2001. The increase was primarily due to the previously mentioned asset impairment charges.

Discontinued Communications Segment Operations

In addition, Avaya deposited approximately $13.5 million and $1.0 million into escrow accounts to satisfy certain specified liabilities that were not assumed by Avaya, and certain indemnification obligations of Netexit, respectively. Avaya also reduced cash paid at closing by approximately $44.6 million as a working capital adjustment, pending the determination of a final closing balance sheet. On February 24, 2004, Avaya submitted its proposed final calculation of the working capital adjustment asserting that there was a working capital shortfall at Expanets of approximately $48.8 million at closing, and claiming that Avaya should retain the entire holdback amount plus an additional $4.2 million. Netexit disputes this calculation and believes that pursuant to the terms of the asset purchase agreement Netexit is owed additional cash ranging from $10 million to $20 million (resulting in potential net cash proceeds to Netexit of $60.8 million to $70.8 million). The dispute over the working capital adjustment is subject to an arbitration process, which is expected to be decided in May 2004. Pending resolution of the final balance sheet, the determination of the expenses that Netexit must pay in connection with the sale, and the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit. If Netexit cannot wind-down its affairs in an orderly manner pursuant to applicable provisions of Delaware law, it may be forced to file bankruptcy. We have recognized an estimated loss on disposal of approximately $49.3 million based on the terms of the sale and our expectation of the amount to be received from Avaya. An additional loss may arise based on the results of the arbitration process discussed above.

Summary financial information for the discontinued Expanets operations is as follows (in thousands):

	2003			2002			2001
Revenues	$	541,211		$	710,452		$	1,032,033

Income (Loss) before income taxes and minority interests	$	1,360		$	(422,802	)	$	(119,198	)
Estimated loss on disposal	(49,250		)	—			—
Minority interests	—			11,152			127,893
Income tax benefit (provision)	—			(22,780		)	32,190
Loss from discontinued operations, net of income taxes and minority interests	$	(47,890	)	$	(434,430	)	$	40,885

Expanets’ income before income taxes and minority interests for the year ended December 31, 2003, includes a gain on debt extinguishment of $27.3 million.

Discontinued HVAC Segment Operations

Blue Dot sold 48 businesses during 2003, repaid its credit facility from sales proceeds and terminated the facility. As of December 31, 2003, Blue Dot has 14 remaining businesses. (Subsequent to December 31, 2003, Blue Dot has sold 6 additional businesses as of March 1, 2004.) Blue Dot anticipates selling substantially all of its remaining businesses by June 30, 2004. We hope to receive in excess of $15 million in cash from Blue Dot during the liquidation of the operations; provided however, this assumes satisfactory resolutions to remaining stock obligations, potential or pending litigation, insurance and bonding reserves, and no new material additional claims or litigation. Furthermore, it assumes that the remaining businesses produce their projected cash proceeds and receivables from various sold locations are collectible.

Summary financial information for the discontinued Blue Dot operations is as follows (in thousands):

	2003			2002			2001
Revenues	$	400,679		$	471,824		$	423,803

Income (Loss) before income taxes and minority interests	$	(3,356	)	$	(311,674	)	$	(17,392	)
Gain on disposal	14,352			—			—
Minority interests	—			3,762			13,555
Income tax benefit (provision)	—			(9,071		)	3,830
Income (Loss) from discontinued operations, net of income taxes	$	10,996		$	(316,983	)	$	(7	)

LIQUIDITY AND CAPITAL RESOURCES

Our financial condition has been significantly and negatively affected by the poor performance of our nonenergy businesses and our significant indebtedness.

September 12, 2004, and bears interest at a variable rate tied to the Eurodollar rate plus a spread of 3.00% or at the prime rate plus a spread of 1.00%. The DIP Facility requires that we maintain certain other financial covenants and restricts liens, indebtedness, capital expenditures, dividend payments and sales of assets. As of December 31, 2003, we had $15.2 million in letters of credit outstanding and no borrowings under the DIP Facility.

We reached an agreement with the lenders holding claims under our senior credit facility agented by CSFB in October 2003 to reduce the interest rate of our $390 million prepetition credit facility. In January 2004, the Bankruptcy Court entered a final order authorizing the amendment of the credit facility and granting protection in connection therewith. The amended credit facility provides advantages to NorthWestern, including lower interest expense and allowing reinstatement upon NorthWestern’s emergence from Chapter 11. At NorthWestern’s option, the amended credit facility bears interest at a variable rate tied to the Eurodollar rate, plus a spread of 5.50%, or at an alternate base rate, as defined by the amended credit facility, plus a spread of 3.50%. There is no longer a minimum floor for the Eurodollar rate or the alternate base rate. As a result of this amendment, we estimate annualized interest expense will be reduced by approximately $6 million to $8 million.

Cash Flows

Cash used in continuing operations totaled $105.7 million during 2003, compared to cash provided of $125.6 million in 2002 and $16.4 million in 2001. Cash flows from operations decreased significantly during 2003, primarily due to our deteriorating financial condition, reduced vendor credit terms (including requirement of deposits), increased legal and professional fees, and increased interest expense. As a result of our bankruptcy filing, we anticipate our cash flows from operations will improve during 2004, primarily due to our inability to pay interest on unsecured debt. Cash provided by continuing operations increased during 2002, compared with 2001, primarily due to the addition of our Montana operations.

Cash provided by investing activities totaled $4.9 million during 2003, compared to cash used of $641.1 million in 2002 and $80.7 million in 2001. Cash provided in 2003 was primarily due to proceeds from investment sales offset by property additions. Cash used in 2002 was principally due to the acquisition of our Montana operations, which accounted for approximately $502.8 million. Cash used in 2001 was almost entirely due to property, plant and equipment additions.

Cash provided by financing activities totaled $77.6 million during 2003, compared to $732.6 million in 2002 and $200.2 million in 2001. During 2003 we received proceeds of $390.0 million under a new senior secured term loan, which was used to repay $255.0 million on our credit facility. During 2002, we received proceeds of $720.0 million from the issuance of senior notes, which was used to acquire our Montana operations and repay existing debt. During 2001, we received proceeds of $74.9 million and $100.0 million from the issuance of common stock and trust preferred securities, respectively.

Capital Requirements

Our capital expenditures program is subject to continuing review and modification. Actual utility construction expenditures may vary from estimates due to changes in electric and natural gas projected load growth, changing business operating conditions and other business factors. We anticipate funding capital expenditures through cash flows from operations and available credit sources. Our estimated cost of capital expenditures for the next five years is as follows (in thousands):

Year	Amount
2004	$	77,000
2005	71,000
2006	71,500
2007	72,000
2008	72,500

Contractual Obligations and Other Commitments

NorthWestern has a variety of contractual obligations and other commercial commitments that represent prospective requirements in addition to expense. The following table shows our contractual cash obligations and commercial commitments as of December 31, 2003, without regard to the reclassification of long-term debt to current. See additional discussion in Note 9 to the Consolidated Financial Statements.

	Total			2004		2005		2006		2007			2008			Thereafter
	(in thousands)
Debt Not Subject to Compromise:
Senior Secured Term Loan(1)	$	386,100		$	3,900	$	3,900	$	378,300	$	—	$		—	$		—
South Dakota Mortgage Bonds, 7.00% and 7.10%	115,000			—		60,000		—		—		—			55,000
South Dakota Pollution Control Obligations, 5.85% and 5.90%	21,350			—		—		—		—		—			21,350
Montana First Mortgage Bonds, 7.00%, 7.30%, 8.25% and 8.95%	157,197			—		5,386		150,000		365		—			1,446
Discount on Montana First Mortgage Bonds	(3,483		)	—		—		—		—		—			(3,483			)
Montana Pollution Control Obligations, 6.125% and 5.90%	170,205			—		—		—		—		—			170,205
Montana Secured Medium Term Notes, 7.25%	13,000			—		—		—		—		13,000			—
Montana Natural Gas Transition Bonds, 6.20%	46,502			4,052		4,744		4,712		5,248		5,391			22,355
Other debt, various	1,122			320		343		221		238		—			—
Capital leases(2)	12,399			3,371		2,146		1,798		1,194		738			3,152

Total Debt Not Subject to Compromise	919,392			11,643		76,519		535,031		7,045		19,129			270,025
Debt Subject to Compromise:
Senior Unsecured Notes, 7.875% and 8.75%	720,000			—		—		—		250,000		—			470,000
Senior Unsecured Debt, 6.95%	105,000			—		—		—		—		—			105,000
Montana Unsecured Medium Term Notes, 7.07%, 7.96% and 7.875%	40,000			—		—		15,000		—		—			25,000
Discount on Montana Unsecured Medium Term Notes	(156		)	—		—		—		—		—			(156			)
Total Debt Subject to Compromise	864,844			—		—		15,000		250,000		—			599,844

Total Mandatorily Redeemable Preferred Securities of Subsidiary Trusts	365,550			—		—		—		—		—			365,550
Future minimum operating lease payments(3)	227,562			33,133		32,849		32,572		32,288		32,268			64,452
Estimated Pension and Other Postretirement Obligations(4)	116,000			16,000		25,000		25,000		25,000		25,000			N/A
Qualifying Facilities(5)	1,818,673			54,823		56,579		58,468		60,634		62,931			1,525,238
Power Purchase Contracts(6)	1,235,826			250,983		227,693		164,953		98,383		45,333			448,481
Interest payments on existing secured debt	439,327			61,440		58,613		52,557		18,646		17,418			230,653
Total Commitments	$	5,987,174		$	428,022	$	477,253	$	883,581	$	491,996	$		202,079	$		3,504,243

(1) This facility was used to repay our $280 million credit facility on February 10, 2003.

(2) The capital lease obligations are principally used to finance equipment purchases.

(3) While not included on this schedule, NorthWestern has a residual value guarantee related to certain vehicles under operating leases by Blue Dot in the event of default and subsequent failure to cure such default. At December 31, 2003, the amount of this financial guarantee was approximately $5.2 million. In connection with the various sales of Blue Dot businesses, the vehicle lessor has agreed to terminate the NorthWestern guarantee of Blue Dot’s performance under the vehicle leases.

(4) We have only estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter.

(5) 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 estimated gross contractual obligation related to the QFs is approximately $1.8 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.4 billion. The obligation and payments reflected on this schedule represent the estimated gross contractual obligation.

(6) We have entered into various purchase commitments, largely purchased power, coal and natural gas supply, electric generation construction and natural gas transportation contracts. These commitments range from one to 30 years.

Performance Bonds and Letters of Credit

We have various letter of credit requirements and other collateral obligations of approximately $16.4 million and $48.1 million as of December 31, 2003 and 2002, respectively.

Blue Dot and Expanets have obtained various license, bid and performance bonds in place to secure the performance of contracts and the adequate provision of services. The total amount of outstanding surety bonds obtained by Blue Dot and Expanets is approximately $59.5 million as of December 31, 2003. Due to completion of work and as a result of the sale of Expanets and certain Blue Dot businesses, we estimate the amount of the underlying obligations that such bonds secure is $3.5 million and $14.3 million as of December 31, 2003 and 2002, respectively.

The surety bonds obtained by Blue Dot and Expanets are supported by indemnity agreements that we entered into for the benefit of Blue Dot and Expanets and are secured by various letters of credit obtained by Blue Dot, Expanets or us. Approximately $10 million and $18.6 million of these letter of credit and other collateral obligations as of December 31, 2003 and 2002, respectively, serve to support performance bonds primarily related to Blue Dot and Expanets. In addition, included in other assets at December 31, 2003, is $7.1 million of deposits that support performance bonds related to Blue Dot and Expanets. No such amounts existed at December 31, 2002.

Defined Benefit Pension and Postretirement Benefit Plans.

With the acquisition of our Montana operations, our pension and other postretirement benefit obligations significantly increased. Our reported costs of providing pension and other postretirement benefits, as described in Note 15 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 are impacted by actual employee demographics, including age and compensation levels, the level of contributions we make to the plan, earnings on plan assets, and health care cost trends. Changes made to the provisions of such plans may also impact current and future benefit costs. 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.

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

At December 31, 2003, our accumulated benefit obligation exceeded plan assets by approximately $116.2 million for our pension plans. In addition, our projected benefit obligation for other postretirement benefit plans exceeded plan assets by $61.5 million. Additional contributions may be required in the near future to meet the requirements of the plan to pay benefits to plan participants. To the extent such additional contributions are reflected in the ratemaking process to determine the rates billed to customers, such amounts will be treated as regulatory assets. For the years ended December 31, 2003 and 2002, contributions to our pension and other postretirement benefit plans were $46.8 million and $7.4 million. No contributions were made during 2001. The increase in contributions for fiscal 2003 was the result of the acquisition of our Montana operations and the excess of our accumulated benefit obligations over plan assets.

Capital Sources

During 2003 and 2002, we raised cash proceeds from the following offerings of our securities and new debt facilities.

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 costs and fees, were used to repay $259.6 million outstanding under the existing $280.0 million bank credit facility and existing outstanding letters-of-credit. The remaining proceeds of the term loan were used to fund working capital and other general corporate purposes.

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.

On March 13, 2002, we issued $250 million of our 7.875% senior notes due March 15, 2007, and $470 million of our 8.75% 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 Noncurrent 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 February 15, 2002, in connection with the 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 $720.0 million term loan and drew down a $19.0 million swing line commitment under our $280.0 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, 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 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.

NEW ACCOUNTING STANDARDS

See Note 4 of “Notes to Consolidated Financial Statements,” included in Item 8 herein for a discussion of new accounting standards.

RISK FACTORS

You should carefully consider the risk factors described below, as well as other information included in this Annual Report on Form 10-K, before making an investment in our common stock or other securities. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties not presently known or that we currently believe to be less significant may also adversely affect us.

Bankruptcy Related Risks

Our Plan of Reorganization may not be confirmed by the Bankruptcy Court and may not be successfully consummated.

Our future results are dependent upon successfully obtaining approval, confirmation and implementation of our plan of reorganization. There can be no assurance that our plan of reorganization will be confirmed by the Bankruptcy Court. Section 1129 of Chapter 11 requires, among other things, a showing that confirmation of the plan will not be followed by liquidation or the need for further financial reorganization, and that the value of distributions to dissenting holders of claims and interests may not be less than the value such holders would receive if the Company were liquidated under Chapter 7 of the United States Bankruptcy Code. There can be no assurance that the Bankruptcy Court will conclude the plan satisfies the requirements of Section 1129. Conversely, the Bankruptcy Court may confirm a plan even though it was not accepted by one or more impaired classes of creditors, if certain requirements of Chapter 11 are met. Currently, it is not possible to predict with certainty the length of time we will operate under the protection of Chapter 11, the outcome of the Chapter 11 proceedings in general, or the effect of the proceedings on our business or on the interests of the various creditors and stakeholders.

In January 2004, the Bankruptcy Court extended our exclusive period to file a plan of reorganization through and including March 12, 2004, and extended the time to solicit votes on our plan of reorganization through and including May 11, 2004. We filed our initial plan of reorganization on March 12, 2004. Even if the Bankruptcy Court confirms our plan, consummation of the plan will likely be dependent upon a number of other conditions. There can be no assurance that any or all of the conditions in the plan will be met (or waived) or that the other conditions to consummation of the plan, if any, will be satisfied. Accordingly, we can provide no assurances that the plan will be consummated and the restructuring completed. If a plan is not timely consummated, it could result in our Chapter 11 proceedings becoming protracted or being converted into Chapter 7 liquidation proceedings, either of which could substantially erode the value of our enterprise to the detriment of all stakeholders.

The Creditors’ Committee and other parties in interest may not support our positions in the Chapter 11 proceedings.

The Creditors’ Committee appointed in the bankruptcy proceedings has the right to be heard on all matters that come before the Bankruptcy Court. We are also subject to regulation by FERC and the state public service or utility commissions in the states we serve. There can be no assurance that the Creditors’ Committee, our equity holders other parties in interest or our primary regulators will support our positions in the bankruptcy proceeding or the plan of reorganization once proposed, and disagreements between us and such entities could protract the bankruptcy proceedings, could negatively impact our ability to operate during bankruptcy, and could delay our emergence from bankruptcy.

Our Chapter 11 proceedings may result in a negative public perception of us that may adversely affect our relationships with customers and suppliers, as well as our business, results of operations and financial condition.

Even if we submit a plan of reorganization that is confirmed by the Bankruptcy Court and consummated by us, our Chapter 11 filing and the resulting uncertainty regarding our future prospects may hinder our ongoing business activities and its ability to operate, fund and execute our business plan by (i) impairing relations with existing and potential customers; (ii) negatively impacting our ability to attract, retain and compensate key executives and associates and to retain employees generally; (iii) limiting our ability to obtain trade credit; and (iv) impairing present and future relationships with vendors and service providers.

Holders of certain claims and interests will receive no distributions under our proposed Plan of Reorganization.

Under Chapter 11, the rights and treatment of prepetition creditors and equity security holders may be substantially altered. At this time, it is not certain what effect the Chapter 11 proceedings will have on our creditors and common shareholders. Under the priority rules established by Chapter 11, certain postpetition liabilities and prepetition liabilities need to be satisfied before shareholders are entitled to receive any distribution. The ultimate recovery to our creditors and common shareholders, if any, will not be determined until confirmation of a plan of reorganization. No assurance can be given as to what values, if any, ultimately will be ascribed in the Chapter 11 proceedings to each of these constituencies. Under any plan of reorganization in the Chapter 11 proceedings, management of NorthWestern expects that unsecured claims against us will be satisfied at a fraction of their face value, and that there will be no value available for distribution to our common shareholders. Because of this, any investment in our common stock is highly speculative. Accordingly, we urge that appropriate caution be exercised with respect to existing and future investments in any of our equity or debt securities.

We have incurred, and expect to continue to incur, significant costs associated with the Chapter 11 proceedings.

We have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to have a significant adverse affect on the results of operations and cash flows.

We must replace our debtor-in-possession credit facility (DIP Facility) in order to emerge from bankruptcy and continue normal operations.

Our DIP Facility is intended to provide us with financing during our reorganization. We will need a replacement financing, known as an exit facility, to provide financing following our recapitalization. We may use our DIP Facility to provide the cash for our daily operations and to finance our capital expenditures. If we do not obtain a replacement facility in a timely fashion, then we may not be able to implement our recapitalization.

Our ability to raise capital and the liquidity of our stock may be adversely affected by the fact that our shares are not listed on the New York Stock Exchange or another major exchange.

On September 15, 2003, in connection with our Chapter 11 filing the NYSE suspended trading on our common stock and all series of our trust preferred securities. On October 10, 2003, the SEC issued an order granting the application of the NYSE to delist our common stock and trust preferred securities. Our common shares are now quoted on Nasdaq’s OTC Bulletin Board. The fact that our common stock and all series of our trust preferred securities are not listed on the NYSE or any other major exchange could reduce the

liquidity of such securities and make it more difficult for a shareholder to obtain accurate quotations as to the market price of such securities. Reduced liquidity of our common stock and all series of our trust preferred securities also may reduce our ability to access the capital markets in the future. In addition, under our proposed plan of reorganization in the Chapter 11 proceedings, our existing equity securities will be cancelled and we will issue new equity securities to certain of our creditors upon our emergence from Chapter 11 in full or partial satisfaction of creditor claims. There can be no assurance that any of our new equity securities issued under the plan of reorganization will be listed on any major exchange.

Our ability to continue as a going concern is dependent on a number of factors.

The accompanying financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of the bankruptcy filing and related events, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. In addition, a plan of reorganization, or rejection thereof, could change the amounts reported in the financial statements. As a result, there is substantial doubt about our ability to continue as a going concern. Our liquidity generally depends on cash provided by operating activities and access to the DIP Facility. Our ability to continue as a going concern (including our ability to meet postpetition obligations) and the continued appropriateness of using the going concern basis for our financial statements are dependent upon, among other things, (i) our ability to comply with the covenants of the DIP Facility, (ii) our ability to maintain adequate cash on hand, (iii) our ability to continue to generate cash from operations, (iv) confirmation of a plan of reorganization under the Bankruptcy Code and the terms of such plan, (v) our ability to attract, retain and compensate key executives and associates and to retain employees generally, and (vi) our ability to achieve profitability following such confirmation.

Our Chapter 11 filings triggered defaults, or termination events, on substantially all of our debt and lease obligations, and certain contractual obligations.

At December 31, 2003, we had a significant common shareholders’ deficit and currently have approximately $2.2 billion in debt and trust preferred instruments outstanding. After failing to implement an out-of-court turnaround plan, we filed a petition with the Bankruptcy Court in order to reorganize our capital and debt structure under Chapter 11 of the Bankruptcy Code. The Chapter 11 filing triggered defaults, or termination events, on substantially all of our debt and lease obligations, and certain contractual obligations. However, under Chapter 11, actions by creditors to collect claims on prepetition debt are stayed or deferred unless specifically ordered by the Bankruptcy Court.

We may, under certain circumstances, file motions with the Bankruptcy Court to assume or reject our executory contracts. An executory contract is one in which the parties have mutual obligations to perform (e.g., contracts of affreightment, charters, equipment leases and real property leases). Unless otherwise agreed, the assumption of a contract will require that we cure all prior defaults under the related contract, including all prepetition liabilities. Unless otherwise agreed, the rejection of a contract is deemed to constitute a breach of the agreement as of the moment immediately preceding the Chapter 11 filing, giving the other party to the contract a right to assert a general unsecured claim for damages arising out of the breach. Additional liabilities subject to the proceedings may arise in the future as a result of the rejection of executory contracts, including leases, and from the determination of the Bankruptcy Court (or agreement by parties in interest) of allowed claims for contingencies and other disputed amounts. Conversely, the assumption of executory contracts and unexpired leases may convert liabilities shown as subject to compromise to postpetition liabilities. Due to the uncertain nature of many of the potential claims, we are unable to project the magnitude of such claims with any degree of certainty.

If we are unable to successfully sell our noncore assets, then the amount of proceeds we receive from such sales could be significantly less than anticipated and adversely affect our liquidity.

As part of our efforts to restructure our business, we are attempting to divest certain noncore assets, including Expanets, Blue Dot and our Montana First Megawatts generation project in Montana. If the sales price for such assets is less than anticipated, or we encounter unexpected liabilities in connection with such sales, such as an unfavorable resolution of our purchase price dispute with Avaya regarding the sale of Expanets or costs relating to the wind-down of such operations, including termination of benefit plans and payment of other liabilities, our liquidity could be adversely affected. Further, we cannot assure you that we will be able to consummate such asset sales or that any asset sales will be at or greater than the current net book value of such assets.

Company Specific Risks

We are one of several defendants in a class action lawsuit brought in connection with the sale of generating and energy-related assets by The Montana Power Company. If we do not successfully resolve this lawsuit, the insurance coverage does not pay for any damages we are found liable for, or our indemnification claims against TouchAmerica Holdings, Inc. cannot be enforced and reimbursed, then our business will be harmed and there will be material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al,, now pending in federal court in Montana. The lawsuit, which was filed by the former shareholders of The Montana Power Company (many of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of The Montana Power Company), claims that the disposition of various generating and energy-related assets by The Montana Power Company was void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern Corporation is named as a defendant due to the fact that we purchased Montana Power LLC, which plaintiffs claim is a successor to The Montana Power Company. We intend to vigorously defend against this lawsuit. On November 6, 2003, the Bankruptcy Court approved a stipulation between NorthWestern and the plaintiffs in McGreevey, et al. v. The Montana Power Company, et al. The stipulation provides that litigation, as against Northwestern, Clark Fork & Blackfoot LLC, the Montana Power Company, Montana Power LLC and Jack Haffey, shall be temporarily stayed for 180 days from the date of the stipulation. Pursuant to the stipulation and after providing notice to Northwestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material. If the stay is lifted, then we intend to vigorously defend against these lawsuits. In that event, we cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

We are the subject of a formal investigation by the Securities and Exchange Commission relating to the restatement of our 2002 quarterly financial statements and other accounting and financial reporting matters. If the investigation was to result in a regulatory proceeding or action against us, then our business and financial condition could be harmed.

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern, NorthWestern Communications Solutions, Expanets and Blue Dot. This action follows the SEC’s requests for information made in connection with the previously disclosed SEC informal inquiry into questions regarding the restatements and other accounting and financial reporting matters. In addition, a NorthWestern director was interviewed by a representative of the Federal Bureau of Investigation (FBI) concerning certain of the allegations made in the class action securities and derivative litigation matters. We have not been contacted by the FBI and have not been advised that NorthWestern is the target of its investigation. We are cooperating with the SEC’s investigation and intend to cooperate with the FBI if we are contacted in connection with its investigation. We understand that the FBI or the Internal Revenue Service (IRS) may have contacted former employees of ours or our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters. We cannot predict whether or not any other governmental inquiry or investigation will be commenced, nor can we predict the outcome of the SEC, FBI, IRS or any other governmental inquiry or investigation or related litigation or proceeding.

The impact of ongoing class action litigation and shareholder derivative actions may be material. We are also subject to the risk of additional litigation and regulatory action in connection with the restatement of our 2002 quarterly financial statements and the potential liability from any such litigation or regulatory action could materially harm our business and may have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

We, and certain of our present and former officers and directors, have been named in several class action lawsuits and shareholder derivative actions commenced in or removed to federal court and described in detail above. A tentative settlement has been reached in the consolidated securities class action and consolidated derivative litigation as described earlier. Among the terms of the proposed settlement, we, Expanets, Blue Dot and other parties and persons will be released from all claims relating to these cases, a settlement fund in the amount of $41 million (of which approximately $37 million will be contributed by our directors and officers liability insurance carriers, and $4 million would be contributed from other persons and parties) will be established, and, if Netexit seeks bankruptcy protection, the plaintiffs would have a $20 million liquidated securities claim against Netexit. However, that proposed settlement is subject to several conditions, such as approval by the Bankruptcy Court and the Federal District Court in South Dakota, which may or may not occur. If the proposed settlement of the consolidated class actions and derivative litigation is not consummated, then we intend to vigorously defend against these lawsuits. In that event, we cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

As a result of the restatement of our quarterly results for the first three quarters of 2002, we could become subject to additional shareholder derivative actions or other securities litigation. In addition, federal, state or local regulatory agencies, such as the FERC, state public utilities commissions, and/or the NYSE, could commence a formal investigation relating to the restatement of our quarterly results. The initiation of any additional securities litigation, together with the pending securities and shareholder derivative lawsuits described in this Annual Report, has had a material adverse affect on our business and financial condition. Until such inquiries, investigations, proceedings and litigation are resolved, it will be more difficult to raise additional capital or favorably refinance or restructure our debt or other obligations. If an unfavorable result occurred in any such action, our business and financial condition could be further harmed and there could be an adverse impact on our ability to timely confirm a plan of reorganization. In addition, we have incurred substantial expenses and are likely to incur additional substantial expenses in connection with such litigation and regulatory inquiries and investigations, including substantial fees for attorneys and other professional advisors. We may also be obligated to indemnify officers and directors named as defendants in such action. These expenses, to the extent not covered by available insurance, have and will continue to adversely affect our cash position.

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,” then we 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.

The 1997 Montana Restructuring Act, as amended, provides that certain customers be able to choose their electricity supplier during a transition period ending on June 30, 2027. NorthWestern Energy is required to act as the “default supplier” for customers who have not chosen an alternate supplier. The Restructuring Act provides for full recovery of prudently incurred costs for procuring a default supply portfolio of electric power. The default supplier was required to propose a “cost recovery mechanism” for electrical supply procurement costs before March 30, 2002. On April 25, 2002, the MPSC approved our proposed “cost recovery mechanism”. Annual filings under this mechanism will address the recovery and tracking of all future electric default supply costs.

On June 21, 2002, the MPSC issued a final order approving contracts meeting approximately 60% of the default supply winter peak load and approximately 73% of the annual energy requirements. As a result of the order, NorthWestern Energy has implemented a procurement strategy that involves supplying the remainder of the default supply portfolio through open market purchases. Currently, NorthWestern Energy is making short-term purchases to fill intermediate and peak electricity needs. These short-term purchases, along with the MPSC approved base load supply, are being fully recovered through our 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 in many respects to the cost recovery process that has been utilized in Montana, South Dakota and other states for natural gas purchases for residential and commercial customers. The MPSC further stated that NorthWestern Energy has an ongoing responsibility to prudently administer its supply contracts and the energy procured pursuant to those contracts for the benefit of ratepayers. The MPSC could, in any particular year, disallow the recovery of a portion of the default supply costs if it makes a determination that NorthWestern Energy acted imprudently with respect to implementation of its open market purchase strategy or that the approved supply contracts were not prudently administered. A failure to recover such costs could adversely affect our net income and financial condition. On July 3, 2003, the MPSC issued an order disallowing the recovery of certain gas supply costs. The MPSC also granted an interim order on July 3, 2003, for the projected gas cost adjusted for a portion of the gas portfolio at a fixed price of $3.50 per MMBTU as opposed to the market price submitted in the original filing, which was higher. Assuming our average forecast price over the next 6 months occurs, the disallowance on the volumes at the imputed price compared to market price would be approximately $4.5 million for the period July 1, 2003 through June 30, 2004.

We are subject to extensive governmental regulations that could impose significant costs or change rates of our operations and changes in existing regulations and future deregulation may have a detrimental effect on our business and could increase competition.

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

Our utility businesses are regulated by certain state commissions, including as of May 30, 2003, the Nebraska Public Service Commission, with regard to our natural gas businesses in that state. As a result, these commissions have the ability to review the regulated utility’s books and records. This ability to review our books and records could result in prospective negative adjustments to our rates.

The United States electric utility and natural gas industries are currently experiencing increasing competitive pressures as a result of consumer demands, technological advances, deregulation, greater availability of natural gas-fired generation and other factors.

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

Proposals have been introduced in Congress to repeal the Public Utility Holding Company Act of 1935, or PUHCA. To the extent regulatory barriers to entry are eliminated, competitive pressures increase, or the pricing and sale of transmission or distribution services or electricity or fuel assume more characteristics of a commodity business, we could face increased competition adverse to our business.

We may not be able to fully recover transition costs, which could adversely affect our net income and financial condition.

Montana law required the MPSC to determine the value of net unmitigable transition costs associated with the transformation of the former The Montana Power Company 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, or CTC, 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 former owner of our Montana transmission and distribution business was required to enter into with certain “qualifying facilities” (QF) as established under the Public Utility Regulatory Policies Act of 1978. The former owner estimated the pretax net present value of its transition costs over the approximate 30-year period to be approximately $304.7 million in a filing with the MPSC on October 29, 2001. On January 31, 2002, the MPSC issued an Order establishing a CTC that would recover $244.7 million on a net present value basis. As a result of this Order, we will under collect approximately $60 million on a net present value basis over the remaining terms of the QF power supply contracts. While the CTC is designed to adjust and compensate for future changes in sales volumes or other factors affecting actual cost recoveries, the CTC runs through the year 2029, and therefore, we cannot predict with certainty the actual recovery of transition costs. Changes in the recovery of transition costs could adversely affect our net income and financial condition by increasing the current under collection amount.

We are subject to risks associated with a changing economic environment.

In general, the financial markets have been weak, and the availability and cost of capital for our business and that of our competitors has been adversely affected. Events such as the bankruptcy of several large energy and telecommunications companies have specifically contributed to this weak environment. Such economic environment, if sustained, could constrain the capital available to our industry and would adversely affect our access to funding for our operations, including the funding necessary to refinance or restructure our substantial indebtedness.

Our electric and natural gas distribution systems are subject to municipal condemnation.

The government of each of the municipalities in which we provide electric or natural gas service has the right to condemn our facilities in that community and to establish a municipal utility distribution system to serve customers by use of such facilities, subject to the approval of the voters of the community and the payment to NorthWestern of fair market value for our facilities, including compensation for the cancellation of our service rights. While there are currently no proceedings pending to undertake such condemnation, a few of the communities served by NorthWestern in South Dakota and Montana have taken steps to begin evaluation of the feasibility of such actions.

Our revenues and results of operations are subject to risks that are beyond our control, including but not limited to future terrorist attacks or related acts of war.

The cost of repairing damage to our facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of reserves established for such repairs, may adversely impact our results of operations, financial condition and cash flows. Generation and transmission facilities, in general, have been identified as potential terrorist targets. The occurrence or risk of occurrence of future terrorist activity may impact our results of operations, financial condition and cash flows in unpredictable ways. These actions could also result in adverse changes in the insurance markets and disruptions of power and fuel markets. The availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. In addition, our electric transmission and distribution, electric generation, natural gas distribution and pipeline and gathering facilities could be directly or indirectly harmed by future terrorist activity.

The occurrence or risk of occurrence of future terrorist attacks or related acts of war could also adversely affect the United States economy. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and margins and limit our future growth prospects. Also, these risks could cause instability in the financial markets and adversely affect our ability to access capital.

Our operating results fluctuate on a seasonal and quarterly basis.

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

Changes in commodity prices and availability of supply 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.

Our wholesale costs for electricity and natural gas are recovered through various pass-through mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rate through our monthly tracker. To the extent our adjusted rate is deemed inappropriate by the applicable state regulatory commission, we could under recover our costs during the relevant period. While the tracker mechanisms are designed to allow a timely recovery of costs, a rapid increase in commodity costs may create a temporary, material under recovery situation. As a result, we may not be able to immediately pass on to our retail customers rapid increases in our energy supply costs, which could reduce our liquidity.

We do not own any natural gas reserves and do not own electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and all of our Montana electricity supply pursuant to contracts with third party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. Such risk is not present in our South Dakota electric operation because we own interests in generation assets that substantially cover our electric supply requirement in South Dakota.

If we are unable to obtain investment grade ratings upon exit from bankruptcy, then our working capital could be adversely affected by trade vendors reducing or eliminating customary credit terms.

In order to fulfill our obligations to supply electrical power and natural gas supply in our service territories, we enter into power and fuel purchase agreements of varying lengths. If we are unable to obtain investment grade ratings upon exit from bankruptcy, under customary contract terms, the power or fuel vendor would have the right to reduce or eliminate credit terms and/or demand credit enhancement, including the posting of letters of credit, bonds, cash deposits or requiring prepayments. If we are required to provide such credit enhancements, then our liquidity will be adversely affected.

Our utility business is subject to extensive environmental regulations and potential environmental liabilities, which could result in significant costs and liabilities.

Our utility business is subject to extensive regulations imposed by federal, state and local government authorities in the ordinary course of operations with regard to the environment, including environmental regulations relating to air and water quality, solid waste disposal and other environmental considerations. Many of these environmental laws and regulations create permit and license requirements and provide for substantial civil and criminal fines which, if imposed, could result in material costs or liabilities. We cannot predict with certainty the occurrence of a private tort allegation or government claim for damages associated with specific environmental conditions. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair and upgrade of our facilities in order to meet future requirements and obligations under environmental laws.

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for environmental remediation obligations is estimated to be $43.9 million to $82.7 million. We have an environmental reserve of $43.9 million at December 31, 2003. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from private tort actions or government claims for damages allegedly associated with specific environmental conditions. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies, our results of operations and financial condition could be adversely affected.

Certain subsidiaries may be subject to potential rescission rights held by their minority shareholders.

In connection with acquisitions in prior years, Expanets and Blue Dot issued shares of their capital stock as part of the consideration offered to owners of various companies that they acquired. None of these shares were registered under the Securities Act of 1933, as amended, in the belief that the issuance of these shares was exempt from the registration requirements of the Securities Act. It is possible that the exemptions from registration on which Expanets and Blue Dot relied were not available, and that these shares may have been issued in violation of the Securities Act. As a result, the persons who received these shares upon the sale of their companies to Expanets or Blue Dot may have the right to seek recovery from Expanets or Blue Dot damages as prescribed by applicable securities laws.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

We are exposed to the impact of market fluctuations associated with commodity prices and interest rates.

Interest Rate Risk

We use fixed and variable rate long-term debt to partially finance capital expenditures and mandatory debt retirements. These debt agreements expose us to market risk related to changes in interest rates. We manage this risk by taking advantage of market conditions when timing the placement of long-term or permanent financing. We have historically used interest rate swap agreements to manage a portion of out interest rate risk and may take advantage of such agreements in the future to minimize such risk. As of December 31, 2003, we also have outstanding mandatorily redeemable preferred securities with various fixed interest rates. All of our debt has fixed interest rates, with the exception of our senior secured term loan which bears interest at a variable rate tied to the Eurodollar rate. Effective with the amendment of this loan, the current rate is approximately 6.75%. A 1% increase in the Eurodollar rate would increase annual interest expense by approximately $3.8 million. Our new DIP Facility also bears interest at a variable rate tied to the Eurodollar rate, however, we have no outstanding borrowings as of March 12, 2004.

Commodity Price Risk

The fair value of fixed-price commodity contracts is estimated based on market prices of commodities covered by the contracts. As of December 31, 2003, we have outstanding call obligations for physical delivery of 3.3 million MMBTU of natural gas during February and March of 2004. We have recorded a liability related to these obligations of $1.8 million based on the market value of natural gas as of December 31, 2003. We settled these calls during January and February, resulting in a gain of $526,000.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The consolidated financial information, including the reports of independent accountants, the quarterly financial information, and the financial statement schedules, required by this Item 8 is set forth on pages F-1 to F-44 of this Annual Report on Form 10-K and is hereby incorporated into this Item 8 by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As reported in our December 2002 annual report on Form 10-K, management and our independent auditors advised our Audit Committee that during the course of the 2002 audit, deficiencies in internal controls were noted relating to:

• The evaluation of appropriate reserves for accounts receivable and billing adjustments specifically at Expanets;

• Timely evaluation and substantiation of material account balances; and

• Supervision, staffing and training of accounting personnel.

These internal control deficiencies existing at the time constituted reportable conditions and, collectively, a material weakness as defined in Statement on Auditing Standards No. 60.

During 2003, we implemented substantial corrective actions to address these issues including, but not limited to, the following:

• Retained outside legal counsel and a consulting firm to evaluate and improve our existing internal and disclosure controls;

• Hired a Vice President-Audit and Controls, reporting directly to our chief executive officer, to monitor and review internal controls at our utility division, NorthWestern Energy;

• Advised all employees of our corporate code of conduct in a form and content complying with the Sarbanes-Oxley Act;

• Adopted improved accounting policies, procedures and internal controls for the consolidated financial closing process, including closer management review of subsidiary financial information, and documentation of intercompany transactions;

• Improved communication between operating, financial and management functions and expanded our formal reporting procedures;

• Strengthened our base control environment including: establishment of weekly senior management and cash review meetings, issued capital and expense approval levels; defined strategic initiatives, company objectives and core values, as well as management and employee conduct guidelines;

• Established a Project Office to manage a 3-phase process (evaluation, remediation, testing) for the implementation of improved controls to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act;

• Provided education to management as to their responsibilities for the evaluation of the effectiveness of internal controls and their assessment and demonstration of the asserted effectiveness;

• Conducted performance evaluations of all members of internal financial staff and undertook appropriate action resulting from these evaluations.

We will continue to evaluate the effectiveness of our internal controls and procedures on an ongoing basis. We have discussed our corrective actions and plans with the Audit Committee and our independent auditors and, as of the date of this report, we believe the actions outlined have corrected the deficiencies in internal controls that were considered to be a material weakness. Further, our management, including the Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

As described above, there have been significant changes in our internal controls and in other factors that we believe will significantly improve the control environment.

Part III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

Executive Officer	Current Title and Prior Employment	Age on March 1, 2004

Gary G. Drook	Chief Executive Officer since January 2003 and President since August 2003; Chairman of the Board and formerly President and Chief Executive Officer and Director of AFFINA, The Customer Relationship Company (formerly Ruppman Marketing Technologies, Inc.), a provider of customer services programs, since 1997; formerly President of Network Services (1994-1995) for Ameritech Corporation, a communications services provider. Mr. Drook also serves as Chairman of NorthWestern Growth Corporation, Netexit, Inc. and Blue Dot Services Inc. (each of which are NorthWestern subsidiaries).	59

Michael J. Hanson	Chief Operating Officer since August 2003; formerly President and Chief Executive Officer of NorthWestern Energy division (1998-2003). Prior to joining the Company, Mr. Hanson was General Manager and Chief Executive of Northern States Power Company South Dakota and North Dakota in Sioux Falls, South Dakota (1994-1998).	45

William M. Austin	Chief Restructuring Officer since April 2003. Prior to joining the Company, Mr. Austin served as Chief Executive Officer of Cable & Wireless/Exodus Communications US, Executive Vice President and Chief Financial Officer of Exodus (2001-2002), Senior Vice President and Chief Financial Officer of BMC Software (1997-2001). Mr. Austin also serves as a member of the boards of directors of NorthWestern Growth Corporation, Netexit, Inc. and Blue Dot Services Inc.	57

Brian B. Bird	Chief Financial Officer since December 2003. Prior to joining the Company, Mr. Bird was Chief Financial Officer and Principal of Insight Energy, Inc., a Chicago-based independent power generation development company (2002-2003). Previously, he was Vice President and Treasurer of NRG Energy, Inc., in Minneapolis (1997-2002). Mr. Bird serves as a member on the board of directors of Netexit, Inc.	41

Eric R. Jacobsen	Senior Vice President since February 2002; General Counsel and Chief Legal Officer since February 1999; formerly Vice President (1999-2002); Mr. Jacobsen also serves as Chief Operating Officer of NorthWestern Growth Corporation (since 2001); formerly Principal and General Counsel of NorthWestern Growth Corporation (1998-2001). Mr. Jacobsen also is a member of the boards of directors of NorthWestern Growth Corporation and Netexit, Inc. Prior to joining the Company, Mr. Jacobsen was Vice President-General Counsel and Secretary of LodgeNet Entertainment Corporation (1995-1998). Previously Mr. Jacobsen was a partner (1988-1995) with the law firm Manatt, Phelps & Phillips in Los Angeles, California.	47

Maurice H. Worsfold	Vice President-Audit and Controls since April 2003 and Chief Risk Officer since December 2003. Prior to joining the Company, Mr. Worsfold served as Vice President and Chief Financial Officer of VimpelCom (NYSE: VIP) a Russian telecommunications company (2000-2002), Chief Financial Officer of ClearWater-Moscow (1999) and Corporate Director Finance of RIG Restaurants Ltd.-Moscow (1995-1998).	68

Roger P. Schrum	Vice President – Human Resources and Communications since December 2003; formerly Vice President – External Communications (2001-2003). Prior to joining the Company, Mr. Schrum was General Manager, Marketing Communications and Public Affairs of SCANA Corporation, a Columbia, South Carolina-based utility company (1993-2001).	48

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

The following information is furnished with respect to the directors in Class I whose terms will expire at the 2004 annual meeting of the Board .

Director	Principal Occupation or Employment	Director Since	Age on March 1, 2004
Randy G. Darcy	Senior Vice President, Operations of General Mills, Inc. (NYSE: GIS) a consumer foods company, since 1987.	1998	53

Gary G. Drook	Chief Executive Officer of NorthWestern since January 2003 and President since August 2003; Chairman of the Board of AFFINA, The Customer Relationship Company (formerly Ruppman Marketing Technologies, Inc.), a provider of customer services programs, formerly President and Chief Executive Officer and Director of AFFINA (1997-2003) , President of Network Services (1994-1995) for Ameritech Corporation, a communications services provider.	1998	59

Bruce I. Smith	Attorney and partner in the law firm of Leininger, Smith, Johnson, Baack, Placzek, Steele & Allen since 1978.	1989	62

The following information is furnished with respect to directors in Class II whose terms will expire in May 2005:

Director	Principal Occupation or Employment	Director Since	Age on March 1, 2004
Jerry W. Johnson	Dean Emeritus and Professor Emeritus, School of Business, University of South Dakota; formerly Visiting Scholar, Congressional Budget Office, U.S. Congress (2002-2003). Dean and Professor of Economics (1990-2001), School of Business, University of South Dakota; Member of the Boards of Directors of Citibank (S.D.), N.A., Citibank FSB (West) and Citibank USA.	1994	63

Larry F. Ness	Chairman and Chief Executive Officer of First Dakota Financial Corp., a bank holding company, and of First Dakota National Bank since 1996; formerly Vice Chairman and Chief Executive Officer of that bank (1993-1996).	1991	58

The following information is furnished with respect to directors in Class III whose terms will expire in May 2006:

Director	Principal Occupation or Employment	Director Since	Age on March 1, 2004
Marilyn R. Seymann	Interim Chairman of the NorthWestern Board of Directors since January 2003; President and Chief Executive Officer of M ONE, Inc., a financial services consulting firm, since 1991; Member of the Boards of Directors of Beverly Enterprises, Inc. (NYSE: BEV), a healthcare service provider; Community First Bankshares, a financial institution; EOS International, a holding company of direct sellers; and Maximus, Inc. (NYSE: MMS) a firm providing program management, information technology, and consulting services to the government agencies.	2000	61

Lawrence J. Ramaekers	Self-employed consultant since 2001; formerly Chief Operating Officer for MicroWarehouse, Inc., a computer equipment seller (2003-2004); member of AlixPartners (1982-2000), a turnaround management firm.	2003	66

Audit Committee

The Audit Committee is composed of four nonemployee directors who are financially literate in financial and auditing matters and are “independent” as defined by the SEC and the NYSE. The members of the Audit Committee are Chairman Jerry W. Johnson, Lawrence J. Ramaekers, Bruce I. Smith and Larry F. Ness. The Company’s Board of Directors has determined that the Company has at least one audit committee financial expert, as defined in Item 401(h)(2) of Regulation S-K, serving on its Audit Committee, namely, Jerry W. Johnson. Mr. Johnson is independent as that term is used in Item 7(d)(3)(iv) of Schedule 14A under the 1934 Act. The Audit Committee held 18 meetings during 2003. The functions of the Audit Committee are to oversee the integrity of NorthWestern’s financial statements, NorthWestern’s compliance with legal and regulatory requirements, the independent public accountant’s qualifications and independence, the performance of NorthWestern’s internal audit function and independent auditors, and preparation of this report and the financial statement and notes included herein, and all other reports required under the Securities Exchange Act.

Section 16(a) Beneficial Ownership Reporting Compliance

Based solely upon a review of reports on Forms 3, 4 and 5 and any amendments thereto furnished to NorthWestern pursuant to Section 16 of the Securities Exchange Act of 1934, as amended, and written representations from the executive officers and directors that no other reports were required, NorthWestern believes that all of such reports were filed on a timely basis by executive officers and directors during 2003.

Code of Ethics

Our Board of Directors adopted our Code of Business Conduct and Ethics (“Code of Ethics”) on August 26, 2003. Our Code of Ethics sets forth standards of conduct for all officers, directors and employees of NorthWestern and its subsidiary companies, including all full and part-time employees and certain persons that provide services on our behalf, such as agents. Copies of our Code of Ethics are available on NorthWestern’s Web site at http://www.northwestern.com. We intend to post on our Web site any amendments to, or waivers from, our Code of Ethics. In addition, our Board of Directors adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions on August 26, 2003.

ITEM 11. EXECUTIVE COMPENSATION

Compensation of Directors and Executive Officers

We are required by the SEC to disclose compensation earned during the last three fiscal years by (i) our Chief Executive Officer; (ii) our four most highly compensated executive officers, other than the Chief Executive Officer, who were serving as executive officers at the end of fiscal 2003; and (iii) up to two additional individuals for whom such disclosure would have been provided under clause (i) and (ii) above but for the fact that the individual was not serving as an executive officer at the end of fiscal 2003; provided, however, that no disclosure need be provided for any executive officer, other than the Chief Executive Officer, whose total annual salary and bonus does not exceed $100,000.

Accordingly, the following sections disclose information regarding compensation earned during the last three fiscal years by (i) Gary G. Drook, our President and Chief Executive Officer; (ii) Michael J. Hanson, Eric R. Jacobsen, William M. Austin and John R. Van Camp, the four most highly-compensated executive officers, other than the Chief Executive Officer, who were serving as executive officers at the end of fiscal 2003 and whose salary and bonus exceeded $100,000 ,and (iii) Daniel K. Newell, former Senior Vice President of the Company. All of these officers are referred to in this Form 10-K as the “Named Executive Officers.”

Summary Compensation Table

The following table sets forth the compensation earned during the fiscal years indicated for services in all capacities by the Named Executive Officers in 2003:

Name and Principal Position1	Year	Salary (7)$		Bonus (1)$		Restricted Stock Awards (2)($)		Awards (Securities Underlying Options)(3)(#)	LTIP Payouts (4)($)		All Other Compensation(5) ($)
Gary G. Drook President & Chief Executive Officer	2003	$	544,355	$	600,000	$	1,143,332	335,643	$	—	$	216,744
	2002	88,384		N/A		N/A		4,000	N/A		N/A
	2001	68,140		N/A		N/A		4,000	N/A		N/A

Michael J. Hanson Chief Operating Officer	2003	355,609		—		—		—	—		27,916
	2002	345,833		540,000		—		29,000	—		25,817
	2001	323,750		635,914		—		9,000	—		19,684

Eric R. Jacobsen Senior Vice President, General Counsel & Chief Legal Officer	2003	314,967		—		—		—	41,960		31,261
	2002	304,791		400,000		—		44,000	—		28,829
	2001	280,416		150,000		—		28,000	430,757		17,491

William M. Austin Chief Restructuring Officer	2003	284,615		—		102,500		119,980	—		16,280
	2002	N/A		N/A		N/A		N/A	N/A		N/A
	2001	N/A		N/A		N/A		N/A	N/A		N/A

John R. Van Camp Vice President-Organization & Staffing	2003	248,926		—		—		—	—		38,750
	2002	245,000		—		—		30,000	—		24,105
	2001	241,875		55,000		—		28,000	—		12,274

Daniel K. Newell (6) President & Chief Executive Officer	2003	328,215		—		—		—	—		34,366
	2002	354,000		—		—		36,000	42,979		19,541
	2001	347,333		80,000		—		44,500	861,346		21,600
Blue Dot Services Inc.

(1) Bonuses shown were earned in the year shown and paid in the following year except that Mr. Drook received a bonus at employment of $600,000.

(2) The restricted stock awards for Mr. Drook and Mr. Austin have no value and will be cancelled in connection with the adoption of our plan of reorganization. Mr. Drook was awarded 233,333 shares of restricted stock in 2003, which had a value of $21,000 at December 31, 2003. Mr. Austin was awarded 50,000 shares of restricted stock in 2003, which had a value of $4,500 at December 31, 2003.

(3) We anticipate all outstanding options will be cancelled in connection with the adoption of our plan of reorganization. Awards for Mr. Drook and Mr. Austin in 2003 include awards of stock options of 335,643 and 119,980. For 2002, the awards shown represent stock options for Mr. Drook, Mr. Hanson, Mr. Jacobsen, Mr. Van Camp and Mr. Newell. For 2001, the awards include stock options for Mr. Hanson, Mr. Jacobsen, Mr. Van Camp and Mr. Newell, as well as phantom stock unit awards of 3,000; 2,819; 3,172; and 4,714 units, respectively (these phantom stock unit awards were terminated as of December 31, 2003, when the Company failed to meet the performance targets required for vesting.)

(4) For 2002 and 2001, the amounts included for Mr. Newell include $42,979 and $30,970, respectively, for the cash payout from the company’s former phantom stock long-term incentive compensation plan at the end of the five-year period following the date of the award. The remaining 2001 distribution for Mr. Newell and the 2001 distribution for Mr. Jacobsen represent vested interests in the former NorthWestern Growth Corporation long-term incentive plan. The 2003 distribution to Mr. Jacobsen represents a final liquidation payment upon termination of the NorthWestern Growth plan.

(5) The amounts include employer contributions, as applicable, for medical, dental, vision, employee assistance program (EAP), term life, group term life, 401(k), supplemental 401(k), Employee Stock Option Purchase (ESOP), and contributions to postretirement benefit plans as well as an airplane allowance for Mr. Drook, vehicle lease or car allowance, association and club dues, relocation expenses and tax gross up payments (where provided).

(6) Mr. Newell served as Senior Vice President for NorthWestern Corporation until November 2003.

(7) For 2002 and 2001, Mr. Drook’s compensation shown represents cash fees and common stock received as a nonemployee member of the Board of Directors.

Information on Options

Option Grants in Last Fiscal Year

Individual Grants

Potential Realizable Value
At Assumed Annual Rates
of Stock Price Appreciation
for Option Term(3)($)

Name

No.
of Securities
Underlying
Options
Granted (#)(1)

Percent of
Total Options
Granted to
Employees
in Fiscal Year

Exercise or
Base Price
($/Sh)(2)

Expiration
Date

At 5% ($0.13
Stock Price)

At 10% ($0.21
Stock Price)

Gary G. Drook

335,643

4.90

2/5/2013

Michael J. Hanson

N/A

Eric R. Jacobsen

N/A

William M. Austin

119,980

2.05

4/16/2013

John R. VanCamp

N/A

Daniel K. Newell

N/A

(1) Mr. Drook’s options vest 1/3 on 12/31/03, 12/31/04 and 12/31/05. Any shares acquired cannot be sold for 12 months except to satisfy tax obligations. Mr. Austin’s options vest 1/3 on 3/31/04, 12/31/05 and 12/31/06; any shares acquired cannot be sold for 12 months except to satisfy tax obligations.

(2) All options were granted at market value (the closing price of the Common Stock on the NYSE as reported in the Midwest Edition of The Wall Street Journal) on the date of grant.

(3) The hypothetical potential gains (reported net of exercise price) are based entirely on assumed annual growth rates of 5% and 10% in the value of NorthWestern’s stock price over the 10-year life of the options (which would equal a total increase in stock price of 63% and 159%, respectively). These assumed rates of growth are mandated by rules of the SEC for illustration purposes only and are not intended to predict future stock price. All stock options will be cancelled in connection with the adoption of our plan of reorganization.

Fiscal Year-End Option Values

	Number of Securities Underlying Unexercised Options at Fiscal Year-End (#)		Value of Unexercised In-the-Money Options At Fiscal Year-End ($)(1)
Name	Exercisable	Unexercisable	Exercisable		Unexercisable

Gary G. Drook	117,181	235,762	$	0	$	0
Michael J. Hanson	15,362	42,290	0		0
Eric R. Jacobsen	43,985	95,158	0		0
William M. Austin	0	119,980	0		0
John R. Van Camp	36,857	80,161	0		0
Daniel K. Newell	47,746	118,114	0		0

(1) There were no in-the-money options at December 31, 2003.

Employment Contracts

Mr. Hanson entered into an employment agreement as of March 1, 2001, which was terminated in March 2004, and Messrs. Jacobsen and Van Camp entered into employment agreements as of March 1, 2001, which terminated on the last day of February 2004. Under the agreements, Messrs. Hanson, Jacobsen and Van Camp were entitled to receive a base salary that was subject to annual increases based on the median of comparable companies and a discretionary bonus. They each were also eligible to participate in NorthWestern’s annual short-term cash incentive plans and long-term cash and stock incentive plans tied to the success of the organization. These long-term incentive plans included, among other things, options to purchase shares of NorthWestern common stock. They were also entitled to participate in NorthWestern benefit plans available to executives, including, among other things, health, retirement, disability and life insurance benefits as well as an automobile allowance. Mr. Jacobsen had the right under his contract to participate in long-term incentive plans which held minority investments in or were otherwise tied to the performance of NorthWestern’s nonregulated subsidiaries.

The former agreements provided for the payment of accrued salary and termination benefits if employment was terminated by NorthWestern for any reason other than Cause, due to death or by the employee due to a “fundamental change.” A fundamental change generally occurs if there is a diminution in the employee’s responsibilities or compensation, NorthWestern relocates its primary offices more than 30 miles or there is a change in control or major transaction involving NorthWestern (each as defined in the agreement). The termination benefits included a lump sum payment equal to (1) the sum of (a) base salary, (b) the higher of either the employee’s most recent bonuses and short-term incentive awards or the average of such bonuses and awards over the preceding three calendar years and (c) the higher of either the value of the employee’s most recent options, long-term incentive awards and private equity investment returns or the average value of such options, awards and returns over the preceding three calendar years, multiplied by (2) the remaining term of the agreement plus one year. The termination benefits also included lump sum payments equal to the employee’s interests under NorthWestern’s benefit plans. The Executive had the right to defer receipt of certain of these termination benefits rather than receiving them as a lump sum. All equity awards granted to him accelerated in full upon termination of the agreement (other than for Cause) and remained exercisable in accordance with their terms. NorthWestern had agreed to make gross-up payments to him to the extent that termination benefits would be subject to the excise tax on excess “parachute payments” following a change of control. The termination benefits under these agreements were to be provided regardless of whether the employee is able to obtain other employment. The agreements contained provisions requiring the Executive to maintain the confidentiality of NorthWestern proprietary information and restricted him from competing with NorthWestern or soliciting NorthWestern employees, suppliers and customers for a period of two years following termination. NorthWestern has agreed, pursuant to the agreement, to indemnify him to the fullest extent permitted by law.

We have contractual arrangements with two other executive officers, Chief Restructuring Officer William M. Austin, one of the named executives, and Chief Financial Officer Brian B. Bird.

We have a Memorandum of Engagement with Mr. Austin, which, as amended and approved by the Bankruptcy Court in its Order dated October 10, 2003, terminates on the earlier of 18 months or the effective date of a confirmed reorganization plan, unless extended by mutual agreement. Under the agreement Mr. Austin, as he serves as Chief Restructuring Officer, is entitled to a base salary of $400,000, a time-based addition, and an incentive-based addition. The agreement provides that if an effective date of a reorganization plan occurs before scheduled completion of the above distributions, the payments not yet made will be fully earned and paid on the effective date. The agreement also provides for severance if Mr. Austin is involuntarily terminated or otherwise as a result of the bankruptcy proceedings and indemnification by us for claims made in connection with his engagement as Chief Restructuring Officer.

We also have an Employment Agreement with Mr. Bird, which, as amended and approved by the Bankruptcy Court in its Order dated January 13, 2004, provides for him to serve as Chief Financial Officer, commencing December 1, 2003, and extends until the earlier of his termination of employment or December 1, 2005. Mr. Bird’s compensation package consists of a sign-on bonus, a base salary of $275,000 and performance-based incentive of up to his annual salary. Mr. Bird is also entitled to participate in our benefit plans available to executives, including, among other things, health, retirement, disability and life insurance benefits. The agreement provides that if an effective date of a reorganization plan, or the consummation of a sale of NorthWestern occurs before scheduled completion of the above distributions, then payments not yet made will be fully earned and paid on the effective date. The agreement also provides for severance if Mr. Bird is terminated for any reason other than Cause.

Blue Dot President and Chief Executive Officer Daniel K. Newell, one of the named executives, has a Memorandum of Engagement with Blue Dot, dated November 6, 2003, and effective for a term beginning September 1, 2003, and extending until September 1, 2004, or his earlier termination of employment. Under the agreement, Mr. Newell is provided a base salary, incentive-based additional compensation related to Blue Dot’s success in completing the sale of its operations, a severance benefit if his employment is involuntarily terminated by Blue Dot, reasonable out-of-pocket expense reimbursement, and indemnification by Blue Dot for claims made in connection with his engagement as President and Chief Executive Officer. Pursuant to such agreement, Mr. Newell was paid $1.42 million of incentive-based compensation in February 2004 related to the receipt of targeted net proceeds from the sales of businesses. He may be entitled to an additional $180,000 bonus upon termination of his employment if certain sales proceeds goals are met.

Retirement Plans

NorthWestern has two retirement plans, with one applicable to its Montana NorthWestern Energy employees and one applicable to its South Dakota and Nebraska NorthWestern Energy and all NorthWestern Corporation employees. All of the named executives participate in the latter plan. For that plan, effective January 1, 2000, NorthWestern offered its employees two alternatives with regard to its retirement plan. An employee could convert his or her existing accrued benefit from the existing plan into an opening balance in a hypothetical account under a new cash balance formula, or that team member could continue under the existing defined benefit formula. All employees hired after January 1, 2000, participate in the cash balance formula. The beginning balance in the cash balance account for a converting team member was determined based on the employee’s accrued benefit, age and service as of January 1, 2000, 2000 eligible pay, and a conversion interest rate of 6%. Under the cash balance formula a participant’s account grows based upon (1) contributions by NorthWestern made once per year, and (2) by annual interest credits based on the average Federal 30-year Treasury bill rate for November of the preceding year (6.15% for 2000). Contribution rates were determined on January 1, 2000, based on the participant’s age and years of service on that date. They range from 3%-7.5% (3% for all new employees) for compensation below the taxable wage base and are doubled for compensation above the taxable wage base. Upon termination of employment with NorthWestern, an employee, or if deceased, his or her beneficiary, receives the cash balance in the account paid in a lump sum or in other permitted annuity forms of payment.

To be eligible for the retirement plan, an employee must be 21 years of age and have worked at least one year for NorthWestern, working at least 1,000 hours in that year. Nonemployee Directors are not eligible to participate. Benefits for employees who chose not to convert to the cash balance formula will continue to be part of the defined benefit formula, which provides an annual pension benefit upon normal retirement at age 65 or earlier (subject to benefit reduction). Under this formula, the amount of the annual pension is based upon average annual earnings for the 60 consecutive highest paid months during the 10 years immediately preceding retirement. Upon retirement on the normal retirement date, the annual pension to which an eligible employee becomes entitled under the formula amounts to 1.34% of average annual earnings up to the Covered Compensation base plus 1.75% of such earnings in excess of the Covered Compensation base, multiplied by all years of credited service.

As of December 31, 2003, Mr. Drook and Mr. Austin, among the named executives, were not vested participants in either retirement plan. Mr. Hanson, Mr. Jacobsen, Mr. Van Camp, and Mr. Newell were participants in the retirement plan applicable to South Dakota and Nebraska employees. Those four named executives also have participated in a supplemental excess retirement plan related to both of the pension formulas, which provides benefits based on those formulas but with respect to compensation which exceeds the limits under the Code. In addition, NorthWestern has agreed to assure Mr. Hanson a pension benefit equivalent to that which would be provided by the Retirement Plan if he were given credit for his 17 years of prior service with another utility company in addition to his years of service with NorthWestern. As a result, he was credited with those additional years of service under the supplemental excess retirement plan.

Assuming the named executives reach the normal retirement age of 65, the projected annual life annuity benefits for the named executives would be: Mr. Hanson, $162,483; Mr. Jacobsen, $57,731; Mr. Van Camp, $67,218; and Mr. Newell, $95,240. In 2003, NorthWestern contributed the following amounts for those four named executive officers, through interest credits and pay credits under the retirement plan and the supplemental excess retirement plan: Mr. Hanson, $42,263; Mr. Jacobsen, $19,298; Mr. Van Camp, $14,240; and Mr. Newell, $29,004. As of December 31, 2003, the cash balance accounts for those four named executive officers were as follows: Mr. Hanson, $92,433; Mr. Jacobsen, $16,280; Mr. Van Camp, $15,060; and Mr. Newell, $39,133.

Other Benefits

NorthWestern currently maintains a variety of benefit plans and programs, which are generally available to all NorthWestern employees, including executive officers, such as the 401(k) Retirement Plan under which an employee may contribute up to 13% of his or her salary (with NorthWestern matching up to 4% of the first 6% contributed by the employee), a term life and supplemental life insurance coverage, long-term disability plan, and other general employee benefits such as emergency personal leave and educational assistance. In 2003, the Board of Directors terminated certain benefit plans, including the Supplemental Variable Investment Plan (a nonqualified Supplemental 401(k) plan available to the extent participation in the 401(k) is limited by the Internal Revenue Code), a Team Member Stock Purchase Plan (Section 423 Plan) approved by shareholders and instituted in 1999, under which an employee may contribute up to $3,000 per year for the purchase of NorthWestern Common Stock (at a discount of up to 15% of market value), and the NorthWestern Employee Stock Ownership Plan (ESOP).

Salary Continuation Plan

NorthWestern has a nonqualified salary continuation plan for directors and selected management employees (the Supplemental Income Security Plan). In 2003, the Board of Directors amended the plan to terminate any new participation in it and to authorize the payment to plan participants, other than nonemployee directors, of the discounted present value of the future benefits under the plan, or the refund of employees’ personal contributions to the plan for those employees whose interest in the plan had not become vested, based on the participant’s election. NorthWestern utilized the cash value of the life insurance policies held by NorthWestern, in part, to make such

payments to those participants electing such payout.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee is composed of not less than three nonemployee directors. The members of the Compensation Committee are Chairman Randy G. Darcy, Marilyn R. Seymann, Larry F. Ness and Lawrence J. Ramaekers. None of the persons who served as members of the Compensation Committee of the Board during fiscal year 2003 are officers or employees or former employees of NorthWestern or any of its subsidiaries.

Director Compensation

Nonemployee Directors are paid $2,500 each quarter for serving on the Board, and receive an attendance fee of $4,000 for attendance at each regular or special meeting of the Board. Directors are also paid $1,700 for each meeting of a committee on which such director serves and $500 for each quarter during which they serve as chairman of a committee of the Board. Directors receive one-half of the meeting fee for telephonic conference board or committee meetings. In addition, as Chairman of the Board, Ms. Seymann receives $18,750 per quarter. Because he is an executive officer, Mr. Drook is not separately compensated for his services as a director on NorthWestern’s Board.

Directors may elect to defer receipt of their cash compensation as directors until they cease to be directors. The deferred compensation may be invested in (1) an account which earns interest at the same rate as accounts in the employees savings plan or (2) a deferred compensation unit account in which the deferred compensation is converted into deferred compensation units on the basis that each unit is at the time of investment equal in value to the fair market value of one share of NorthWestern’s Common Stock, sometimes referred to as “phantom stock units.” Additional units based on the dividends paid on NorthWestern’s Common Stock are added to the director’s deferred compensation unit account. Following the director’s retirement, the value of the deferred compensation is paid in cash to the former director within a period of five years.

REPORT OF COMPENSATION COMMITTEE
ON EXECUTIVE COMPENSATION

The Compensation Committee (the Committee) of the Board furnishes the following report on executive compensation.

Procedures and Policies

The Committee is comprised of four independent directors, Chairman Randy G. Darcy, Marilyn R. Seymann, Larry F. Ness and Lawrence J. Ramaekers. The Committee has overall responsibility to nominate persons to serve as executive officers and to review and to approve annual and long-term compensation plans and awards for the members of the Board and for the executive officers. The Committee also reviews and recommends to the full Board any welfare benefit and retirement plans for officers and employees. The Compensation Committee Charter is reviewed at least annually. The Committee met seven times during 2003.

In 2003, the Committee engaged Towers Perrin, a compensation and benefits consulting firm, to assess the current executive officer compensation plans and employment protections and to offer recommendations that would support our business strategy. Towers Perrin representatives interviewed members of the Board, compared the compensation of our executive officers and directors to comparable companies, and presented their findings to the Committee. The Board has implemented various recommendations from the Towers Perrin analysis which are designed to align investor and executive officer interests; to compensate executives for improvement in our performance; to focus on long-term performance and the creation of enterprise value; and to attract and retain key executives and other key employees.

The Committee approved in February 2003 a compensation program which positioned total direct executive compensation (including base salary, annual incentives and long-term incentives) at between the median and 75th percentile based on benchmarking of comparable companies in the energy industry when performance is consistent with that comparative group. In addition to utilizing external benchmarking as a guidepost, any adjustments to base salary levels or incentive targets and payments of incentives for executive officers are based on assessment of individual officer performance and require Committee approval. Each officer minimally receives a formal performance assessment and review on an annual basis; such assessment is based on the achievement of specific individual and department goals and the degree to which it is determined the officer has contributed to the achievement of our overall goals. On September 14, 2003, we filed for relief under Chapter 11 of the federal Bankruptcy Code and continue to operate our business as a debtor-in-possession, subject to the jurisdiction of the Bankruptcy Court. As described below, the Committee adopted, and the Bankruptcy Court has approved, a new incentive compensation and severance plan that replaces prior incentive and severance programs.

Section 162(m) of the Internal Revenue code of 1986 generally disallows a tax deduction to public companies for compensation over $1,000,000 paid to their chief executive officer and the four other most highly compensated executive officers unless certain tests are

met. The Committee’s general objective is to design and administer NorthWestern’s compensation programs in a manner that will preserve the deductibility of compensation payments to executive officers but also will consider such programs in light of the importance of achieving NorthWestern’s compensation objectives discussed above.

Base Salary

Base salary levels for executive officers are reviewed annually and are generally targeted within a range around the median of the comparative group with adjustments based on individual officer performance and market data.

Annual Incentive Compensation

The philosophy for all of our incentive compensation plans is to provide rewards when financial, operational and other objectives are achieved, and to provide reduced or no benefits when the objectives are not achieved. These objectives are designed to further our goals and to increase our enterprise value.

Our Board of Directors has adopted, and the Bankruptcy Court has approves, an incentive compensation and severance plan to motivate and to retain key employees who support our continued and successful operations, and who can help lead us through a successful Chapter 11 reorganization. This plan modifies and supersedes any and all prior incentive compensation and severance policies, plans and programs. Under this plan, for which funding has been established at approximately 50% of historic total targeted annual incentives, participants, including the named executives, become eligible to receive incentive compensation upon determination that the associated performance-based milestones approved by the Bankruptcy Court have been achieved. For executive officers, such milestones include the Bankruptcy Court approval of a disclosure statement, the effective date of a plan of reorganization and a time based component. For all other officers and eligible employees, the milestones are essentially time-based to encourage retention. A participant must remain employed to receive such an incentive payment. The plan further provides that participants are eligible to receive certain specified severance benefits if their employment terminates, except under specified circumstances, including resignation and discharge for cause.

Long-Term Incentive Compensation

As a complement to our annual incentive plans, the Board has determined that long-term incentive programs that tie executive compensation to increases in enterprise value are important. The Board and the shareholders of NorthWestern adopted the NorthWestern Stock Option and Incentive Plan (Plan) to strengthen the link between compensation and the market value of NorthWestern’s stock. The Plan was intended to recognize employee contributions, to provide such persons with additional incentive to devote themselves to our future success, and to improve our ability to attract, retain and motivate individuals upon whom our future growth and financial success is dependant. Similarly, the Plan was intended as an additional incentive to directors who are not employees to serve on the Board and to devote themselves to our future success. In 2003, a limited number of executive officers, including Mr. Drook and Mr. Austin, among the named executives, received option grants, and in 2003 no options were granted to directors who are not employees. All such grants were to vest in equal installments over a three-year period. All stock options are expected to be cancelled prior to emergence from bankruptcy.

Compensation of the Chief Executive Officer

Upon his appointment as interim Chief Executive Officer in January 2003, Mr. Drook’s compensation included a base salary of $565,000 and he received grants of 233,333 shares of restricted stock, incentive stock options covering 61,224 shares, and nonqualified stock options covering 274,419 shares, all based upon a per share price of $4.90. All such restricted shares and option grants are expected to be cancelled prior to emergence from bankruptcy. Mr. Drook also received a cash payment of $600,000 which must be repaid in full should he serve less than 12 months in that position, and for which $250,000 must be repaid should he serve less than 24 months in that position. In addition, we agreed to provide reasonable use of our aircraft for an interim period of 12 months for Mr. Drook to travel to our corporate office from his home. Mr. Drook, who was elected President and Chief Executive Officer in August 2003, has since moved to Sioux Falls, S.D. Mr. Drook’s salary, as he continues in his position, will be based upon his success in achieving the goals and objectives the Committee has recommended, and the Board of Directors has approved. These goals and objectives include liquidating our investments in Expanets, Blue Dot and other noncore assets; reorganizing and restructuring to a utility only business; instituting appropriate internal audit controls and external financial reporting controls; maximizing operating cash flows; restoring community, regulatory and governmental confidence; and leading us to complete our reorganization and emerge from bankruptcy.

Randy G. Darcy, Chairman
Marilyn R. Seymann
Larry F. Ness
Lawrence J. Ramaekers

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

Security Ownership by Certain Beneficial Owners and Management

The following table sets forth information, as of March 1, 2004, with respect to the beneficial ownership of shares of NorthWestern’s Common Stock owned by the directors, nominees for director, the “Named Executive Officers” of NorthWestern, as described below, and by all directors and executive officers of NorthWestern as a group. Except under special circumstances, NorthWestern’s Common Stock is the only class of voting securities. There are no persons known to NorthWestern who own more than 5% of the outstanding shares of Common Stock.

The “Named Executive Officers” include NorthWestern’s (a) Chief Executive Officer; (b) its four most highly compensated executive officers, other than the Chief Executive Officer, who were serving as executive officers at the end of fiscal year 2003; and (c) up to two additional individuals for whom such disclosure would have been provided under clause (a) and (b) above but for the fact that the individual was not serving as an executive officer of NorthWestern at the end of fiscal year 2003; provided, however, that no disclosure need be provided for any executive officer, other than the CEO, whose total annual salary and bonus does not exceed $100,000.

Accordingly, NorthWestern’s Named Executive Officers include (a) Gary G. Drook, its President and Chief Executive Officer; and (b) Michael J. Hanson, Eric R. Jacobsen, William M. Austin, and John R. Van Camp, the four most highly compensated executive officers, other than the Chief Executive Officer, who were serving as executive officers at the end of fiscal year 2003 and whose salary and bonus exceeded $100,000, and (c) former Senior Vice President Daniel K. Newell.

Except as otherwise noted, the persons or entities in this table have sole voting and investing power with respect to all the shares of NorthWestern’s Common Stock beneficially owned by them subject to community property laws, where applicable. The information with respect to each person specified is as supplied or confirmed by such person, based upon statements filed with the SEC, or based upon the actual knowledge of NorthWestern.

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership (1)		Percent of Common Stock
Name of Beneficial Owner	Shares of Common Stock Beneficially Owned		Percent of Common Stock

Randy G. Darcy	5,811			*
Jerry W. Johnson	11,326			*
Larry F. Ness	12,407			*
Lawrence J. Ramaekers	0			*
Marilyn R. Seymann	4,106			*
Bruce I. Smith	15,024			*
Gary G. Drook	238,943	(3)		*
Michael J. Hanson	13,146	(2)		*
Eric R. Jacobsen	8,676			*
William M. Austin	50,000	(3)		*
John R. Van Camp	7,008			*
Daniel K. Newell	32,631			*
All directors and executive officers	399,078		1	%

* Less than 1%.

(1) Shares shown represent both record and beneficial ownership, including shares held in the employee’s account in NorthWestern’s 401(k) Retirement Plan. The address of each person is 125 S. Dakota Ave., Sioux Falls, SD 57104.

(2) Includes 4,316 shares in an Individual Retirement Account.

(3) Includes restricted stock shares of 233,333 for Mr. Drook and 50,000 for Mr. Austin.

Information regarding equity compensation plans required by this Item 12 is included in Item 5 of Part II of this report and is incorporated into this Item 12 by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Prior to his employment by us as our Chief Financial Officer, Brian B. Bird owned a 50% member interest in a limited liability company that derived a portion of its revenue from consultant introduction fees. In this regard, Mr. Bird’s company earned such fees by assisting two utility property tax consultants, Thomas Hamilton and George Karvel, in the development of their consulting practice. During 2003, well in advance of our hiring of Mr. Bird, we engaged the services of Messers. Hamilton and Karvel to evaluate our South Dakota and Montana utility property tax situation and make recommendations on ways to optimize property tax refunds and planning opportunities. We have paid no compensation to Messers. Hamilton and Karvel for services provided to date, as their compensation is entirely contingent upon our realizing property tax savings or refunds directly related to their recommendations. In the event Messers. Hamilton and Karvel are paid fees by us, Mr. Bird has disclaimed any right to receive his allocated share of the introduction fee earned and distributed by his company.

ITEM 14. PRINCIPAL ACCOUNTANTS FEES AND SERVICES

The following table is a summary of the fees billed to us by Deloitte & Touche, LLP (Deloitte) for professional services for the fiscal years ended December 31, 2003 and December 31, 2002:

Fee Category	Fiscal 2003 Fees		Fiscal 2002 Fees

Audit Fees	$	2,300,000	$	4,117,000
Audit-Related Fees	101,000		169,000
Tax Fees	1,372,000		680,000
All Other Fees	—		—
Total Fees	$	3,773,000	$	4,966,000

Audit Fees

Consists of fees billed for professional services rendered for the audit of our financial statements and review of the interim financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements. Audit fees billed in fiscal 2002 related to both the re-audit of 2001 financial statements and the audit of our 2002 financial statements.

Audit-Related Fees

Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include employee benefit plan audits, accounting consultations in connection with acquisitions, attest services that are not required by statute or regulation, and consultations concerning financial accounting and reporting standards.

Tax Fees

Consists of fees billed for professional services for tax compliance, tax advice and tax planning. These services include assistance regarding federal and state tax compliance, tax audit defense, acquisitions, and bankruptcy tax planning.

All Other Fees

Consists of fees for products and services other than the services reported above. In fiscal 2003 and 2002, there were no other fees.

Preapproval Policies and Procedures

Pursuant to the provisions of the Audit Committee Charter, before Deloitte is engaged to render audit or nonaudit services, the Audit Committee must preapprove such engagement. In 2003, the Audit Committee approved all such services undertaken by Deloitte before engagement for such services.

Part IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND REPORTS ON FORM 8-K

a) The following documents are filed as part of this report:

(1) Financial Statements.

The following items are included in Part II, Item 8 of this annual report on Form 10-K:

FINANCIAL STATEMENTS:

Independent Auditors' Report

Consolidated Statements of Income (Loss) for the Years Ended December 31, 2003, 2002 and 2001

Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001

Consolidated Balance Sheets as of December 31, 2003 and 2002

Consolidated Statement of Shareholders’ Equity (Deficit) for the Years Ended December 31, 2003, 2002 and 2001

Notes to Consolidated Financial Statements

Quarterly Unaudited Financial Data for the Two Years Ended December 31, 2003

(2) Financial Statement Schedules

Independent Auditors' Report

Schedule II. Valuation and Qualifying Accounts

Schedule II, Valuation and Qualifying Accounts, is included in Part II, Item 8 of this annual report on Form 10-K. All other schedules are omitted because they are not applicable or the required information is shown in the Financial Statements or the Notes thereto.

(3) Exhibits.

The exhibits listed below are hereby filed with the SEC, as part of this annual report on Form 10-K. Certain of the following exhibits have been previously filed with the SEC pursuant to the requirements of the Securities Act of 1933 or the Securities Exchange Act of 1934. Such exhibits are identified by the parenthetical references following the listing of each such exhibit and are incorporated by reference. We will furnish a copy of any exhibit upon request, but a reasonable fee will be charged to cover our expenses in furnishing such exhibit.

Exhibit Number		Description of Document
2.1(a)*		Unit Purchase Agreement, dated as of September 29, 2000, among NorthWestern Corporation, Touch America Holdings, Inc. and The Montana Power Company with respect to all outstanding membership interests in The Montana Power, LLC (incorporated by reference to Exhibit (10)(a)(1) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 21, 2001, Commission File No. 0-692).
2.1(b)*		Amendment No. 1 to the Unit Purchase Agreement, dated as of June 21, 2001 (incorporated by reference to Exhibit (10)(a)(2) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 21, 2001, Commission File No. 0-692).

3.1*		Restated Certificate of Incorporation of NorthWestern Corporation, dated November 9, 2000 (incorporated by reference to Exhibit 3(a) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, Commission File No. 0-692).
3.2**		By-Laws of NorthWestern Corporation, as amended, dated August 26, 2003.
4.1(a)*		General Mortgage Indenture and Deed of Trust, dated as of August 1, 1993, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(a) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 16, 1993, Commission File No. 0-692).
4.1(b)*		Supplemental Indenture, dated as of August 15, 1993, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(b) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 16, 1993, Commission File No. 0-692).
4.1(c)*		Supplemental Indenture, dated as of August 1, 1995, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(b) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 30, 1995, Commission File No. 0-692).
4.1(d)*		Supplemental Indenture, dated as of February 1, 2003, from NorthWestern Corporation to JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
4.2(a)*		Preferred Securities Guarantee Agreement, dated as of August 3, 1995, between NorthWestern Corporation and Wilmington Trust Company (incorporated by reference to Exhibit 1(d) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 30, 1995, Commission File No. 0-692).
4.2(b)*		Declaration of Trust of NWPS Capital Financing I (incorporated by reference to Exhibit 4(d) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 30, 1995, Commission File No. 0-692).
4.2(c)*		Amended and Restated Declaration of Trust of NWPS Capital Financing I (incorporated by reference to Exhibit 4(e) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 30, 1995, Commission File No. 0-692).
4.2(d)*		Preferred Securities Guarantee Agreement, dated as of November 18, 1998, between NorthWestern Corporation and Wilmington Trust Company (incorporated by reference to Exhibit 4(g) of NorthWestern Corporation’s Registration Statement on Form 8-A (Amendment No. 1), dated December 3, 1998, Commission File No. 001-14623).
4.2(e)*		Certificate of Trust of NorthWestern Capital Financing I (incorporated by reference to Exhibit 4(b)(11) of NorthWestern Corporation’s Registration Statement on Form S-3, dated July 2, 1998, Commission File No. 333-58491).
4.2(f)*		Amended and Restated Declaration of Trust of NorthWestern Capital Financing I (incorporated by reference to Exhibit 4(e) of NorthWestern Corporation’s Registration Statement on Form 8-A (Amendment No. 1), dated December 3, 1998, Commission File No. 001-14623).

Exhibit Number		Description of Document
4.2(g)*		Preferred Securities Guarantee Agreement, dated as of December 21, 2001, between NorthWestern Corporation and Wilmington Trust Company (incorporated by reference to Exhibit 4.7 of NorthWestern Corporation’s Registration Statement on Form 8-A, dated December 21, 2001, Commission File No. 001-16843).
4.2(h)*		Restated Certificate of Trust of NorthWestern Capital Financing II (incorporated by reference to Exhibit 4(b)(12) of NorthWestern Corporation’s Registration Statement on Form S-3, dated July 2, 1998, Commission File No. 333-58491).
4.2(i)*		Amended and Restated Declaration of Trust of NorthWestern Capital Financing II (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation’s Registration Statement on Form 8-A, dated December 21, 2001, Commission File No. 001-16843).
4.2(j)*		Preferred Securities Guarantee Agreement, dated as of January 31, 2002, between NorthWestern Corporation and Wilmington Trust Company (incorporated by reference to Exhibit 4.6 of NorthWestern Corporation’s Registration Statement on Form 8-A, dated February 1, 2002, Commission File No. 001-31229).
4.2(k)*		Restated Certificate of Trust of NorthWestern Capital Financing III (incorporated by reference to Exhibit 4(b)(13) of NorthWestern Corporation’s Registration Statement on Form S-3, dated July 2, 1998, Commission File No. 333-58491).
4.2(l)*		Amended and Restated Declaration of Trust of NorthWestern Capital Financing III (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation’s Registration Statement on Form 8-A, dated February 1, 2002, Commission File No. 001-16843).
4.2(m)*		Form of Guarantee Agreement, between The Montana Power Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 4(d) of The Montana Power Company’s Registration Statement on Form S-3, dated October 18, 1996, Commission File No. 333-14369).
4.2(n)*		Assumption of Guarantee Agreement, dated as of February 13, 2002, by The Montana Power, LLC in favor of The Bank of New York, as trustee (incorporated by reference to Exhibit 4.2(n) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.2(o)*		Assumption Agreement (QUIPs Guarantee), dated as of November 15, 2002, by between NorthWestern Energy, LLC, as assignor, and NorthWestern Corporation, as assignee (incorporated by reference to Exhibit 4.2(o) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.2(p)*		Form of Trust Agreement of Montana Power Capital I (incorporated by reference to Exhibit 4(a) of The Montana Power Company’s Registration Statement on Form S-3, dated October 18, 1996, Commission File No. 333-14369).
4.2(q)*		Assignment and Assumption Agreement (QUIPs Agreements), dated as of November 15, 2002, by between NorthWestern Energy, LLC, as assignor, and NorthWestern Corporation, as assignee (incorporated by reference to Exhibit 4.2(q) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.2(r)*		Form of Amended and Restated Trust Agreement of Montana Power Capital I (incorporated by reference to Exhibit 4(b) of The Montana Power Company’s Registration Statement on Form S-3, dated October 18, 1996, Commission File No. 333-14369).
4.2(s)*		Subordinated Debt Securities Indenture, dated as of August 1, 1995, between NorthWestern Corporation and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4(f) of the Company’s Current Report on Form 8-K, dated August 30, 1995, Commission File No. 0-692).

Exhibit Number		Description of Document
4.2(t)*		First Supplemental Indenture to the Subordinated Debt Securities Indenture, dated as of August 1, 1995 (incorporated by reference to Exhibit 4(g) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 30, 1995, Commission File No. 0-692).
4.2(u)*		Second Supplemental Indenture to the Subordinated Debt Securities Indenture, dated as of November 15, 1998 (incorporated by reference to Exhibit 4(f) of NorthWestern Corporation’s Registration Statement on Form 8-A (Amendment No. 1), dated December 3, 1998, Commission File No. 001-14623).
4.2(v)*		Third Supplemental Indenture to the Subordinated Debt Securities Indenture, dated as of December 21, 2001 (incorporated by reference to Exhibit 4.6 of NorthWestern Corporation’s Registration Statement on Form 8-A, dated December 21, 2001, Commission File No. 001-16843).
4.2(w)*		Fourth Supplemental Indenture to the Subordinated Debt Securities Indenture, dated as of January 31, 2002 (incorporated by reference to Exhibit 4.6 of NorthWestern Corporation’s Registration Statement on Form 8-A, dated February 1, 2002, Commission File No. 001-31229).
4.2(x)*		Form of Indenture, between The Montana Power Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4(c) of The Montana Power Company’s Registration Statement on Form S-3, dated October 18, 1996, Commission File No. 333-14369).
4.2(y)*		First Supplemental Indenture to the Indenture, dated as of February 13, 2002, between The Montana Power, LLC and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.2(y) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.2(z)*		Second Supplemental Indenture to the Indenture, dated as of August 13, 2002, between The Montana Power, LLC and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.2(z) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.2(aa)*		Third Supplemental Indenture to the Indenture, dated as of November 15, 2002, between NorthWestern Corporation (successor to NorthWestern Energy, LLC, formerly known as The Montana Power, LLC) and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.2(aa) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.3(a)*		Indenture, dated as of November 1, 1998, between NorthWestern Corporation and The Chase Manhattan Bank, as Trustee (incorporated by reference to Exhibit 4(b)(8) of NorthWestern Corporation’s Registration Statement on Form S-3, dated July 12, 1999, Commission File No. 333-82707).
4.3(b)*		First Supplemental Indenture to the Indenture, dated as of November 1, 1998 (incorporated by reference to Exhibit 4(b)(9) of NorthWestern Corporation’s Registration Statement on Form S-3, dated July 12, 1999, Commission File No. 333-82707).
4.3(c)*		Second Supplemental Indenture to the Indenture, dated as of March 13, 2002 (filed as Exhibit 4(f)(3) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 0-692).
4.4(a)*		Sale Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Mercer County, North Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993 (incorporated by reference to Exhibit 4(b)(1) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).

Exhibit Number		Description of Document
4.4(b)*		Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Grant County, South Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993A (incorporated by reference to Exhibit 4(b)(2) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.4(c)*		Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Grant County, South Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993B (incorporated by reference to Exhibit 4(b)(3) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.4(d)*		Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and the City of Salix, Iowa, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993 (incorporated by reference to Exhibit 4(b)(4) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.4(e)*		Loan Agreement, dated as of May 1, 1993, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(e) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.4(f)*		1993A First Supplemental Loan Agreement, dated as of September 21, 2001, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(f) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.4(g)*		Assumption Agreement of The Montana Power, LLC to Bank One, as Trustee, dated as of February 13, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(g) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.4(h)*		Assignment and Assumption Agreement (PCRB 1993A Loan Agreement), between NorthWestern Energy, LLC, as Assignor, and NorthWestern Corporation, as Assignee, dated as of November 15, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(h) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692.
4.4(i)*		Loan Agreement, dated as of December 1, 1993, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993B due 2023 (incorporated by reference to Exhibit 4.4(i) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.4(j)*		1993B First Supplemental Loan Agreement, dated as of September 21, 2001, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(j) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.4(k)*		Assumption Agreement of The Montana Power, LLC to Bank One, as Trustee, dated as of February 13, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993B due 2023 (incorporated by reference to Exhibit 4.4(k) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.4(l)*		Assignment and Assumption Agreement (PCRB 1993B Loan Agreement), between NorthWestern Energy, LLC, as Assignor, and NorthWestern Corporation, as Assignee, dated as of November 15, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(l) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).

Exhibit Number		Description of Document
4.5(a)*		First Mortgage and Deed of Trust, dated as of October 1, 1945, by The Montana Power Company in favor of Guaranty Trust Company of New York and Arthur E. Burke, as trustees (incorporated by reference to Exhibit 7(e) of The Montana Power Company’s Registration Statement, Commission File No. 002-05927).
4.5(b)*		Thirteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of December 1, 1991 (incorporated by reference to Exhibit 4(a)—14 of The Montana Power Company’s Registration Statement on Form S-3, dated December 16, 1992, Commission File No. 033-55816).
4.5(c)*		Fourteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of January 1, 1993 (incorporated by reference to Exhibit 4(c) of The Montana Power Company’s Registration Statement on Form S-8, dated June 17, 1993, Commission File No. 033-64576).
4.5(d)*		Fifteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 1993 (incorporated by reference to Exhibit 4(d) of The Montana Power Company’s Registration Statement on Form S-8, dated June 17, 1993, Commission File No. 033-64576).
4.5(e)*		Sixteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of May 1, 1993 (incorporated by reference to Exhibit 99(a) of The Montana Power Company’s Registration Statement on Form S-3, dated September 13, 1993, Commission File No. 033-50235).
4.5(f)*		Seventeenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of December 1, 1993 (incorporated by reference to Exhibit 99(a) of The Montana Power Company’s Registration Statement on Form S-3, dated December 5, 1994, Commission File No. 033-56739).
4.5(g)*		Eighteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of August 5, 1994 (incorporated by reference to Exhibit 99(b) of The Montana Power Company’s Registration Statement on Form S-3, dated December 5, 1994, Commission File No. 033-56739).
4.5(h)*		Nineteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of December 16, 1999 (incorporated by reference to Exhibit 99 of The Montana Power Company’s Annual Report on Form 10-K for the year ended December 31, 2000, Commission File No. 001-04566).
4.5(i)*		Twentieth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of November 1, 2001 (incorporated by reference to Exhibit 4(u) of NorthWestern Energy, LLC’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 001-31276).
4.5(j)*		Twenty-first Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 13, 2002 (incorporated by reference to Exhibit 4(v) of NorthWestern Energy, LLC’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 001-31276).
4.5(k)*		Twenty-second Supplemental Indenture to the Mortgage and Deed of Trust, dated as of November 15, 2002 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).

Exhibit Number		Description of Document
4.5(l)*		Twenty-third Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 1, 2002 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
4.6(a)*		Form of Indenture, dated as of December 1, 1989, between The Montana Power Company and Citibank, N.A., as Trustee (incorporated by reference to Exhibit 4-A to The Montana Power Company’s Registration Statement on Form S-3, dated November 24, 1989, Commission File No. 033-32275).
4.6(b)*		First Supplemental Indenture to the Indenture, dated as of February 13, 2002 (incorporated by reference to Exhibit 4.6(b) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(c)*		Second Supplemental Indenture to the Indenture, dated as of November 15, 2002 (incorporated by reference to Exhibit 4.6(c) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.7(a)*		Natural Gas Funding Trust Indenture, dated as of December 22, 1998, between MPC Natural Gas Funding Trust, as Issuer, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.7(a) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.7(b)*		Natural Gas Funding Trust Agreement, dated as of December 11, 1998, among The Montana Power Company, Wilmington Trust Company, as trustee, and the Beneficiary Trustees party thereto (incorporated by reference to Exhibit 4.7(b) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.7(c)*		Transition Property Purchase and Sale Agreement, dated as of December 22, 1998, between MPC Natural Gas Funding Trust and The Montana Power Company (incorporated by reference to Exhibit 4.7(c) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.7(d)*		Transition Property Servicing Agreement, dated as of December 22, 1998, between MPC Natural Gas Funding Trust and The Montana Power Company (incorporated by reference to Exhibit 4.7(d) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.7(e)*		Assumption Agreement regarding the Transition Property Purchase Agreement and the Transition Property Servicing Agreement, dated as of February 13, 2002, by The Montana Power, LLC to MPC Natural Gas Funding Trust (incorporated by reference to Exhibit 4.7(e) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.7(f)*		Assignment and Assumption Agreement (Natural Gas Transition Documents), dated as of November 15, 2002, by and between NorthWestern Energy, LLC, as assignor, and NorthWestern Corporation, as assignee (incorporated by reference to Exhibit 4.7(f) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.8(a)*		Rights Agreement, dated as of December 11, 1996, between NorthWestern Corporation and Norwest Bank Minnesota, N.A. as Rights Agent (incorporated by reference to Exhibit 4(c)(5) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, Commission File No. 0-692).
4.8(b)*		First Amendment to Rights Agreement, dated as of August 21, 2000, between NorthWestern Corporation and Wells Fargo Bank Minnesota, N.A., (formerly Norwest Bank Minnesota, N.A.), as Rights Agent (incorporated by reference to Exhibit 4(c)(6) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000).
10.1(a)†*		NorthWestern Corporation Traditional Pension Equalization Plan, as amended and restated, effective as of January 1, 2000 (incorporated by reference to Exhibit 10(a)(2) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, Commission File No. 0-692).
10.1(b)†*		NorthWestern Corporation Cash Balance Supplemental Executive Retirement Plan, effective as of January 1, 2000 (incorporated by reference to Exhibit 10(a)(3) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, Commission File No. 0-692).

Exhibit Number		Description of Document
10.1(c)†*		NorthSTAR Annual Incentive Plan, for all eligible employees, as amended as of May 4, 1999 (incorporated by reference to Exhibit 10(a)(4) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, Commission File No. 0-692).
10.1(d)†*		NorthWestern Executive Performance Plan, effective as of May 2, 2000 (incorporated by reference to Exhibit 10(a)(5) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, Commission File No. 0-692).
10.1(e)†*		NorthWestern Stock Option and Incentive Plan, as amended as of January 16, 2001 (incorporated by reference to Exhibit 10(a)(6) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, Commission File No. 0-692)
10.1(f)†*		Deferred Compensation Plan for Non-employee Directors, adopted as of November 6, 1985 (incorporated by reference to Exhibit 10(g)(2) of NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 1988, Commission File No. 0-692).
10.1(g)†*		Supplemental Variable Investment Plan, as amended and restated as of January 1, 2000 (filed as Exhibit 10(a)(7) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 0-692).
10.1(h)†*		Retirement Agreement, effective as of December 31, 2002, by and between NorthWestern Corporation and Merle D. Lewis (incorporated by reference to Exhibit 10.1(i) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
10.1(i)†*		Comprehensive Employment Agreement and Equity Plan Participation Program for Richard R. Hylland, dated as of March 1, 2001 (incorporated by reference to Exhibit 10.2 of NorthWestern Corporation’s Current Report on Form 8-K/A (Amendment No. 1), dated December 14, 2001, Commission File No. 0-692).
10.1(j)†*		Comprehensive Employment Agreement and Equity Plan Participation Program for Michael J. Hanson, dated as of March 1, 2001 (incorporated by reference to Exhibit 10.4 of NorthWestern Corporation’s Current Report on Form 8-K/A (Amendment No. 1), dated December 14, 2001, Commission File No. 0-692).
10.1(k)†*		Supplemental Income Security Plan for Directors, Officers and Managers, as amended and restated effective as of July 1, 1999 (incorporated by reference to Exhibit 10.8 of NorthWestern Corporation’s Current Report on Form 8-K/A (Amendment No. 1), dated December 14, 2001, Commission File No. 0-692).

Exhibit Number		Description of Document
10.1(l)†*		Form of “Tier 1” Termination Benefits Upon Change in Control Agreement (incorporated by reference to Exhibit 10(a) of The Montana Power Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, Commission File No. 1-4566).
10.1(m)†*		Form of “Tier 2” Termination Benefits Upon Change in Control Agreement (incorporated by reference to Exhibit 10(b) of The Montana Power Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, Commission File No. 1-4566).
10.1(n)†*		Form of “Tier 3” Termination Benefits Upon Change in Control Agreement (incorporated by reference to Exhibit 10(c) of The Montana Power Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, Commission File No. 1-4566).
10.1(o) †**		Memorandum of Engagement with William M Austin as Chief Restructuring Officer, as amended and approved by the Bankruptcy Court in its Order dated October 10, 2003.
10.1(p) †**		Employment Agreement with Brian B. Bird as Chief Financial Officer, as amended and approved by the Bankruptcy Court in its Order dated January 13, 2004.
10.1(q) †**		Memorandum of Engagement between Daniel K. Newell and Blue Dot Services Inc., dated November 6, 2003.
10.1(r) †**		NorthWestern Corporation Incentive Compensation and Severance Plan.
10.1(s)†*		NorthWestern Capital Partners LLC Limited Liability Company Agreement, dated as of September 30, 1999 (incorporated by reference to Exhibit 10.1(r) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
10.1(t)†*		Form of Put Option Agreement, dated as of September 30, 1999 (incorporated by reference to Exhibit 10.1(s) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
10.2(a)*		Credit Agreement, dated as of January 14, 2002, among NorthWestern Corporation, Credit Suisse First Boston, ABN AMRO Bank N.V., CIBC Inc. and Barclays Capital Inc., as co-arrangers, Credit Suisse First Boston, as administrative agent, lead arranger and sole book runner, and the banks and other financial institutions parties thereto (filed as Exhibit 10(b)(1) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 0-692).
10.2(b)*		Amendment No. 1 to Credit Agreement, dated as of June 20, 2002, among NorthWestern Corporation, Credit Suisse First Boston, ABN AMRO Bank N.V., CIBC Inc. and Barclays Capital Inc., as co-arrangers, Credit Suisse First Boston, as administrative agent, lead arranger and sole book runner, and the banks and other financial institutions parties thereto (incorporated by reference to Exhibit 10.2(c) of Amendment No. 1 to NorthWestern Corporation’s Registration Statement on Form S-4, dated July 12, 2002, Commission File No. 333-86888).
10.2(c)*		Amendment No. 2 to Credit Agreement, dated as of August 13, 2002, among NorthWestern Corporation, Credit Suisse First Boston, ABN AMRO Bank N.V., CIBC Inc. and Barclays Capital Inc., as co-arrangers, Credit Suisse First Boston, as administrative agent, lead arranger and sole book runner, and the banks and other financial institutions parties thereto (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 0-692.)
10.2(d)*		Credit Agreement, dated as of December 17, 2002, between NorthWestern Corporation and Credit Suisse First Boston, as administrative agent, lead arranger and sole book runner (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
10.2(e)*		Amendment No. 1 to Credit Agreement, dated as of January 8, 2003, between NorthWestern Corporation and Credit Suisse First Boston, as administrative agent, lead arranger and sole book runner (incorporated by reference to Exhibit 99.3 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).

Exhibit Number		Description of Document
10.2(f)*		Amendment No. 2 to Credit Agreement, dated as of February 10, 2003, among NorthWestern Corporation, Credit Suisse First Boston, as administrative agent, lead arranger and sole book runner, and the banks and other financial institutions parties thereto (incorporated by reference to Exhibit 99.4 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
10.2(g)*		Bond Collateral Agreement, dated as of February 10, 2003, between NorthWestern Corporation and Credit Suisse First Boston, acting through its Cayman Islands Branch, as collateral agent (incorporated by reference to Exhibit 99.5 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
10.2(h)**		Secured Superpriority Debtor in Possession Credit and Guaranty Agreement, dated September 19, 2003, among NorthWestern Corporation a Debtor and Debtor in Possession, as Borrower, and the Other Loan Parties as Guarantors, the Lenders herein from time to time, and Bank One N.A. and Banc One Capital Markets, Inc. as Lead Arranger and Sole Book Runner.
10.2(i)**		Amended and Restated Credit Agreement among NorthWestern Corporation, Credit Suisse First Boston, as administrative agent, lead arranger and sole book runner, and the banks and other financial institutions parties thereto, dated January 13, 2004.
10.3(a)*		Credit and Security Agreement, dated as of March 31, 2001, between Expanets, Inc. and Avaya Inc. (and NorthWestern Corporation with respect to Section 7.3 only) (filed as Exhibit 10(d)(1) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001 Commission File No. 0-692).
10.3(b)*		First Amendment to Credit and Security Agreement, dated as of August 1, 2001, between Expanets, Inc. and Avaya Inc. (acknowledged by NorthWestern Corporation) (filed as Exhibit 10(d)(2) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001. Commission File No. 0-692).
10.3(c)*		Second Amendment to Credit and Security Agreement; Amendment to Collateral Agreements, dated as of March 5, 2002, between Expanets, Inc. (and several affiliates of Expanets) and Avaya Inc. (and NorthWestern Corporation with respect to Sections 1(h) and 7 only) (filed as Exhibit 10(d)(3) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 0-692).
10.3(d)*		Third Amendment to Credit and Security Agreement, dated as of March 5, 2003, between Expanets, Inc. (and several affiliates of Expanets) and Avaya Inc. (and NorthWestern Corporation with respect to Sections 1 and 6 only) (incorporated by reference to Exhibit 10.3(d) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
10.3(e)**		Asset Purchase and Sale Agreement, dated October 29, 2003, Agreement among Expanets, Inc., NorthWestern Corporation, NorthWestern Growth Corporation, NorthWestern Capital Corporation and Avaya, Inc.
10.3(f)**		Amendment No. 1 to Asset Purchase and Sale Agreement dated October 29, 2003, Agreement among Expanets, Inc., NorthWestern Corporation, NorthWestern Growth Corporation, NorthWestern Capital Corporation and Avaya, Inc.
10.4(a)*		Credit and Security Agreement, dated as of August 30, 2002, between Blue Dot Services Inc. and U.S. Bank, N.A. (incorporated by reference to Exhibit 10.4(a) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
12.1**		Statement Regarding Computation of Earnings to Fixed Charges.
21**		Subsidiaries of NorthWestern Corporation.
23.1**		Independent Auditors' Consent
24**		Power of Attorney (included on the signature page of this Annual Report on Form 10-K)
31.1**		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2**		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32.1**		Certification of Gary G. Drook pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Brian B. Bird pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

† Management contract or compensatory plan or arrangement.

* Incorporated by reference.

** Filed herewith.

All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are not applicable, and, therefore, have been omitted.

(b) Reports on Form 8-K

We filed a Current Report on Form 8-K with the SEC on October 30, 2003, to disclose under Item 5 of the Report that we issued a press release announcing that we had entered into a sale agreement with Avaya, Inc.(NYSE: AV) for substantially all of the assets of our Expanets communications services unit.

We filed a Current Report on Form 8-K with the SEC on November 13, 2003, to disclose under Item 5 of the Report that we issued a press release announcing that Daniel K. Newell has resigned as senior vice president of NorthWestern.

We filed a Current Report on Form 8-K with the SEC on November 14, 2003, to disclose under Item 5 of the Report that we issued a press release discussing operating results for the third quarter of 2003. The press release also discussed NorthWestern’s previously announced Chapter 11 filing and provided an update on recent sales of assets by Expanets, Inc. and Blue Dot Services, Inc., subsidiaries of NorthWestern.

We filed a Current Report on Form 8-K with the SEC on November 20, 2003, to disclose under Item 5 of the Report that we issued a press release announcing that Brian B. Bird has been named our Chief Financial Officer, effective December 1, 2003.

We filed a Current Report on Form 8-K with the SEC on November 26, 2003, to disclose under Item 5 of the Report that we issued a press release announcing that we had completed the sale of substantially all of the assets of our Expanets communications services unit to Avaya, Inc. (NYSE: AV).

We filed a Current Report on Form 8-K with the SEC on December 18, 2003, to disclose under Item 5 of the Report that we issued a press release announcing that Roger P. Schrum had been elected Vice President of Human Resources and Communications.

We filed a Current Report on Form 8-K with the SEC on December 31, 2003, to disclose under Item 5 of the Report that we issued a press release announcing that the U.S. Securities and Exchange Commission had issued subpoenas to Blue Dot Services Inc. and Expanets, Inc. requesting the production of documents as part of a now formal investigation of NorthWestern.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

	NorthWestern Corporation
Dated: March 15, 2004	By:	/s/ GARY G. DROOK
		Gary G. Drook
		President and Chief Executive Officer

POWER OF ATTORNEY

We, the undersigned directors and/or officers of NorthWestern Corporation, hereby severally constitute and appoint Gary G. Drook and Eric R. Jacobsen, and each of them with full power to act alone, our true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution and revocation, for each of us and in our name, place, and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, and hereby grant unto such attorneys-in-fact and agents, and each of them, the full power and authority to do each and every act and thing requisite and necessary to be done in and about the foregoing, as fully to all intents and purposes as each of us might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their respective substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ MARILYN R. SEYMANN	Chairman of the Board	March 15, 2004
Marilyn R. Seymann

/s/ GARY G. DROOK	President and Chief Executive Officer and Director	March 15, 2004
Gary G. Drook	(Principal Executive Officer)

/s/ BRIAN B. BIRD	Chief Financial Officer	March 15, 2004
Brian B. Bird	(Principal Financial Officer)

/s/ KENDALL G. KLIEWER	Chief Accountant and Director of Financial Reporting	March 15, 2004
Kendall G. Kliewer	(Principal Accounting Officer)

Signature	Title	Date

/s/ RANDY G. DARCY	Director	March 15, 2004
Randy G. Darcy

/s/ JERRY W. JOHNSON	Director	March 15, 2004
Jerry W. Johnson

/s/ LARRY F. NESS	Director	March 15, 2004
Larry F. Ness

/s/ BRUCE I. SMITH	Director	March 15, 2004
Bruce I. Smith

/s/ LAWRENCE J. RAMAEKERS	Director	March 15, 2004
Lawrence J. Ramaekers

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

	Page
Financial Statements
Independent Auditors' Report	F-2
Consolidated statements of income (loss) for the years ended December 31, 2003, 2002 and 2001	F-3
Consolidated statements of cash flows for the years ended December 31, 2003, 2002 and 2001	F-4
Consolidated balance sheets as of December 31, 2003 and 2002	F-5
Consolidated statements of common shareholders’ equity (deficit) for the years ended December 31, 2003, 2002 and 2001	F-6
Notes to consolidated financial statements	F-8
Financial Statement Schedules
Independent Auditors' Report	F-43
Schedule II. Valuation and Qualifying Accounts	F-44

F - 1

INDEPENDENT AUDITORS' REPORT

To the Shareholders and Board of Directors of NorthWestern Corporation:

We have audited the accompanying consolidated balance sheets of NORTHWESTERN CORPORATION (a Delaware corporation) (Debtor-in-Possession) AND SUBSIDIARIES as of December 31, 2003 and 2002, and the related consolidated statements of income (loss), common shareholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of NorthWestern Corporation management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of NorthWestern Corporation and Subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1, NorthWestern Corporation filed for reorganization under Chapter 11 of the Federal Bankruptcy Code on September 14, 2003. The accompanying financial statements do not purport to reflect or provide for the consequences of the bankruptcy proceedings. In particular, such financial statements do not purport to show (a) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (b) as to prepetition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (c) as to shareholder accounts, the effect of any changes that may be made in the capitalization of NorthWestern Corporation and Subsidiaries; or (d) as to operations, the effect of any changes that may be made in its business.

The accompanying financial statements have been prepared assuming that NorthWestern Corporation and Subsidiaries will continue as a going concern. As discussed in Note 3, NorthWestern Corporation and Subsidiaries’ recurring losses from operations, negative working capital, shareholders’ deficit, and defaults under terms of its long-term debt agreements raise substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 3. The financial statements do not include adjustments that might result from the outcome of this uncertainty.

As discussed in Note 4, NorthWestern Corporation and Subsidiaries changed its methods of accounting for asset retirement obligations and its company obligated mandatorily redeemable preferred securities in 2003 and, as discussed in Note 6, changed its method of accounting for goodwill and other intangible assets in 2002.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
March 15, 2004

F - 2

NORTHWESTERN CORPORATION, A DEBTOR-IN-POSSESSION

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(in thousands, except per share amounts)

	YEAR ENDED DECEMBER 31
	2003			2002			2001

OPERATING REVENUES	$	1,027,437		$	783,744		$	255,151
COST OF SALES	550,589			341,526			145,568
GROSS MARGIN	476,848			442,218			109,583
OPERATING EXPENSES
Operating, general and administrative	307,258			268,218			61,730
Impairment on assets held for sale	12,399			35,729			—
Depreciation	70,252			63,240			17,923
Amortization of goodwill and other intangibles	—			19			269
Restructuring charge	—			—			11,771
Reorganization professional fees and expenses	8,280			—			—
TOTAL OPERATING EXPENSES	398,189			367,206			91,693
OPERATING INCOME	78,659			75,012			17,890
Interest Expense (contractual interest of $176,926 for the year ended 12/31/03)	(147,626		)	(98,010		)	(27,709		)
Gain (Loss) on Debt Extinguishment	3,300			(20,688		)	—
Investment Income and Other	(5,977		)	(5,481		)	7,134
Reorganization Interest Income	14			—			—
Loss From Continuing Operations Before Income Taxes	(71,630		)	(49,167		)	(2,685		)
Benefit for Income Taxes	48			39,811			6,860
Income (Loss) From Continuing Operations	(71,582		)	(9,356		)	4,175
Discontinued Operations, Net of Taxes and Minority Interests	(42,143		)	(854,586		)	40,357
Net Income (Loss)	(113,725		)	(863,942		)	44,532
Minority Interests on Preferred Securities of Subsidiary Trusts	(14,945		)	(28,610		)	(6,827		)
Dividends and Redemption Premium on Preferred Stock	—			(391		)	(191		)
Earnings (Losses) on Common Stock	$	(128,670	)	$	(892,943	)	$	37,514

Average Common Shares Outstanding	37,397			29,726			24,390
Basic Earnings (Loss) per Average Common Share
Continuing operations	$	(2.31	)	$	(1.29	)	$	(0.11	)
Discontinued operations	(1.13		)	(28.75		)	1.65
Basic	$	(3.44	)	$	(30.04	)	$	1.54

Diluted Earnings (Loss) per Average Common Share
Continuing operations	$	(2.31	)	$	(1.29	)	$	(0.12	)
Discontinued operations	(1.13		)	(28.75		)	1.65
Diluted	$	(3.44	)	$	(30.04	)	$	1.53

Dividends Declared per Average Common Share	—			$	1.27		$	1.21

See Notes to Consolidated Financial Statements

F - 3

NORTHWESTERN CORPORATION, A DEBTOR-IN-POSSESSION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	YEAR ENDED DECEMBER 31
	2003			2002			2001

Operating Activities:
Net Income (Loss)	$	(113,725	)	$	(863,942	)	$	44,532
Items not affecting cash:
Depreciation and amortization	70,252			63,259			18,192
Amortization of debt issue costs	13,935			6,655			314
(Gain) Loss on debt extinguishment	(3,300		)	20,688			—
Impairment on assets held for sale	12,399			35,729			—
(Income) Loss on discontinued operations, net of taxes	42,143			854,586			(40,357		)
Impairment of note receivable	9,073			—			—
Deferred income taxes	10,334			(8,761		)	(20,891		)
(Gain) Loss on property, plant and equipment and investments	(1,468		)	13,984			(2,256		)
Changes in current assets and liabilities, net of acquisitions:
Restricted cash	996			4,330			(2,369		)
Accounts receivable	(14,636		)	4,864			8,624
Inventories	(614		)	12,545			55
Prepaid energy supply costs	(62,445		)	—			—
Other current assets	7,804			19,233			954
Accounts payable	22,443			6,384			(16,815		)
Accrued expenses	(303		)	(1,816		)	35,901
Changes in regulatory assets	(3,069		)	(74,095		)	(369		)
Changes in regulatory liabilities	(23,557		)	(31,276		)	—
Other noncurrent liabilities	(55,364		)	34,708			20,437
Other, net	(16,571		)	28,482			(29,530		)
Cash flows (used in) provided by continuing operations	(105,673		)	125,557			16,422
Change in net assets of discontinued operations	11,813			(195,421		)	(141,751		)
Cash flows used in operating activities	(93,860		)	(69,864		)	(125,329		)
Investing Activities:
Property, plant, and equipment additions	(70,737		)	(147,847		)	(80,295		)
Proceeds from sale of assets	2,743			8,579			—
Sale (purchase) of noncurrent investments and assets, net	72,926			899			(433		)
Acquisitions, net of cash received	—			(502,765		)	—
Cash flows provided by (used in) investing activities	4,932			(641,134		)	(80,728		)
Financing Activities:
Dividends on common and preferred stock	—			(38,081		)	(29,956		)
Minority interest on preferred securities of subsidiary trusts	(9,720		)	(28,610		)	(6,827		)
Redemption of preferred stock	—			(4,028		)	—
Proceeds from issuance of common stock	—			81,031			74,868
Issuance of long term debt	397,200			721,970			—
Issuance of preferred securities of subsidiary trust, net	—			117,750			100,000
Repayment of long-term debt	(26,979		)	(213,587		)	(5,259		)
Line of credit borrowings, net	(255,000		)	123,000			74,303
Repayment of discontinued operations debt	—			(26,059		)	—
Treasury stock activity	—			121			—
Financing costs	(27,944		)	(25,813		)	(6,936		)
Proceeds from termination of hedge	—			24,898			—
Cash flows provided by financing activities	77,557			732,592			200,193
Increase (Decrease) in Cash and Cash Equivalents	(11,371		)	21,594			(5,864		)
Cash and Cash Equivalents, beginning of period	26,554			4,960			10,824
Cash and Cash Equivalents, end of period	$	15,183		$	26,554		$	4,960

See Notes to Consolidated Financial Statements

F - 4

NORTHWESTERN CORPORATION, A DEBTOR-IN-POSSESSION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	December 31, 2003			December 31, 2002

ASSETS
Current Assets:
Cash and cash equivalents	$	15,183		$	26,554
Restricted cash	27,043			28,039
Accounts receivable, net	106,443			91,807
Inventories	26,521			25,907
Regulatory assets	23,145			28,096
Prepaid energy supply	63,108			663
Other	32,838			40,642
Assets held for sale	30,000			42,665
Current assets of discontinued operations	106,197			275,549
Total current assets	430,478			559,922
Property, Plant, and Equipment, Net	1,362,749			1,353,543
Goodwill	375,798			375,798
Other:
Investments	11,027			85,236
Regulatory assets	202,174			194,154
Other	61,979			51,438
Noncurrent assets of discontinued operations	306			164,970
Total assets	$	2,444,511		$	2,785,061

LIABILITIES AND SHAREHOLDERS’ DEFICIT
Liabilities Not Subject to Compromise
Current Liabilities:
Current maturities of long-term debt	$	919,392		$	25,909
Accounts payable	67,602			49,704
Accrued expenses	104,594			161,224
Regulatory liabilities	702			33,536
Current liabilities of discontinued operations	44,496			243,551
Total current liabilities	1,136,786			513,924
Long-term Debt	—			1,642,522
Deferred Income Taxes	10,536			202
Noncurrent Regulatory Liabilities	152,851			143,574
Other Noncurrent Liabilities	210,094			487,162
Noncurrent Liabilities and Minority Interests of Discontinued Operations	1,998			83,003
Total liabilities not subject to compromise	1,512,265			2,870,387
Liabilities Subject to Compromise
Financing Debt	864,844			—
Trade Creditors	287,803			—
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts	365,550			—
Total liabilities subject to compromise	1,518,197			—
Total liabilities	3,030,462			2,870,387
Minority Interests	—			500
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts	—			370,250
Shareholders’ Deficit:
Common stock, par value $1.75; authorized 50,000,000 shares; issued and outstanding 37,680,095 and 37,396,762	65,940			65,444
Paid-in capital	301,455			304,781
Treasury stock, at cost	—			(3,560		)
Retained deficit	(947,274		)	(818,604		)
Accumulated other comprehensive loss	(6,072		)	(4,137		)
Total shareholders’ deficit	(585,951		)	(456,076		)
Total liabilities and shareholders’ deficit	$	2,444,511		$	2,785,061

See Notes to Consolidated Financial Statements

F - 5

NORTHWESTERN CORPORATION, A DEBTOR-IN-POSSESSION

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY (DEFICIT)

(in thousands)

	Number of Common Shares	Number of Treasury Shares	Common Stock		Paid in Capital		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity (Deficit)
	(in thousands)
Balance at December 31, 2000	23,411	—	$	40,968	$	165,932	$	—		$	111,355		$	1,294		$	319,549

Net income	—	—	$	—	$	—	$	—		$	44,532		$	—		$	44,532
Other comprehensive income (loss), net of tax:
Unrealized loss on marketable securities net of reclassification adjustment	—	—	—		—		—			—			(2,081		)	(2,081		)
Issuances of common stock	3,714	—	6,498		68,370		—			—			—			74,868
Cashless exercise of warrants	272	—	476		6,321		—			(6,797		)	—
Amortization of unearned restricted stock compensation	—	—	—		174		—			—			—			174
Treasury stock activity	—	156	—		—		(3,681		)	—			—			(3,681		)
Distributions on minority interests in preferred securities of subsidiary trusts	—	—	—		—		—			(6,827		)	—			(6,827		)
Dividends on preferred stock	—	—	—		—		—			(191		)	—			(191		)
Dividends on common stock	—	—	—		—		—			(29,765		)	—			(29,765		)
Balance at December 31, 2001	27,397	156	$	47,942	$	240,797	$	(3,681	)	$	112,307		$	(787	)	$	396,578

Net loss	—	—	$	—	$	—	$	—		$	(863,942	)	$	—		$	(863,942	)
Other comprehensive income (loss), net of tax:
Unrealized gain on marketable securities net of reclassification adjustment	—	—	—		—		—			—			1,139			1,139
Foreign currency translation adjustments	—	—	—		—		—			—			5			5
Gain on hedge termination	—	—	—		—		—			—			5,072			5,072
Amortization of hedge gain	—	—	—		—		—			—			(807		)	(807		)
Minimum pension liability	—	—	—		—		—			—			(8,759		)	(8,759		)
Issuances of common stock	10,000	—	17,502		63,529		—			—			—			81,031
Amortization of unearned restricted stock compensation	—	—	—		455		—			—			—			455
Treasury stock activity	—	18	—		—		121			—			—			121
Distributions on minority interests in preferred securities of subsidiary trusts	—	—	—		—		—			(28,610		)	—			(28,610		)
Dividends on preferred stock	—	—	—		—		—			(112		)	—			(112		)
Redemption premium on preferred stock	—	—	—		—		—			(278		)	—			(278		)
Dividends on common stock	—	—	—		—		—			(37,969		)	—			(37,969		)
Balance at December 31, 2002	37,397	174	$	65,444	$	304,781	$	(3,560	)	$	(818,604	)	$	(4,137	)	$	(456,076	)

F - 6

	Number of Common Shares	Number of Treasury Shares		Common Stock		Paid in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity (Deficit)
	(in thousands)
Balance at December 31, 2002	37,397	174		$	65,444	$	304,781		$	(3,560	)	$	(818,604	)	$	(4,137	)	$	(456,076	)

Net loss	—	—		$	—	$	—		$	—		$	(113,725	)	$	—		$	(113,725	)
Other comprehensive income (loss), net of tax:
Unrealized loss on marketable securities net of reclassification adjustment	—	—		—		—			—			—			(352		)	(352		)
Foreign currency translation adjustments	—	—		—		—			—			—			298			298
Amortization of hedge gain	—	—		—		—			—			—			(416		)	(416		)
Minimum pension liability	—	—		—		—			—			—			(1,465		)	(1,465		)
Issuances of restricted stock	283	—		496		(496		)	—			—			—			—
Amortization of unearned restricted stock compensation	—	—		—		266			—			—			—			266
Treasury stock activity	—	(174	)	—		(3,096		)	3,560			—			—			464
Distributions on minority interests in preferred securities of subsidiary trusts	—	—		—		—			—			(14,945		)	—			(14,945		)
Balance at December 31, 2003	37,680	—		$	65,940	$	301,455		$	—		$	(947,274	)	$	(6,072	)	$	(585,951	)

See Notes to Consolidated Financial Statements

F - 7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Management’s Statement

The consolidated financial statements for the periods included herein have been prepared by NorthWestern Corporation (the “Corporation”, “Debtor” or “we”), a debtor-in-possession, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates.

On September 14, 2003 (the “Petition Date”), we filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). Pursuant to Chapter 11 (as discussed further in Note 3), we retain control of our assets and are authorized to operate our business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Included in the consolidated financial statements are subsidiaries that are not party to the Chapter 11 case and are not debtors. The assets and liabilities of such nondebtor subsidiaries are not considered to be material to the consolidated financial statements or are included in discontinued operations.

Beginning in the third quarter of 2003, the consolidated financial statements have been prepared in accordance with the American Institute of Certified Public Accountants’ Statement of Position (SOP) 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code, and on a going-concern basis, which contemplates continuity of operation, realization of assets, and liquidation of liabilities in the ordinary course of business. As a result of our Chapter 11 filing, the realization of assets and liquidation of liabilities are subject to uncertainty. Under SOP 90-7, certain liabilities existing prior to the Chapter 11 filing are classified as Liabilities Subject to Compromise on the Consolidated Balance Sheets. Additionally, professional fees and expenses directly related to the Chapter 11 proceeding and interest income on funds accumulated during the Chapter 11 proceedings are reported separately as reorganization items. Finally, the extent to which our reported interest expense differs from the stated contractual interest is disclosed on the Consolidated Statements of Income (Loss).

(2) Nature of Operations and Basis of Consolidation

We are one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 608,000 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. On February 15, 2002, we completed the acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company, or Montana Power. As a result of the acquisition, from February 15, 2002 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 the electric and natural gas transmission and distribution operations of NorthWestern Energy, LLC to NorthWestern Corporation, and since that date, we have operated its 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. The former NorthWestern Energy, LLC has been renamed “Clark Fork and Blackfoot, LLC.”

We also have made investments in three primary nonenergy businesses: Netexit, Inc., (f/k/a Expanets, Inc.,) or Expanets, a provider of networked communications and data services and solutions to small to mid-sized businesses; Blue Dot Services Inc., or Blue Dot, a provider of air conditioning, heating, plumbing and related services; and, through November 1, 2002, we held an economic equity interest in a subsidiary that serves as the managing general partner of CornerStone Propane Partners, LP, or CornerStone, a publicly traded limited partnership that is a retail propane and wholesale energy related commodities distributor.

The accompanying consolidated financial statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. The financial statements of Expanets, Blue Dot and CornerStone (CornerStone is only through November 1, 2002) are included in the accompanying consolidated financial statements by virtue of the voting and control rights, and therefore included in references to “subsidiaries.” Expanets and Blue Dot are not party to our Chapter 11 case. All significant intercompany balances and transactions have been eliminated from the consolidated financial statements. The operations of Expanets, Blue Dot and CornerStone and our interest in these subsidiaries have been reflected in the consolidated financial statements as Discontinued Operations (see Note 8 for further discussion). On November 25, 2003, we completed the sale of substantially all the assets and business of Expanets, and the assumption of specified liabilities, to Avaya, Inc. At that time, Expanets was renamed Netexit, Inc.

F - 8

(3) Chapter 11 Filing

As a result of our Chapter 11 filing, we operate our business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code, the Federal Rules of Bankruptcy Procedure and applicable court orders. All vendors are being paid for all goods furnished and services provided after the Petition Date while under the supervision of the bankruptcy court. As a debtor-in-possession, we are authorized to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the approval of the Court, after notice and an opportunity for a hearing.

On September 16, 2003, following first day hearings held on September 15, 2003, the Bankruptcy Court entered orders granting us authority to, among other things, pay prepetition and postpetition employee wages, salaries, benefits and other employee obligations, pay selected vendors and other providers for the postpetition delivery of goods and services, continue bank accounts and existing cash management system, and continue existing forward power contracts and enter into additional similar contracts in the ordinary course of business. On November 7, 2003, the Bankruptcy Court entered a final order to approve access of up to $85 million of the $100 million debtor-in-possession financing facility arranged by the company with Bank One, N.A. In December 2003, we reduced the commitment to $85 million under this Facility. The DIP Facility expires on September 12, 2004, and bears interest at a variable rate tied to the Eurodollar rate plus a spread of 3.00% or at the prime rate plus a spread of 1.00%. The DIP Facility will provide a source of liquidity during the course of our bankruptcy, but requires that we maintain certain other financial covenants and restricts liens, indebtedness, capital expenditures, dividend payments and sales of assets. As of December 31, 2003, there were $15.2 million in letters of credit outstanding and no borrowings under the DIP Facility.

The consolidated financial statements have been prepared on a “going concern” basis in accordance with GAAP. The “going concern” basis of presentation assumes that we will continue in operation for the foreseeable future and will be able to realize our assets and discharge our liabilities in the normal course of business. Because of the Chapter 11 case and the circumstances leading to the filing thereof, our ability to continue as a “going concern” is subject to substantial doubt and is dependent upon, among other things, confirmation of a plan of reorganization, our ability to comply with the terms of the DIP Facility, and our ability to generate sufficient cash flows from operations, asset sales and financing arrangements to meet our obligations. There can be no assurance that this can be accomplished and if it were not, our ability to realize the carrying value of our assets and discharge our liabilities would be subject to substantial uncertainty. Therefore, if the “going concern” basis were not used for the Financial Statements, then significant adjustments could be necessary to the carrying value of assets and liabilities, the revenues and expenses reported, and the balance sheet classifications used.

(4) Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncollectible accounts, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better information or when we can determine actual amounts. Those revisions can affect operating results.

Revenue Recognition

For our 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. For our Montana operations, as prescribed by the MPSC, operating revenues are recorded monthly on the basis of consumption or services rendered. Customers are billed monthly on a cycle basis.

F - 9

Cash Equivalents

We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.

Restricted Cash

Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.

Accounts Receivable, Net

Accounts receivable are net of $2.0 million and $1.8 million of allowances for uncollectible accounts at December 31, 2003 and 2002. Receivables include accrued unbilled revenues of $40.7 million and $30.6 million at December 31, 2003 and 2002.

Inventories

Inventories are stated at the lower of cost or market, with cost determined using the average cost method.

Regulatory Assets and Liabilities

Our regulated operations are subject to the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). Regulatory assets represent probable future revenue associated with certain costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process.

If all or a separable portion of our operations becomes no longer subject to the provisions of SFAS No. 71, an evaluation of future recovery of the related regulatory assets and liabilities would be necessary. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets.

Investments

Investments consisted of the following at December 31 (in thousands):

December 31, 2003
Life insurance contracts and other investments	$	11,027

December 31, 2002
Preferred stocks	$	19,692
Fixed Income securities	27,548
Life insurance contracts and other investments	37,996
	$	85,236

Life insurance contracts are carried at their cash surrender value. We also have investments in various money market accounts and other items. Investments in life insurance contracts of $3.6 million and $22.2 million are held in trust and restricted for postretirement benefits as of December 31, 2003 and 2002, respectively. Investments in money market accounts of $3.6 million and $3.8 million are restricted to satisfy certain debt requirements as of December 31, 2003 and 2002, respectively. Fixed income securities and preferred stocks are carried at market value, which approximates cost at December 31, 2002. Approximately $30 million of our fixed income securities and preferred stock investments are restricted as collateral for letters of credit as of December 31, 2002.

We use the specific identification method for determining the cost basis of our investments in available-for-sale securities. Realized gains and (losses) on our available-for-sale securities were $0.4 million, $(7.5) million and $2.3 million in 2003, 2002 and 2001, respectively.

Derivative Financial Instruments

We manage risk using derivative financial instruments for changes in electric and natural gas supply prices and interest rate fluctuations.

We periodically use commodity futures contracts to reduce the risk of future price fluctuations for electric and natural gas

F - 10

contracts. Increases or decreases in contract values are reported as gains and losses in our Consolidated Statements of Income (Loss) unless the commodities are specifically subject to supply tracking mechanisms within the regulatory environment.

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 original notes to floating interest rates at the three-month LIBOR 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 proceeds and a deferred gain to the Company. The deferred gain is recorded in Other Noncurrent Liabilities. As the deferred gain relates to unsecured notes, we have suspended recognition pending outcome of the bankruptcy.

On March 8, 2002, we settled a cash flow hedge agreement related to an interest rate swap instrument. The settlement resulted in proceeds of $7.9 million, and a deferred gain to the Company. The deferred gain is recorded in Other Comprehensive Income and recognition has been suspended pending outcome of the bankruptcy.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. We include in property, plant and equipment external and incremental internal costs associated with computer software developed for use in the businesses. Capitalization begins when the preliminary design stage of the project is completed. These costs are amortized on a straight-line basis over the project’s estimated useful life once the installed software is ready for its intended use. There were no costs capitalized in 2003 for internally developed software. During 2002 and 2001, we capitalized costs for internally developed software of $3.1 million and $2.0 million, respectively. Internal labor and overhead costs capitalized for other property, plant and equipment were $29.2 million, $33.6 million and $15.5 million during 2003, 2002 and 2001, respectively. Fixed assets under capital lease were $12.6 million and $7.6 million as of December 31, 2003 and 2002, respectively.

Depreciation rates include a provision for our share of the estimated costs to decommission three coal-fired generating plants at the end of the useful life of each plant. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities. (See “New Accounting Standards” in this Note 4 regarding our asset retirement obligation and amounts collected in the rate-making process for costs of removal of regulated utility property.)

All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal.

Property, plant and equipment at December 31 consisted of the following (in thousands):

	2003			2002
Land and improvements	$	37,912		$	30,708
Building and improvements	110,117			102,882
Storage, distribution, transmission and generation	1,729,045			1,706,622
Construction work in process	19,989			22,172
Other equipment	199,362			181,422
	2,096,425			2,043,806
Less accumulated depreciation	(733,676		)	(690,263		)
	$	1,362,749		$	1,353,543

We capitalize the cost of plant additions and replacements, including an allowance for funds used during construction (AFUDC) of utility plant. We determine the rate used to compute AFUDC in accordance with a formula established by the FERC. This rate averaged 8.9% and 8.7% for Montana for 2003 and 2002, and 10.7%, 6.6% and 6.9% for South Dakota for 2003, 2002 and 2001, respectively. Interest capitalized totaled $0.9 million and $1.1 million in 2003 and 2002, respectively, for Montana and South Dakota combined. Interest capitalized was not significant in 2001.

We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from three to forty years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility

F - 11

plant was approximately 3.5%, 3.4% and 3.3% for 2003, 2002 and 2001, respectively.

We recorded a $12.4 million impairment charge in 2003 and a $35.7 million charge in 2002 in our All Other segment related to our construction of a 260-megawatt natural gas-fired generation project located in Great Falls, Montana. The remaining assets of this project have been classified as Assets Held For Sale on the Consolidated Balance Sheets. The remaining investment in this project was $30.0 million at December 31, 2003.

Other Noncurrent Liabilities

Other noncurrent liabilities as of December 31 consisted of the following (in thousands):

	2003		2002
Pension and other postretirement benefit liability	$	133,668	$	196,521
Future QF obligation, net (1)	—		143,515
Environmental liability (1)	—		36,505
Deferred revenue	14,317		22,866
Customer advances	22,841		21,996
Other	39,268		65,759
	$	210,094	$	487,162

(1) These amounts were reclassified to liabilities subject to compromise as of December 31, 2003.

Liabilities Subject to Compromise

Trade creditor liabilities subject to compromise as of December 31, 2003, consisted of the following (in thousands):

Future QF obligation, net	$	142,815
Accrued interest and preferred dividends	46,869
Environmental liabilities	43,927
Pension and other postretirement benefit liabilities	23,168
Hedge gain	13,247
Accounts payable and other	17,777
	$	287,803

Stock-based Compensation

At December 31, 2003, we have a nonqualified stock option plan, as described more fully in Note 19. We apply the intrinsic value based method of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for our stock option plan. No compensation cost is recognized as the option exercise price is equal to the market price of the underlying stock on the date of grant. Our pro forma net income and earnings per share would have been as indicated below had the fair value of option grants been charged to compensation expense in accordance with SFAS No. 123 (in thousands except per share amounts):

	2003			2002			2001
Earnings (losses) on common stock
As reported	$	(128,670	)	$	(892,943	)	$	37,514
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	—			(409		)	(633		)
Pro forma	$	(128,670	)	$	(893,352	)	$	36,881
Diluted earnings per share
As reported	$	(3.44	)	$	(30.04	)	$	1.54
Pro forma	$	(3.44	)	$	(30.05	)	$	1.51

Insurance Subsidiary

Risk Partners Assurance, Ltd is a wholly owned non-United States insurance subsidiary established in 2001 to insure worker’s compensation, general liability and automobile liability risks. Blue Dot was insured by Risk Partners through August 31, 2003. While

F - 12

historical claims are covered by Risk Partners, on September 1, 2003, Blue Dot withdrew from the Risk Partners insurance plan and obtained new insurance from a third party. At December 31, 2003, Netexit (f/k/a Expanets) was insured through Risk Partners. In addition, NorthWestern Energy was insured through Risk Partners for automobile liability risks at December 31, 2003. Reserve requirements are established based on actuarial projections of ultimate losses. Any losses estimated to be paid within one year from the balance sheet date are classified as accrued expenses, while losses expected to be payable in later periods are included in other long-term liabilities. Risk Partners has purchased reinsurance policies through a third-party reinsurance company to transfer a portion of the insurance risk. Restricted cash related to this subsidiary was $13.1 million at December 31, 2003.

Income Taxes

Deferred income taxes relate primarily to the difference between book and tax methods of depreciating property, amortizing tax-deductible goodwill, the difference in the recognition of revenues and expenses for book and tax purposes, certain natural gas costs, which are deferred for book purposes but expensed currently for tax purposes, and net operating loss carry forwards.

Environmental Costs

We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset based on our expectation that we will recover these costs from customers in future rates. Otherwise, we expense the costs. If an environmental expense is related to facilities we currently use, such as pollution control equipment, we capitalize and depreciate the costs over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

We record estimated remediation costs, excluding inflationary increases and probable reductions for insurance coverage and rate recovery. The estimates are based on our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, we estimate and record only our share of the cost. We treat any future costs of restoring sites where operation may extend indefinitely as a capitalized cost of plant retirement. The depreciation expense levels we can recover in rates include a provision for these estimated removal costs.

New Accounting Standards

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, Accounting for Asset Retirement Obligations, which was effective January 1, 2003. The statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The statement requires the present value of future asset retirement costs for which the Corporation has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over the asset life.

We have completed an assessment of the specific applicability and implications of SFAS No. 143. We have identified, but have not recognized, asset retirement obligation, or ARO, liabilities related to our electric and natural gas transmission and distribution assets. Many of these assets are installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.

Our regulated utility operations have, however, previously recognized removal costs of transmission and distribution assets as a component of depreciation in accordance with regulatory treatment. These amounts do not represent SFAS No. 143 legal retirement obligations. As of December 31, 2003 and 2002, we have estimated accrued removal costs of $124.9 million and $115.5 million, respectively, which are included in regulatory liabilities.

For our generation properties, we have accrued decommissioning costs since the generating units were first put into service in the amount of $11.9 million and $11.4 million as of December 31, 2003 and 2002, respectively, which is classified as a noncurrent regulatory liability. These amounts also do not represent SFAS No. 143 legal retirement obligations.

SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, was issued in April 2002. SFAS No. 145 eliminates the requirement that gains and losses from the extinguishments of debt be aggregated and classified as extraordinary items, net of the related income tax. It also requires sale-leaseback treatment for certain modifications of a capital lease that result in the lease being classified as an operating lease. We adopted SFAS No. 145 on January 1, 2003. As a result of the adoption, effective January 1, 2003, we reclassified the recognition of deferred costs related to interim financing of $20.7 million, incurred for the three months ended March 31, 2002, from an extraordinary loss to loss on debt extinguishment on the Consolidated Statement of Income (Loss). The related tax benefit of $7.2 million has been reclassified from an extraordinary loss to benefit for income taxes on the Consolidated Statement of Income (Loss).

F - 13

SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, was issued in June 2002. SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan, including lease termination costs and certain employee termination benefits that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activity. SFAS No. 146 is being applied prospectively and is effective for exit or disposal activities that are initiated after December 31, 2002. We adopted SFAS No. 146 on January 1, 2003. The adoption of SFAS No. 146 did not have a material impact on our consolidated results of operations, financial position, or cash flows.

FASB Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46), was issued in January 2003 and was revised in December 2003. This interpretation changes the method of determining whether certain entities, including securitization entities, should be included in a company’s consolidated financial statements. An entity that is subject to FIN 46 is called a variable interest entity, or VIE, if it has equity that is insufficient to permit the entity to finance its activities without additional subordinated financial support from other parties, or equity investors that cannot make significant decisions about the entity’s operations, or that do not absorb the expected losses or receive the expected returns of the entity. All other entities are evaluated for consolidation in accordance with SFAS No. 94, Consolidation of All Majority-Owned Subsidiaries. A VIE is consolidated by its primary beneficiary, which is the party involved with the VIE that has a majority of the expected losses or a majority of the expected residual returns or both. The requirements of FIN 46 are applicable to NorthWestern Corporation in the fourth quarter of 2003. Had we not filed for bankruptcy, we would have been required to deconsolidate our Subsidiary Trusts, which hold our Company Obligated Mandatorily Redeemable Preferred Securities (TPS), upon adoption of FIN 46. However, upon filing for bankruptcy, the Subsidiary Trusts were terminated and the TPS became direct obligations of NorthWestern Corporation. In February 2004, we became aware that certain long-term purchase power and tolling contracts may be considered variable interests under FIN No. 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. We believe the counterparties to these contracts are not special-purpose entities and, therefore, FIN No. 46R would not apply to these contracts until March 31, 2004. We have not yet completed our evaluation of these contracts to determine if we need to consolidate these counterparties under FIN No. 46R and will continue to monitor developing practice in this area.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 149 is effective prospectively for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The exception to these requirements are the provisions of SFAS No. 149 related to SFAS No. 133 implementation issues that have been effective for fiscal quarters that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. In addition, paragraphs 7(a) and 23(a), which relate to forward purchases or sales of when-issued securities or other securities that do not yet exist, should be applied to both existing contracts and new contracts entered into after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on our consolidated results of operations, financial condition or cash flows.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Instruments with Characteristics of Both Liabilities and Equity, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope, which may have previously been reported as equity, as a liability or an asset in some circumstances. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. In accordance with SFAS No. 150, we have presented our Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts as liabilities as of December 31, 2003, and the respective dividends accrued after June 30, 2003, of approximately $6.2 million have been reflected as interest expense through the date of our filing for bankruptcy. Prior period amounts have not been reclassified.

Related-Party Transaction

Long-Term Incentive Program to Key Executives

In order to provide a recruitment and retention incentive, we adopted a long-term equity incentive program in September 1999 in which certain of our key executives and key employees of NorthWestern Growth Corporation, which initiates strategic investments for us, were provided the opportunity to make personal investments. The investment entity was structured as a limited liability company, was controlled and substantially owned by us, and enabled the investors to participate in long-term capital appreciation resulting from increases in the value of our interests in Blue Dot, Expanets and CornerStone above benchmark rates of return to us approved by the independent Compensation Committee of our Board of Directors. Participants would benefit in any such capital appreciation on a pro rata basis with the other holders of equity interests in such entities after achievement of the benchmark rate of return to us. The interests of our executives in the limited liability company upon formation collectively represented a less than .05% interest in each of Blue Dot, Expanets and CornerStone. The limited liability company had no indebtedness and was consolidated in our financial statements. In the year ended December 31, 2002, there were no distributions to any of our executive officers, and in the year ended December 31, 2001, the following executive officers received distributions in respect of the transfer to us of a portion of their vested interests relating to the performance of

F - 14

certain entities acquired in 1998, 1999 and 2000, each of which exceeded target performance benchmarks during the 12 month period following the date of acquisition: M. Lewis, then chief executive officer, $1.1 million; R. Hylland, then president, $0.8 million; D. Newell, then senior vice president, $0.8 million; E. Jacobsen, senior vice president, $0.4 million; and K. Orme, then chief financial officer, $0.1 million. This limited liability company was terminated and dissolved in March 2003 pursuant to a plan of dissolution and liquidation. In connection with the winding up of the entity, four participants received final liquidation payments, one of which was a named executive officer, E. Jacobsen, who received a final payment of $41,960.

Reclassifications

Certain 2001 and 2002 amounts have been reclassified to conform to the 2003 presentation. Such reclassifications had no impact on net income (loss) or shareholders’ equity (deficit) as previously reported.

Supplemental Cash Flow Information

	2003			2002			2001
	(in thousands)
Cash paid (received) for
Income taxes	$	(13,038	)	$	(17,572	)	$	6,436
Interest	101,778			163,045			41,229
Reorganization interest income	(14		)	—			—
Reorganization professional fees and expenses	1,371			—			—
Noncash transactions for
Fair value of notes receivable received in exchange for sales of discontinued operations	$	1,600		$	—		$	—
Assets acquired in exchange for debt	193			—			—
Exchange of warrants for common stock	—			—			6,797
Issuance of restricted stock	—			—			760
Debt and preferred securities assumed in acquisitions	—			511,100			—

(5) Acquisitions

On February 15, 2002, we completed the asset acquisition of Montana Power’s energy transmission and distribution business for $478.0 million in cash and the assumption of $511.1 million in existing debt and mandatorily redeemable preferred securities of subsidiary trusts (net of cash received). Acquisition costs were approximately $24.8 million. We completed this acquisition to expand our presence in the energy market. As a result of the acquisition, we are now a provider of natural gas and electricity to approximately 608,000 customers in Montana, South Dakota and Nebraska. Results of our Montana operations have been included in the accompanying consolidated financial statements since the effective date of the acquisition.

The following unaudited pro forma results of consolidated operations for the years ended December 31, 2002 and 2001, give effect as if the acquisition had occurred as of January 1, 2001 (in thousands, except per share amounts):

	December 31, 2002			December 31, 2001
Revenues	$	846,593		$	958,936
Net Loss	(854,723		)	1,534
Diluted loss per share	$	(29.74	)	$	(.38	)

The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future consolidated results.

(6) Goodwill

We adopted the provisions of SFAS No. 142 effective January 1, 2002, and goodwill is no longer amortized. 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 (October 1) and more frequently when indications of impairment exist. Accounting standards require that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, we compare the implied fair value of the reporting unit’s goodwill with its carrying value. This methodology differs from our previous policy, as permitted under previous accounting standards, of using undiscounted cash flows on an enterprise wide basis to determine if goodwill is recoverable.

F - 15

We determined that our Chapter 11 bankruptcy filing constitutes an event that may reduce the fair value of our reporting unit below its carrying value. Therefore we retained a third party to assist us in completing a goodwill impairment test as required by SFAS No. 142. Fair value was determined using a discounted cash flow approach and a guideline company market approach. Completion of the testing indicated that no impairment charge was required.

There were no changes in our goodwill during the 12 months ended December 31, 2003. Goodwill relates entirely to the Montana operations acquired in 2002 included in our Electric and Natural Gas segment and totals $375.8 million as of December 31, 2003 and 2002.

(7) Restructuring Reserve

We recognized a restructuring charge in the fourth quarter of 2001 related to certain cost savings initiatives. We summarize the activity in accrued expenses related to the restructuring charge in our Consolidated Balance Sheets in the following table (in thousands):

	December 31, 2002		Payments			December 31, 2003
Employee termination benefits	$	1,783	$	(1,783	)	$	—

(8) Discontinued Operations

During the second quarter of 2003, we committed to a plan to sell or liquidate our interest in Expanets and Blue Dot. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classified the results of operations of Expanets and Blue Dot as discontinued operations.

In October 2003, we were authorized to complete the sale of Expanets’ assets. On November 25, 2003, Expanets closed on an Asset Purchase and Sale Agreement to sell substantially all the assets and business of Expanets to Avaya, Inc. (Avaya) and retain certain specified liabilities. Thereafter, Expanets was renamed Netexit, Inc. (Netexit), which will continue as a non-operating company until its affairs can be wound-down in accordance with its lending agreements, its corporate charter and provisions of Delaware law. Under the terms of the agreement, a $4 million “break-up fee” was paid to a third party originally involved in the transaction and Avaya paid Netexit cash of approximately $50.8 million, and assumed debt of approximately $38.1 million. In addition, Avaya deposited approximately $13.5 million and $1.0 million into escrow accounts to satisfy certain specified liabilities that were not assumed by Avaya, and certain indemnification obligations of Netexit, respectively. Avaya also reduced cash paid at closing by approximately $44.6 million as a working capital adjustment, pending the determination of a final closing balance sheet. On February 24, 2004, Avaya submitted its proposed final calculation of the working capital adjustment asserting that there was a working capital shortfall at Expanets of approximately $48.8 million at closing, and claiming that Avaya should retain the entire holdback amount plus an additional $4.2 million. Netexit disputes this calculation and believes that pursuant to the terms of the asset purchase agreement Netexit is owed additional cash ranging from $10 million to $20 million (resulting in potential net cash proceeds to Netexit of $60.8 million to $70.8 million). The dispute over the working capital adjustment is subject to an arbitration process, which is expected to be decided in May 2004. Pending resolution of the final balance sheet, the determination of the expenses that Netexit must pay in connection with the sale, and the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit. If Netexit cannot wind-down its affairs in an orderly manner pursuant to applicable provisions of Delaware law, it may be forced to file bankruptcy. We have recognized an estimated loss on disposal of approximately $49.3 million based on the terms of the sale and our expectation of the amount to be received from Avaya. An additional loss may arise based on the results of the arbitration process discussed above.

F - 16

Summary financial information for the discontinued Expanets operations is as follows (in thousands):

	December 31, 2003		December 31, 2002
Accounts receivable, net	$	—	$	101,990
Other current assets	59,949		72,170
Current assets of discontinued operations	$	59,949	$	174,160

Other noncurrent assets of discontinued operations	$	—	$	155,781

Accounts payable	$	11,795	$	34,735
Other current liabilities	—		125,066
Current liabilities of discontinued operations	$	11,795	$	159,801

Other noncurrent liabilities of discontinued operations	$	—	$	71,971

	2003			2002			2001
Revenues	$	541,211		$	710,452		$	1,032,033
Income (Loss) before income taxes and minority interests	$	1,360		$	(422,802	)	$	(119,198	)
Estimated loss on disposal	(49,250		)	—			—
Minority interests	—			11,152			127,893
Income tax benefit (provision)	—			(22,780		)	32,190
Loss from discontinued operations, net of income taxes and minority interests	$	(47,890	)	$	(434,430	)	$	40,885

Expanets’ income before income taxes and minority interests for the year ended December 31, 2003, includes a gain on debt extinguishment of $27.3 million.

Blue Dot sold 48 businesses during 2003, repaid its credit facility from sales proceeds and terminated the facility. As of December 31, 2003, Blue Dot had 14 remaining businesses. Subsequent to December 31, 2003, Blue Dot sold 6 additional businesses as of March 1, 2004. Blue Dot anticipates selling substantially all of its remaining businesses by June 30, 2004. We hope to receive in excess of $15 million in cash from Blue Dot during the liquidation of the operations; provided however, this assumes satisfactory resolutions to remaining stock obligations, potential or pending litigation, insurance and bonding reserves, and no new material additional claims or litigation. Furthermore, it assumes that the remaining businesses produce their projected cash proceeds and receivables from various sold locations are collectible.

	December 31, 2003		December 31, 2002
Accounts receivable, net	$	27,588	$	56,393
Other current assets	18,660		36,668
Current assets of discontinued operations	$	46,248	$	93,061

Other noncurrent assets of discontinued operations	$	306	$	185

Accounts payable	$	11,486	$	18,945
Other current liabilities	21,215		61,266
Current liabilities of discontinued operations	$	32,701	$	80,211

Other noncurrent liabilities of discontinued operations	$	1,998	$	10,611

F - 17

	2003			2002			2001
Revenues	$	400,679		$	471,824		$	423,803

Income (Loss) before income taxes and minority interests	$	(3,356	)	$	(311,674	)	$	(17,392	)
Gain on disposal	14,352			—			—
Minority interests	—			3,762			13,555
Income tax benefit (provision)	—			(9,071		)	3,830
Income (Loss) from discontinued operations, net of income taxes	$	10,996		$	(316,983	)	$	(7	)

During the second and third quarters of 2003, we also sold our interest in two other subsidiaries. The sale of One Call Locators, Ltd., was completed in June for consideration of $6.6 million in cash and a note receivable of $4.7 million. We recorded the carrying value of the note receivable based on the fair value of our trust preferred securities at the date of the transaction, and we recognized a loss of approximately $3.4 million on this sale. The acquiring entity elected to prepay the note receivable on August 25, 2003, by presenting trust preferred obligated securities of NorthWestern, which were accepted at face value. We recognized a gain of $3.3 million on the extinguishment of trust preferred obligated securities during the third quarter of 2003. We sold assets of the other subsidiary in July for $0.2 million in cash and a note receivable of $0.3 million. We recognized a loss of approximately $2.2 million on this sale. We have classified the results of these subsidiaries and CornerStone Propane Partners, LP (see discussion below) in discontinued operations and summary financial information is as follows (in thousands):

	2003			2002			2001
Revenues	$	19,493		$	422,816		$	2,526,768

Income (Loss) before income taxes, net of minority interests	$	456		$	(21,584	)	$	(5,021	)
Loss on disposal	(5,705		)	(97,055		)	—
Income tax benefit (provision)	—			15,466			4,500
Loss from discontinued operations, net of income taxes and minority interests	$	(5,249	)	$	(103,173	)	$	(521	)

Effective November 1, 2002, we relinquished our direct and indirect equity interests in CornerStone Propane Partners, LP and CornerStone Propane, LP. We do, however, own a noneconomic voting interest in a limited liability company, which owns 100 percent of the stock of the managing general partner of CornerStone. As a result, the assets and liabilities of CornerStone are no longer included in our Consolidated Balance Sheets subsequent to November 1, 2002. The results for CornerStone’s operations and impairments related to our investments in and advances to CornerStone for the year ended December 31, 2002 and 2001, have been presented as discontinued operations in the Consolidated Statements of Income (Loss).

On August 20, 2002, NorthWestern purchased the lenders’ interest in approximately $19.9 million of CornerStone short-term debt outstanding under CornerStone’s credit facility together with approximately $6.1 million in letters of credit, 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 had $9.2 million in letters of credit outstanding on behalf of CornerStone. In October 2003, the $9.2 million in letters of credit outstanding on behalf of CornerStone were drawn by their respective beneficiaries. During the third quarter of 2003, we recorded an impairment charge of $9.1 million to reduce our note receivable to an estimated recoverable amount. As of December 31, 2003, the net recorded value of our receivables from CornerStone was $11 million.

F - 18

(9) Long-Term Debt

Long-term debt at December 31 consisted of the following (in thousands):

	Due	2003			2002
Debt Not Subject to Compromise:

Senior Secured Term Loan	2006	$	386,100		$	—
Bank credit facility	—	—			255,000

Mortgage bonds—
South Dakota—7.10%	2005	60,000			60,000
South Dakota—7.00%	2023	55,000			55,000
Montana—7.30%	2006	150,000			150,000
Montana—8.25%	2007	365			365
Montana—8.95%	2022	1,446			1,446
Montana—7.00%	2005	5,386			5,386
Pollution control obligations—
South Dakota—5.85%	2023	7,550			7,550
South Dakota—5.90%	2023	13,800			13,800
Montana—6.125%	2023	90,205			90,205
Montana—5.90%	2023	80,000			80,000
Secured medium term notes—
7.23%	2003	—			15,000
7.25%	2008	13,000			13,000
Montana Natural Gas Transition Bonds	2012	46,502			50,866
Capital leases	Various	12,399			8,422
Other term debt	Various	1,122			1,419
Discount on Notes and Bonds	—	(3,483		)	(3,867		)
		919,392			803,592
Debt Subject to Compromise:
Senior Unsecured Notes—7.875%	2007	$	250,000		$	250,000
Senior Unsecured Notes—8.75%	2012	470,000			470,000
Senior Unsecured debt—6.95%	2028	105,000			105,000
Unsecured medium term notes—
7.07%	2006	15,000			15,000
7.875%	2026	20,000			20,000
7.96%	2026	5,000			5,000
Discount on Notes and Bonds	—	(156		)	(161		)
		864,844			864,839
Less current maturities		(1,784,236		)	(25,909		)
		$	—		$	1,642,522

As discussed in Note 3, the Chapter 11 filing triggered defaults and we have classified our secured debt as current as of December 31, 2003. Although 2002 debt was not subject to compromise, it has been presented in the above table as such for comparability.

On September 14, 2003, the Bankruptcy Court gave interim approval for access of up to $50 million of our $100 million DIP Facility. On November 7, 2003, the Bankruptcy Court entered a final order to approve the DIP Facility and, in doing so, increased our access under this facility to $85 million. In December 2003, we reduced the commitment to $85 million under this facility. The DIP Facility expires on September 12, 2004, and bears interest at a variable rate tied to the Eurodollar rate plus a spread of 3.00% or at the prime rate plus a spread of 1.00%. The DIP Facility requires that we maintain certain other financial covenants and restricts liens, indebtedness, capital expenditures, dividend payments and sales of assets. As of December 31, 2003, we had $15.2 million in letters of credit outstanding and no borrowings under the DIP facility.

We have reached an agreement with the lenders holding claims under our senior credit facility agented by CSFB to amend the terms of our $390 million prepetition credit facility. In January 2004, the Bankruptcy Court entered a final order authorizing the amendment of the credit facility and granting protection in connection therewith. The amended credit facility provides advantages to NorthWestern, including lower interest expense allowing reinstatement upon NorthWestern’s emergence from Chapter 11. At NorthWestern’s option, the amended credit facility bears interest at a variable rate tied to the Eurodollar rate, plus a spread of 5.50%, or at

F - 19

an alternate base rate, as defined by the amended credit facility, plus a spread of 3.50%. There is no longer a minimum floor for the Eurodollar rate or the alternate base rate. As a result of this amendment, we estimate annualized interest expense will be reduced by approximately $6 million to $8 million.

Our senior secured term loan expires on December 1, 2006, and requires quarterly amortization payments equal to $975,000. The credit agreement contains financial covenants related to minimum EBITDAR(1), maximum capital expenditures and a number of other representations and warranties. We are in compliance with these debt covenants at December 31, 2003.

In January 2003, in connection with executing the new senior secured term loan facility, we applied to the MPSC for authorization to issue up to $280 million aggregate principal amount of First Mortgage Bonds secured by Montana utility assets as security for our new senior secured term loan facility. In granting its approval, the MPSC placed the following conditions on the approval of the First Mortgage Bonds:

• We must apply all proceeds from the sale of nonutility assets, specifically including Blue Dot and Expanets, to debt reduction;

• We must commit to fully funding the operation, maintenance, repair and replacement of our public utility infrastructure in Montana, and we were required to file a maintenance plan and budget with the MPSC by March 13, 2003;

• We may not provide more than an additional $10 million in aggregate in capital to any nonutility entity without the prior approval of the MPSC;

• We must report all advances to nonutility companies to the MPSC within 5 business days of such advance; and

• if the existing credit agreements for Blue Dot or Expanets are terminated, we may file an application with the MPSC seeking approval to provide secured loans of up to $20 million to Blue Dot and up to $30 million to Expanets.

The South Dakota Mortgage Bonds are two series of general obligation bonds we issued under our South Dakota indenture, and the South Dakota Pollution Control Obligations are three obligations under our South Dakota indenture. All of such bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets.

The Montana First Mortgage Bonds are four series of bonds that The Montana Power Company issued. The Montana Pollution Control Obligations, and the Secured Medium Term Notes are obligations that The Montana Power Company issued. The Montana Natural Gas Transition Bonds were issued by The Montana Power Company. All of these obligations are secured by substantially all of our Montana electric and natural gas assets.

The Senior Notes are two series of unsecured notes that we issued in 2002 in connection with our acquisition of NorthWestern Energy LLC. Proceeds were used for the acquisition and for general corporate purposes.

The Senior Unsecured Debt is a general obligation that we issued in November 1998. The proceeds were used to repay short-term indebtedness and for general corporate purposes.

The Unsecured Medium Term Notes are general obligations issued by The Montana Power Company.

The aggregate minimum principal maturities of long-term debt, absent accelerations due to default, during the next five years are $11.6 million in 2004, $76.5 million in 2005, $550.0 million in 2006, $257.0 million in 2007 and $19.1 million in 2008.

(1) EBITDAR is earnings before interest, taxes, depreciation, amortization and non-recurring restructuring expenses. EBITDAR is a non-GAAP financial measure and as such, we have not used it in describing our results of operations. We have used EBITDAR in this section specifically to show compliance with our debt covenants, and we do not refer to EBITDAR for any other purpose herein.

F - 20

(10) Comprehensive Income (Loss)

The Financial Accounting Standards Board defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are excepted. Comprehensive income consists of net income and other comprehensive income. Net income may include such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principles. Other comprehensive income may include foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities. Comprehensive income (loss) is calculated as follows (in thousands):

	2003			2002			2001
Net income (loss)	$	(113,725	)	$	(863,942	)	$	44,532
Other comprehensive income:
Net unrealized gain (loss) on available-for-sale securities, net of tax of $(188), $713, and $(1,303) in 2003, 2002, and 2001, respectively	(352		)	1,139			(2,081		)
Net unrealized gain on derivative instruments qualifying as hedges, net of tax of $(224) and $2,757 in 2003 and 2002, respectively	(416		)	4,265			—
Minimum pension liability adjustment	(1,465		)	(8,759		)	—
Foreign currency translation adjustment	298			5			—
Total other comprehensive loss	(1,935		)	(3,350		)	(2,081		)
Total comprehensive income (loss)	$	(115,660	)	$	(867,292	)	$	42,451

The after tax components of accumulated other comprehensive loss for the years ended December 31, 2003 and 2002, were as follows (in thousands):

	2003			2002
Balance at December 31,
Net unrealized gain (loss) on available-for-sale securities	$	—		$	352
Unrealized gain on derivative instruments qualifying as hedges	3,849			4,265
Minimum pension liability adjustment	(10,224		)	(8,759		)
Foreign currency translation adjustment	303			5
Accumulated other comprehensive loss	$	(6,072	)	$	(4,137	)

(11) Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, Disclosures About Fair Value of Financial Instruments. The estimated fair-value amounts have been determined using available market information and appropriate valuation methodologies. However, considerable judgment is necessarily required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

• The carrying amounts of cash and cash equivalents, restricted cash and investments approximate fair value due to the short maturity of the instruments. The fair value of life insurance contracts is based on cash surrender value.

• Fair values for debt were determined based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, which is based on market prices.

• The fair value of preferred securities of subsidiary trusts is based on current market prices.

• The fair-value estimates presented herein are based on pertinent information available to us as of December 31, 2003. Although we are not aware of any factors that would significantly affect the estimated fair-value amounts, such amounts have not been comprehensively revalued for purposes of these financial statements since that date, and current estimates of fair value may differ significantly from the amounts presented herein.

F - 21

The estimated fair value of financial instruments at December 31 is summarized as follows (in thousands):

	2003				2002
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Cash and cash equivalents	$	15,183	$	15,183	$	26,554	$	26,554
Restricted cash	27,043		27,043		28,039		28,039
Investments	11,027		11,027		85,236		85,236
Liabilities:
Long-term debt (including current portion)	1,784,236		1,704,392		1,668,431		1,345,012
Company obligated mandatorily redeemable preferred securities of subsidiary trusts	365,550		130,682		370,250		248,094

(12) Income Taxes

Income tax benefit applicable to continuing operations before minority interests for the years ended December 31 is comprised of the following (in thousands):

	2003			2002			2001
Federal
Current	$	(9,838	)	$	(30,333	)	$	14,882
Deferred	10,334			(8,761		)	(20,891		)
Investment tax credits	(544		)	(535		)	(535		)
State	—			(182		)	(316		)
	$	(48	)	$	(39,811	)	$	(6,860	)

The following table reconciles our effective income tax rate to the federal statutory rate:

	2003		2002		2001

Federal statutory rate	(35.0	)%	(35.0	)%	(35.0	)%
State income, net of federal provisions	(3.9	)	(0.4	)	(11.8	)
Amortization of investment tax credit	(0.8	)	(1.1	)	(19.9	)
ESOP dividends paid	—		—		(26.1	)
Municipal bond interest	—		—		(4.1	)
Affiliated stock loss on disposition	(163.2	)	(60.6	)	—
Nondeductible reserve activity	—		—		(44.9	)
Minority interest preferred stock	(7.3	)	(20.2	)	(91.7	)
Dividends received deduction and other investments	(0.1	)	(1.2	)	(23.7	)
Prior year tax return refund	(8.5	)	—		—
Valuation allowance	221.8		36.1		—
Prior year permanent return to accrual adjustments	(7.3	)	—		—
Prior year permanent IRS examination adjustments	2.0		—		—
Other, net	2.2		1.4		1.7
	(0.1	)%	(81.0	)%	(255.5	)%

F - 22

The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences at December 31 (in thousands):

	2003			2002
Excess tax depreciation	$	(80,784	)	$	(49,246	)
Regulatory assets	(6,867		)	(3,327		)
Regulatory liabilities	4,040			2,664
Unbilled revenue	1,276			861
Unamortized investment tax credit	2,751			2,375
Compensation accruals	(3,790		)	(328		)
Reserves and accruals	26,958			6,395
Goodwill impairment/amortization	(11,071		)	—
Net operating loss carryforward (NOL)	210,382			37,591
AMT credit carryforward	228			1,577
Deferred revenue	25,534			26,463
Other, net	2,394			(7,494		)
Valuation allowance	(181,587		)	(17,733		)
	$	(10,536	)	$	(202	)

Realization of deferred tax assets is dependent upon generating sufficient taxable income. Accordingly, a valuation allowance of $181.6 million and $17.7 million has been recorded as of December 31, 2003 and 2002, as it is more likely than not that these assets will not be realized.

As of December 31, 2003, we have a total NOL carry forward of $563.1 million. Of this amount, $102.9 million will expire in the year 2022 and $460.2 million will expire in the year 2023.

The IRS audit of our federal income tax returns for 1996 through 1999 was completed in 2003 with no material impact to our financial position or results of operations. Additionally, an IRS audit of our federal income tax returns for the years 2000 through 2002 was commenced in October 2003. Management believes that the final results of these audits will not have a material adverse effect on our financial position or results of operations.

(13) Jointly Owned Plants

We have an ownership interest in three electric generating plants, all of which are coal fired and operated by other utility companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Consolidated Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Consolidated Statements of Income (Loss). The participants each finance their own investment.

Information relating to our ownership interest in these facilities at December 31, is as follows (in thousands):

	Big Stone (S.D.)			Neal #4 (Iowa)			Coyote I (N.D.)
2003
Ownership percentages	23.4		%	8.7		%	10.0		%
Plant in service	$	49,619		$	28,037		$	42,441
Accumulated depreciation	$	30,916		$	16,858		$	21,354

2002
Ownership percentages	23.4		%	8.7		%	10.0		%
Plant in service	$	47,802		$	28,081		$	41,957
Accumulated depreciation	$	30,644		$	16,025		$	20,796

F - 23

(14) Operating Leases

In connection with the purchase of our Montana Power operations, we have seven years remaining under an operating lease agreement to lease generation facilities, which requires lease payments of $32.2 million annually. We also lease vehicles, office equipment and office and warehouse facilities under various long-term operating leases. At December 31, 2003, future minimum lease payments under noncancelable lease agreements are as follows (in thousands):

2004	$	33,133
2005	32,849
2006	32,572
2007	32,288
2008	32,268
Thereafter	64,452

Lease and rental expense incurred was $40.1 million, $39.9 million and $1.9 million in 2003, 2002 and 2001, respectively.

(15) Employee Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for employees of the corporation and regulated utility division. In addition, we also sponsor nonqualified, unfunded defined benefit pension plans for certain officers and other employees. With the acquisition of Montana Power, we assumed their pension and postretirement health care plans. These plans are reflected in the 2003 and 2002 columns of the tables below.

Net periodic cost for our pension and other postretirement plans consists of the following for the year ended December 31 (in thousands):

	Pension Benefits									Other Postretirement Benefits
	2003			2002			2001			2003			2002
Components of Net Periodic Benefit Cost (Income)
Service cost	$	5,165		$	4,821		$	891		$	1,350		$	3,068
Interest cost	21,080			19,315			3,421			5,455			10,044
Expected return on plan assets	(16,329		)	(18,737		)	(4,738		)	(261		)	(405		)
Amortization of transitional obligation	155			155			155			675			1,350
Amortization of prior service cost	505			626			626			—			—
Recognized actuarial (gain) loss	2,724			28			(225		)	467			161
	13,300			6,208			130			7,686			14,218
Additional (income) or loss recognized:
Curtailment	—			833			—			13,511			—
Special termination benefits	785			5,858			—			—			168
Settlement cost	—			—			—			(13,586		)	—
Net Periodic Benefit Cost	$	14,085		$	12,899		$	130		$	7,611		$	14,386

The prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10% of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.

F - 24

Following is a reconciliation of the changes in plan benefit obligations and fair value and a statement of the funded status as of December 31 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	2003			2002			2003			2002
Reconciliation of Benefit Obligation
Obligation at January 1	$	329,980		$	50,527		$	103,352		$	33,303
Purchased obligation—Montana Power	—			251,370			—			55,888
Service cost	5,165			4,821			1,350			3,068
Interest cost	21,080			19,315			5,455			10,044
Actuarial loss	23,446			17,147			(387		)	9,219
Plan amendments	—			56			(4,164		)	—
Curtailments	—			(368		)	(3,077		)	—
Settlement cost	—			—			(16,566		)	—
Special termination benefits	785			5,858			—			168
Gross benefits paid	(24,083		)	(18,746		)	(19,015		)	(8,338		)
Benefit obligation at end of year	$	356,373		$	329,980		$	66,948		$	103,352

Reconciliation of Fair Value of Plan Assets
Fair value of plan assets at January 1	$	201,202		$	48,871		$	4,794		$	6,344
Actual return on plan assets	41,727			(25,147		)	385			(647		)
Purchased assets—Montana Power	—			196,223			—			—
Employer contributions	10,925			1			35,836			7,435
Settlements	—			—			(16,566		)	—
Gross benefits paid	(24,083		)	(18,746		)	(19,015		)	(8,338		)
Fair value of plan assets at end of year	$	229,771		$	201,202		$	5,434		$	4,794

The total projected benefit obligation and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $356.4 million and $229.8 million, respectively, as of December 31, 2003. The total accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $346.0 million and $229.8 million, respectively, as of December 31, 2003. The total projected benefit obligation and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $330.0 million and $201.2 million, respectively, as of December 31, 2002. The total accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $320.3 million and $201.2 million, respectively, as of December 31, 2002.

In January 2004, the Financial Accounting Standards Board issued FASB Staff Position No. FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (FSP 106-1). While we have elected to defer recognition of the effects of FSP 106-1 until guidance on the accounting for the federal subsidy is issued, we do not expect the effects of FSP 106-1 to be material to the measurement of our APBO or our net periodic postretirement benefit cost.

F - 25

The accrued pension and other postretirement benefit obligations recognized in the accompanying Consolidated Balance Sheets are computed as follows for the years ended December 31 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	2003			2002			2003			2002

Funded Status	$	(126,602	)	$	(128,778	)	$	(61,514	)	$	(98,558	)
Unrecognized transition amount	309			464			—			18,350
Unrecognized net actuarial loss	60,808			65,484			17,549			8,018
Unrecognized prior service cost	1,288			1,793			—			—
Accrued benefit cost	$	(64,197	)	$	(61,037	)	$	(43,965	)	$	(72,190	)

Prepaid benefit cost	$	2,683		$	5,251		$	—		$	—
Accrued benefit cost	(66,880		)	(66,288		)	(43,965		)	(72,190		)
Additional minimum liability	(52,055		)	(58,043		)	—			—
Intangible asset	1,597			2,257			—			—
Regulatory asset	40,234			42,696			—			—
Accumulated other comprehensive income	10,224			13,090			—			—
Net amount recognized	$	(64,197	)	$	(61,037	)	$	(43,965	)	$	(72,190	)

The weighted-average assumptions used in calculating the preceding information are as follows:

	Pension Benefits						Other Postretirement Benefits
	2003		2002		2001		2003		2002
Discount rate	6.00	%	6.50	%	7.00	%	6.0-6.75	%	6.0-6.75	%
Expected rate of return on assets	8.50	%	8.50	%	8.50	%	8.5	%	8.5	%
Long-term rate of increase in compensation levels (nonunion)	3.97	%	4.00	%	3.50	%	4.0	%	4.0	%
Long-term rate of increase in compensation levels (union)	3.50	%	3.50	%	3.50	%	4.0	%	3.5	%

The expected long-term rate of return assumption on plan assets for both the NorthWestern Energy and NorthWestern Corporation pension and postretirement plans was determined based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension and postretirement portfolios. Over the 15-year period ending December 31, 2002, the returns on these portfolios, assuming they were invested at the current target asset allocation in prior periods, would have been a compound annual average of approximately 10.1%. Considering this information and the potential for lower future returns due to a generally lower interest rate environment, we selected an 8.5% long-term rate of return on assets assumption.

Our investment goals with respect to managing the pension and other postretirement assets is to achieve and maintain a fully funded status for the pension plans, improve the status of the health and welfare plan, minimize contribution requirements, and seek long-term growth by placing primary emphasis on capital appreciation and secondary emphasis on income, while minimizing risk.

Pension funding is based upon annual actuarial studies prepared for each plan. For our postretirement welfare benefits, our policy is to contribute an amount equal to the annual actuarially determined cost that is also recoverable in rates. We generally fund our 401(h) and VEBA trusts monthly, subject to our liquidity needs and the maximum deductible amounts allowed for income tax purposes.

The company’s investment policy for fixed income investments are oriented toward risk adverse, investment-grade securities rated “A” or higher and are required to be diversified among individual securities and sectors (with the exception of U.S. Government securities, in which the plan may invest the entire fixed income allocation) and there is no limit on the maximum maturity of securities held. In addition, the NorthWestern Corporation pension plan assets also includes a participating group annuity contract in the John Hancock General Investment Account, which consists primarily of fixed-income securities, reflected at current market values with a market adjustment.

Equity investments per the investment policy can include convertible securities, and are required to be diversified among industries and economic sectors. Limitations are placed on the overall allocation to any individual security at both cost and market value and international equities investments are diversified by country. In addition, there are limitations on investments in emerging markets.

F - 26

Our investment policy prohibits short sales, margin purchases and similar speculative transactions as well as any transactions that would threaten tax exempt status of the fund, actions that would create a conflict of interest or transactions between fiduciaries and parties in interest as defined under ERISA. With respect to international investments, foreign currency hedging is allowed under the policy for the purpose of hedging currency risk and to effect securities transactions. Permissible investments include foreign currencies in both spot and forward markets, options, futures, and options on futures in foreign currencies.

The target asset allocation percentages are as follows, within an allowable range of plus or minus 5%:

	Pension Benefits		Other Benefits
Cash and cash equivalents	—		—
Debt securities	30.0	%	30.0	%
Domestic equity securities	60.0	%	60.0	%
International equity securities	10.0	%	10.0	%
Other	—		—

The percentage of fair value of plan assets held in the following investment types by the NorthWestern Energy pension plan, NorthWestern Corporation pension plan and NorthWestern Energy Health and Welfare Plan as of December 31, 2003 and 2002, are as follows:

	NorthWestern Energy Pension				NorthWestern Corporation Pension				NorthWestern Energy Health and Welfare
	2003		2002		2003		2002		2003		2002

Cash and cash equivalents	1.4	%	7.2	%	0.6	%	—		2.8	%	4.0	%
Debt securities	28.5	%	33.4	%	11.6	%	—		27.5	%	30.4	%
Domestic equity securities	58.9	%	54.2	%	38.7	%	53.0	%	68.3	%	64.7	%
International equity securities	11.2	%	5.2	%	4.5	%	—		1.4	%	0.9	%
Participating group annuity contracts	—		—		44.6	%	47.0	%	—		—
	100.0%		100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

At December 31, 2002, the NorthWestern Energy pension plan investment portfolio was undergoing a change in investment managers, Domestic equity investments were liquidated and pending reinvestment by the new investment manager. This was completed and the portfolio was again rebalanced to bring it within the target asset allocation during 2003. We also began the process of transitioning NorthWestern Corporation’s pension plan assets over to comply with the new investment policy asset target guidelines adopted in 2002. At December 31, 2003, this process was partially completed with the liquidation and diversified reinvestment of part of the plan assets. We are evaluating the potential for liquidating and reinvesting the assets held in participating group annuity contracts as rebalancing and diversification opportunities are currently limited with respect to this portion of plan assets.

We estimate contributions to our pension and other benefit plans in 2004 to be approximately $16.0 million in total.

The rate of increase in per capita costs of covered health care benefits is assumed to be 11% in 2004, decreasing gradually to 5% by the year 2009. The following table sets forth the sensitivity of retiree welfare results (in thousands):

Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components	$	239
on postretirement benefit obligation	2,488
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components	$	(191	)
on postretirement benefit obligation	(1,943		)

Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. (See Note 17, Regulatory Assets and Liabilities, for the regulatory assets related to our pension and other postretirement benefit plans.)

During 2003 and 2002, we made available to select employees an early retirement program. The impact of that reduction in participants resulted in the special termination benefits presented in the above table.

F - 27

Two nonqualified postretirement defined benefit plans were amended effective May 6, 2003 to permit vested participants the option of continuing the current benefits level or take a present value lump sum distribution. A third nonqualified postretirement defined benefit plan was terminated effective May 6, 2003. The impact of the amendments and termination are presented in the table above.

In May 2003, our Board of Directors adopted a resolution to terminate or amend various employee benefit plans. We terminated our nonqualified supplemental 401(k) plan effective May 6, 2003. Any investment elections in our common stock were presented as Treasury Stock, other investments as part of Investments, and an offsetting liability for both as part of Other Noncurrent Liabilities in the Consolidated Balance Sheets. In June 2003, plan assets were distributed to participants and no further liability remains. Our contributions to the plan were $11,000, $713,000 and $64,000 in 2003, 2002 and 2001, respectively. Our employee stock purchase plan was also terminated, with no impact to our operating results.

We provide various employee savings plans, which permit employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the Plans, the employees may elect to direct a percentage of their gross compensation to be contributed to the Plans. We contribute up to a maximum of 4.0% of the employee’s gross compensation contributed to the Plan. Costs incurred under these plans were $3.1 million, $3.4 million and $0.8 million in 2003, 2002 and 2001, respectively.

(16) Employee Stock Ownership Plan

Our Employee Stock Ownership Plan (“ESOP”) was terminated effective July 19, 2003, and the shares were distributed to participants during 2003. Due to the suspension of our common stock dividend and the declining stock price, we accrued $5.9 million as of December 31, 2002, to satisfy the ESOP loan requirement. This loan was paid off in the second quarter of 2003 and no further liability remains. Shares held by the plan were included in the number of average shares outstanding when computing our basic and diluted earnings per share, therefore the termination has no impact on these calculations. The number, classification and fair value of shares held by the plan at December 31 are as follows:

	2003		2002
	Allocated	Unallocated	Allocated		Unallocated

Number of shares	—	—	668,617		226,883
Fair value	—	—	$	3,396,574	$	1,152,566

(17) Regulatory Assets and Liabilities

We prepare our financial statements in accordance with the provisions of SFAS No. 71, as discussed in Note 4 to the Financial Statements. Pursuant to this pronouncement, certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to the customers. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. We have specific orders to cover approximately 98% of our regulatory assets and approximately 98% of our regulatory liabilities.

	Note Ref.	Remaining Amortization Period	2003		2002
Pension	15	Undetermined	$	95,260	$	92,739
Competitive transition charges		10 Years	40,921		44,809
SFAS No. 106 purchase obligation	15	Undetermined	27,150		28,951
Income taxes	12	Plant lives	28,832		28,181
Unrecovered supply costs		1 Year	18,490		12,666
Other		Various	14,666		14,904
Total regulatory assets			$	225,319	$	222,250

Removal cost		Various	$	136,791	$	126,881
Gas storage sales		36 Years	15,036		15,456
Proceeds from oil and gas sale		—	—		15,982
Utility sale stipulation agreement		—	—		16,254
Other		Various	1,726		2,537
Total regulatory liabilities			$	153,553	$	177,110

F-28

A pension regulatory asset has been recognized upon the purchase of Montana Power for the obligation that will be included in future cost of service. Pension costs in Montana are recovered in rates on a cash basis. Competitive transition charges relate to natural gas properties and earn a rate of return sufficient to meet the debt service requirements of the Montana natural gas transition bonds. A regulatory asset has been recognized for the SFAS No. 106 purchase obligation upon the purchase of Montana Power. The MPSC allows recovery of SFAS No. 106 costs on an accrual basis. A regulatory asset has been recorded to reflect the future recovery of energy supply costs through the ratemaking process. Tax assets and liabilities primarily reflect the effects of plant related temporary differences such as removal costs, capitalized interest and contributions in aid of construction that we will recover or refund in future rates.

A regulatory liability has been recognized to reflect payments our customers have prepaid for future plant removal costs. During 2000 and 2001, Montana Power made sales of natural gas from its storage field at prices in excess of its original cost, creating a regulatory liability. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas and was fully amortized through rates in 2003. Montana Power also has a regulatory liability related to oil and gas proceeds that was credited to customer bills on a monthly basis. In connection with the acquisition of Montana Power, a stipulation agreement was signed that required a contribution by the previous owner and us to fund credits to Montana electric distribution customers. The account was applied on a kilowatt hour basis beginning July 1, 2002 for one year.

(18) Deregulation and Regulatory Matters

Deregulation

The electric and natural gas utility businesses in Montana are operating in a competitive market in which commodity energy products and related services are sold directly to wholesale and retail customers.

Electric

Montana’s Electric Utility Industry Restructuring and Customer Choice Act (Electric Act), was passed in 1997. Various energy-related legislation revised and refined the Act during the legislative sessions that followed. The 2003 Legislature established us as the permanent default supplier and set the transition period for all customers to be able to choose their electric supplier to end July 1, 2027. As default supplier, we are obligated to continue to supply electric energy to customers in our service territory who have not chosen, or have not had an opportunity to choose, other power suppliers. The 2003 legislation also requires smaller customers to remain as default supply customers and established a specific set of requirements and procedures that guide power supply procurements and their cost recovery. This provides adequate assurances of recovering our costs of acquiring electric supply.

On January 23, 2003, we filed our first biannual Electric Default Supply Resource Procurement Plan with the PSC, which fulfills the requirements established by law and describes the planning we are doing on behalf of our electric default supply customers to acquire a balanced and well designed resource portfolio. We have a substantial portion of the portfolio covered by the existing PPL Montana base-load contracts and the QF contracts.

Natural Gas

Montana’s Natural Gas Utility Restructuring and Customer Choice Act, also passed in 1997, provides that a natural gas utility may voluntarily offer its customers choice of natural gas suppliers and provide open access. We have opened access on our gas transmission and distribution systems, and all of our natural gas customers have the opportunity of gas supply choice. We are also the default supplier for the remaining natural gas customers.

Regulatory Matters

The MPSC, the SDPUC, and the Nebraska Public Service Commission (NPSC) regulate our bundled transmission and distribution, services and approves the rates that we charge for these services, while the FERC regulates our transmission services. There have been no significant regulatory issues in South Dakota or Nebraska during the past three years. Current regulatory issues are discussed below.

F-29

cannot determine the impact or resolution of this petition, however, any action taken by the MPSC to increase the regulatory controls under which we operate may have a material affect on our liquidity, operations and financial condition. If we are unable to comply with any MPSC orders in a timely manner, we may become subject to material monetary penalties and fines. We are cooperating with the MCC in the discovery process, but have retained the right to argue that the investigation is stayed as a result of our Chapter 11 filing.

Electric Rates

On June 12, 2003, the MPSC approved the next annual tracking period for the stipulated competitive transition charges Qualifying Facilities Contracts, or CTC-QFs in the amount of $17.4 million to be effective July 1, 2003. On June 16, 2003, we filed our annual electric supply cost tracker request with the MPSC for any unrecovered actual electric supply costs for the 12-month period ended June 30, 2003, and for projected costs for the 12-month period ended June 30, 2004. On July 15, an interim order was approved by MPSC for the projected electric supply cost.

Natural Gas Rates

On June 2, 2003, we filed an annual gas cost tracker request with the MPSC for any unrecovered actual gas costs for the eight-month period ended June 30, 2003, and for the projected gas costs for the 12-month period ending June 30, 2004. On July 3, 2003, the MPSC issued two separate orders, a final order and an interim order, with respect to our recovery of gas costs.

The final order issued by the MPSC disallowed recovery of $6.2 million of actual natural gas costs we incurred during the past eight months. The MPSC also rejected a motion for reconsideration filed by us. We filed suit in district court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. Included in other current assets was $6.2 million, which was written off during June 2003 to comply with the final order. In the event the MPSC’s decision is overturned, we will reinstate the asset.

The MPSC also granted an interim order on July 3, 2003, for the projected gas cost adjusted for a portion of the gas portfolio at a fixed price of $3.50 per MMBTU as opposed to the market price submitted in the original filing, which was higher. Assuming our average forecast price over the next six months occurs, the impact of this disallowance on the volumes at the imputed price compared to market price would be approximately $4.5 million for the period July 1, 2003 through June 30, 2004.

In Nebraska, where natural gas companies have been regulated by the municipalities in which they serve, the 2003 Nebraska Unicameral Legislature enacted a new law during the second quarter of 2003, shifting the regulation to the NPSC. Under the new law, the NPSC regulates rates and terms and conditions of service for natural gas companies, however, the law provides that a natural gas company and the cities in which it serves have the ability to negotiate rates for natural gas service when the natural gas company files an application for increased rates. If the cities and the company choose not to negotiate or they are unable to reach an agreement, then the NPSC will review the rate filing. Our initial tariffs, including our rates, terms and conditions for service consistent with those formerly filed with the municipalities, were filed with and accepted by the NPSC.

FERC

Through a filing with FERC in April 2000, we sought recovery of transition costs associated with serving two wholesale electric cooperatives. On July 15, 2002, a FERC administrative judge issued a summary judgment dismissing the company’s claim primarily on the grounds that the filing did not use FERC methodology. On December 2, 2002, we filed a “Brief on Exceptions to the Initial Decision” aimed at reversing the initial decision. A decision by FERC was received on January 28, 2004, which affirmed the original summary judgment decision.

(19) Stock Options and Warrants

Under the NorthWestern Stock Option and Incentive Plan (“Plan”), we have reserved 3,424,595 shares for issuance to officers, key employees and directors as either incentive-based options or nonqualified options. The Compensation Committee (“Committee”) of our Board of Directors administers the Plan. Unless established differently by the Committee, the per-share option exercise price shall be the fair market value of our common stock at the grant date. The options expire 10 years following the date of grant and options issued during 2003 and prior to 2002 vest over a three-year period beginning in the third year. Options issued during 2002 vest ratably over four years from the date of grant.

In addition, in 1998, we registered 1,279,476 warrants to nonemployees to purchase shares of NorthWestern common stock at $18.225 per share in connection with a previous acquisition. During 2001, all of the remaining warrants were extinguished through a cashless exchange whereby holders received shares of our common stock equivalent to the difference between the warrant price and the market price of our common stock on the date of the exchange. 271,949 shares of common stock were issued in association with these transactions.

F-30

A summary of the activity of stock options is as follows:

	Shares		Option Price Per Share		Weighted Average Option Price

Balance December 31, 2000	1,391,521		$	21.19-$26.13	$	23.31
Issued	536,100		22.70-25.00		23.03
Canceled	(43,129	)	21.19-23.31		22.31
Balance December 31, 2001	1,884,492		21.19-26.13		23.26
Issued	786,200		15.26-20.70		20.61
Canceled	(1,132,527	)	20.30-26.13		22.45
Balance December 31, 2002	1,538,165		15.26-26.13		22.49
Issued	500,623		2.05-4.90		3.97
Canceled	(679,600	)	20.30-26.13		22.23
Balance December 31, 2003	1,359,188				15.81

Options Exercisable as of:

	Shares	Option Price Per Share		Weighted Average Option Price

December 31, 2001	72,488	$	21.19-$26.13	$	23.11
December 31, 2002	245,421	20.70-26.13		23.73
December 31, 2003	315,404	20.70-26.13		23.53

We follow Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees’ to account for stock option plans. No compensation cost is recognized because the option exercise price is equal to the market price of the underlying stock on the date of grant.

An alternative method of accounting for stock options is SFAS No. 123, Accounting for Stock-Based Compensation. Under SFAS No. 123, stock options are valued at grant date using the Black-Scholes valuation model and compensation cost is recognized ratably over the vesting period. SFAS No. 123 also requires disclosure of pro forma net income and earnings per share had the estimated fair value of option grants on their grant date been charged to compensation expense. The weighted average Black-Scholes fair value of the options granted under the stock option plan during 2003, 2002 and 2001 was $1.63, $8.45 and $3.17, respectively. The weighted average remaining contractual life of the options outstanding at December 31, 2003, was 7.63 years. The table in Note 4 illustrates the effect on net income and earnings per share had the fair value of option grants been charged to compensation expense in the Consolidated Statements of Income (Loss).

The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions:

	2003		2002		2001
Expected life (years)	8		8		8
Interest rate	4.0	%	4.0	%	5.1	%
Volatility	26.5	%	26.5	%	18.8	%
Dividend yield	—		—		5.2	%

We issued 283,333 shares of common stock in 2003 under a restricted stock plan with a fair value at date of issuance of $1.2 million. The stock vests over a three-year period and compensation expense is recognized ratably over the vesting period. We previously issued 33,480 shares of common stock in 2001 under this restricted stock plan with a fair value at date of issuance of $0.7 million. In 2003 the 2001 shares were forfeited and year-to-date compensation expense reversed. Compensation expense for the years ended December 31, 2003, 2002, and 2001, of $0.3 million, $0.5 million and $0.2 million, respectively, has been recognized.

(20) Earnings (Loss) Per Share

Basic earnings per share is computed on the basis of the weighted average number of common shares outstanding. Diluted

F -31

earnings per share is computed on the basis of the weighted average number of common shares outstanding plus the effect of the outstanding stock options and warrants. Average shares used in computing the basic and diluted earnings per share for 2003, 2002 and 2001 were as follows:

	2003	2002	2001
Basic computation	37,396,762	29,725,529	24,390,184
Dilutive effect of
Stock options	—	—	19,364
Stock warrants	—	—	45,760
Diluted computation	37,396,762	29,725,529	24,455,308

Certain outstanding antidilutive options and warrants have been excluded from the earnings per share calculations. These options and warrants total 1,359,188 shares, 1,538,165 shares and 1,221,876 shares in 2003, 2002 and 2001, respectively.

(21) Guarantees, Commitments and Contingencies

Qualifying Facilities Liability

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 $1.8 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates and payments from the MPSC, totaling approximately $1.4 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 (using an 8.75% discount factor) of the difference between our obligations under the QFs and the related amount recoverable. At December 31, 2003, the liability was $142.8 million.

The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):

	Gross obligation		Recoverable amounts		Net
2004	$	54,823	($44,652	)	$	10,171
2005	56,579		(52,647	)	3,932
2006	58,468		(52,681	)	5,787
2007	60,634		(53,222	)	7,412
2008	62,931		(53,750	)	9,181
Thereafter	1,525,238		(1,138,340	)	386,898
Total	$	1,818,673	($1,395,292	)	$	423,381

Long Term Power Purchase Obligations

We have entered into various commitments, largely purchased power, coal and natural gas supply, electric generation construction and natural gas transportation contracts. These commitments range from one to 30 years. The commitments under these contracts as of December 31, 2003, were $251.0 million in 2004, $227.7 million in 2005, $165.0 million in 2006, $98.4 million in 2007, $45.3 million in 2008 and $448.5 million thereafter. These commitments are not reflected in our Consolidated Financial Statements.

Employment Contracts

F -32

The former agreements provided for the payment of accrued salary and termination benefits if employment was terminated by NorthWestern for any reason other than Cause, due to death or by the employee due to a “fundamental change.” A fundamental change generally occurs if there is a diminution in the employee’s responsibilities or compensation, NorthWestern relocates its primary offices more than 30 miles or there is a change in control or major transaction involving NorthWestern (each as defined in the agreement). The termination benefits included a lump sum payment equal to (1) the sum of (a) base salary, (b) the higher of either the employee’s most recent bonuses and short-term incentive awards or the average of such bonuses and awards over the preceding three calendar years and (c) the higher of either the value of the employee’s most recent options, long-term incentive awards and private equity investment returns or the average value of such options, awards and returns over the preceding three calendar years, multiplied by (2) the remaining term of the agreement plus one year. The termination benefits also included lump sum payments equal to the employee’s interests under NorthWestern’s benefit plans. The Executive had the right to defer receipt of certain of these termination benefits rather than receiving them as a lump sum. All equity awards granted to him accelerated in full upon termination of the agreement (other than for Cause) and remained exercisable in accordance with their terms. NorthWestern had agreed to make gross-up payments to him to the extent that termination benefits would be subject to the excise tax on excess “parachute payments” following a change of control. The termination benefits under these agreements were to be provided regardless of whether the employee is able to obtain other employment. The agreements contained provisions requiring the Executive to maintain the confidentiality of NorthWestern proprietary information and restricted him from competing with NorthWestern or soliciting NorthWestern employees, suppliers and customers for a period of two years following termination. NorthWestern had agreed, pursuant to the agreement, to indemnify him to the fullest extent permitted by law.

We have contractual arrangements with two other executive officers, Chief Restructuring Officer William M. Austin, one of the named executives, and Chief Financial Officer Brian B. Bird.

We have a Memorandum of Engagement with Mr. Austin, which, as amended and approved by the Bankruptcy Court in its Order dated October 10, 2003, terminates on the earlier of 18 months or the effective date of a confirmed reorganization plan, unless extended by mutual agreement. Under the agreement Mr. Austin, as he serves as Chief Restructuring Officer, is entitled to a base salary, a time-based addition, and an incentive-based addition. The agreement provides that if an effective date of a reorganization plan occurs before scheduled completion of the above distributions, the payments not yet made will be fully earned and paid on the effective date. The agreement also provides for severance if Mr. Austin is involuntarily terminated or otherwise as a result of the bankruptcy proceedings and indemnification by us for claims made in connection with his engagement as Chief Restructuring Officer.

We also have an Employment Agreement with Mr. Bird, which, as amended and approved by the Bankruptcy Court in its Order dated January 13, 2004, provides for him to serve as Chief Financial Officer, commencing December 1, 2003, and extends until the earlier of his termination of employment or December 1, 2005. Mr. Bird’s compensation package consists of a sign-on bonus, a base salary and performance-based incentive of up to his annual salary. Mr. Bird is also entitled to participate in our benefit plans available to executives, including, among other things, health, retirement, disability and life insurance benefits. The agreement provides that if an effective date of a reorganization plan, or the consummation of a sale of NorthWestern occurs before scheduled completion of the above distributions, then payments not yet made will be fully earned and paid on the effective date. The agreement also provides for severance if Mr. Bird is terminated for any reason other than Cause.

Residual Value Guarantees

We have residual value guarantees related to certain vehicles under operating leases by Blue Dot, in the event of default and subsequent failure to cure such default. At December 31, 2003, the maximum exposure under the residual value guarantees is approximately $5.2 million.

F -33

Performance Bonds and Letters of Credit

We have various letter of credit requirements and other collateral obligations of approximately $16.4 million and $48.1 million as of December 31, 2003 and 2002, respectively.

Blue Dot and Expanets have obtained various license, bid and performance bonds in place to secure the performance of contracts and the adequate provision of services. The total amount of outstanding surety bonds obtained by Blue Dot and Expanets is approximately $59.5 million as of December 31, 2003. Due to the completion of work and as a result of the sale of Expanets and certain Blue Dot businesses, we estimate the amount of the underlying obligations that such bonds secure is $3.5 million and $14.3 million as of December 31, 2003 and 2002, respectively.

The surety bonds obtained by Blue Dot and Expanets are supported by indemnity agreements that we entered into for the benefit of Blue Dot and Expanets and are secured by various letters of credit obtained by Blue Dot, Expanets, or us. Approximately $10 million and $18.6 million of these letter of credit and other collateral obligations as of December 31, 2003 and 2002, respectively, serve to support performance bonds primarily related to Blue Dot and Expanets. In addition, included in other assets at December 31, 2003, is $7.1 million of deposits that support performance bonds related to Blue Dot and Expanets. No such amounts existed at December 31, 2002.

Environmental Liabilities

We are subject to numerous state and federal environmental regulations. Because laws and regulations applicable to our businesses are continually developing and are subject to amendment, reinterpretation and varying degrees of enforcement, we may be subject to, but can not predict with certainty the nature and amount of future environmental liabilities. The Clean Air Act Amendments of 1990 (the Act) stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We believe we can comply with such sulfur dioxide emission requirements at our generating plants and that we are in compliance with all presently applicable environmental protection requirements and regulations. We also are subject to other environmental statutes and regulations including those that related to former manufactured gas plant sites and other past and present operations and facilities. In addition, we may be subject to financial liabilities related to the investigation and remediation from activities of previous owners or operators of our industrial and generating facilities. The range of exposure for environmental remediation obligations at present is estimated to range between $43.9 million to $82.7 million.

During the third quarter of 2003, we engaged the services of an environmental consulting firm to perform a comprehensive evaluation of our historical and current utility operations and facilities. Based upon the results of the evaluation, we increased our environmental reserve by $7.4 million. Our environmental reserve accrual is $43.9 as of December 31, 2003. This reserve was established and adjusted during the current year in anticipation of future remediation activities at our various South Dakota, Nebraska and Montana environmental sites and does not factor in any exposure arising from private tort actions or government claims for damages allegedly associated with specific environmental conditions.

In light of the Environmental Protection Agency’s public announcement in April 2003, favoring removal of the Milltown Dam structure as part of the remedy to address heavy metals contamination in the Milltown Reservoir, we commenced negotiations with The Atlantic Richfield Company, or ARCO, to prevent a challenge from ARCO to our statutorily exempt status under the Comprehensive Environmental Response Compensation and Liability Act as a potentially responsible party. On September 10, 2003, we executed a confidential settlement agreement with ARCO which, among other things, caps our maximum contribution towards remediation of the Milltown Reservoir superfund site. Previously, NorthWestern and ARCO executed a settlement agreement which caps our potential liability for remediation of the Milltown site at no more than $10 million. We are currently seeking approval of this settlement agreement from the Bankruptcy Court. The amount of our expected contribution has been fully accrued in the accompanying financial statements. Commencing in the month following Bankruptcy Court approval of the ARCO settlement agreement and each month thereafter, we will pay $500,000 into an escrow account managed by a third party until our total agreed upon amount is funded. No interest will accrue on the unpaid balance due ARCO. The escrow account will remain funded until a final, nonappealable consent decree is entered by the United States District Court. If, however, we are unable to negotiate an acceptable consent decree with the interested parties, then we can terminate the settlement agreement with ARCO, which will trigger the return of the escrowed funds to us. The settlement agreement, which is subject to Bankruptcy Court approval, provides us with appropriate ARCO releases and indemnifications.

Legal Proceedings

We, and certain of our present and former officers and directors, were named as defendants in numerous complaints purporting to

F -34

be class actions which were filed in the United States District Court for the District of South Dakota, Southern Division, alleging violations of Sections 11, 12 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder. The complaints contained varying allegations, including that the defendants misrepresented and omitted material facts with respect to our 2000, 2001, and 2002 financial results and operations included in its filings with the SEC, press releases, and registration statements and prospectuses disseminated in connection with certain offerings of debt, equity, and trust preferred securities. The complaints seek unspecified compensatory damages, rescission, and attorneys’ fees and costs as well as accountants’ and experts’ fees. In June 2003, the complaints were consolidated in the United States District Court for the District of South Dakota and given the caption In re NorthWestern Corporation Securities Litigation, Case No. 03-4049, and Carpenters Pension Trust for Southern California, Oppenheim Investment Management, LLC, and Richard C. Slump were named as co-lead plaintiffs (the “Lead Plaintiffs”). In July 2003, the Lead Plaintiffs filed a consolidated amended class action complaint naming NorthWestern, NorthWestern Capital Financing II and III, Blue Dot, Expanets, certain of our present and former officers and directors, along with a number of investment banks that participated in the securities offerings. The amended complaint alleges that the defendants misrepresented and omitted material facts concerning the business operations and financial performance of NorthWestern, Expanets, Blue Dot and CornerStone, overstated NorthWestern’s revenues and earnings by, among other things, maintaining insufficient reserves for accounts receivable at Expanets, failing to disclose billing problems and lapses and data conversion problems, failing to make full disclosures of problems (including the billing and data conversion issues) arising from the implementation of Expanets’ EXPERT system, concealing losses at Expanets and Blue Dot by improperly allocating losses to minority interest shareholders, maintaining insufficient internal controls, and profiting from improper related-party transactions. We, and certain of our present and former officers and directors, were also named as defendants in two complaints purporting to be class actions which were filed in the United States District Court for the Southern District of New York, entitled Sanford & Beatrice Golman Family Trust, et al. v. NorthWestern Corp., et al., Case No. 03CV3223, and Arthur Laufer v. Merle Lewis, et al., Case No. 03CV3716, which were brought on behalf of the purchasers of our 7.20%, 8.25%, and 8.10% trust preferred securities which were offered and sold pursuant to our registration statement on Form S-3 filed on July 12, 1999. The plaintiffs’ claims are based on similar allegations of material misrepresentations and omissions of fact relating to the registration statement in violation of Sections 11 and 12 of the Securities Act of 1933 and they seek unspecified compensatory damages, rescission and attorneys’, accountants’ and experts’ fees. In July 2003, Arthur Laufer v. Merle Lewis, et al. was transferred to the District of South Dakota and consolidated with the consolidated actions pending in that court. In September 2003, Sanford & Beatrice Golman Family Trust, et al. v. NorthWestern Corp., et al. was also transferred to the District of South Dakota. The actions have been stayed as to NorthWestern Corporation due to its bankruptcy filing. In October 2003, Expanets, Blue Dot, and certain of NorthWestern’s present and former officers and directors filed motions to dismiss the consolidated amended class action complaint for failure to state a claim, which are currently pending in the District of South Dakota.

On February 7, 2004, the parties to the above consolidated securities class actions and consolidated derivative litigation, together with certain other affected persons and parties, reached a tentative settlement of the litigation. Among the terms of the proposed settlement, we, Expanets, Blue Dot and other parties and persons will be released from all claims to these cases, a settlement fund in the amount of $41 million (of which approximately $37 million would be contributed by our directors and officers liability insurance carriers, and $4 million would be contributed from other persons and parties) will be established, and, if Netexit seeks bankruptcy protection, the plaintiffs would have a $20 million liquidated securities claim against Netexit. The proposed settlement is subject to the occurrence of several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding, approval of the proposed settlement by the federal District Court for the District of South Dakota, where the consolidated class actions are pending, and approval by the Bankruptcy Court of our plan of reorganization. If for any reason these conditions do not occur and the settlement is not approved, we intend to vigorously defend against these lawsuits. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

F -35

derivative litigation matters. Northwestern has not been contacted by the FBI and has not been advised that NorthWestern is the target of its investigation. We are cooperating with the SEC’s investigation and intend to cooperate with the FBI if we are contacted in connection with its investigation. We understand that the FBI or the Internal Revenue Service (IRS) may have contacted current and former employees of ours or of our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters. We cannot predict whether or not any other governmental inquiry or investigation will be commenced, nor can we predict the outcome of the SEC, FBI, IRS or any other governmental inquiry or investigation or related litigation or proceeding.

In January 2004, two of the QFs – Colstrip Electric Limited Partnership (CELP) and Yellowstone Electric Limited Partnership (YELP) – initiated adversary proceedings against NorthWestern in its Chapter 11 proceedings. In the CELP adversary proceeding, CELP seeks additional payment for capacity contracted to be provided to NorthWestern under its existing power purchase agreement. In the YELP adversary proceeding, YELP seeks a determination of when and who has the right to determine the scheduling of maintenance on the power facility. We intend to vigorously defend against these adversary proceedings. In the opinion of management, the amount of ultimate liability with respect to these adversary proceedings will not materially affect our financial position or results of operations or our ability to timely confirm a plan of reorganization.

In Northwestern Corporation vs. PPL Montana, LLC vs. Northwestern Corporation and Clark Fork and Blackfoot, LLC, No. CV-02-94-BU-SHE, (D. MT), the Company is pursuing claims against PPL Montana, LLC due to its refusal to purchase the Colstrip transmission assets which under the Asset Purchase Agreement (“APA”) executed by and between The Montana Power Company (“MPC”) and PP&L Global, Inc. (“PPL Global”), NorthWestern claims PPL Montana, LLC (“PPL”) (PPL Global’s successor-in-interest under the APA) is required to purchase the Colstrip transmission assets for $97.1 million. PPL has also asserted a number of counterclaims against NorthWestern and Clark Fork based in large part upon PPL’s claim that MPC and/or NorthWestern Energy breached two Wholesale Transition Service Agreements and certain indemnification obligations under the APA in the approximate amount of $40 million. PPL has moved the Bankruptcy Court for relief from the automatic stay to pursue its counterclaims. PPL also filed a proof of claim against NorthWestern’s bankruptcy estate. NorthWestern has objected to PPL’s motion to lift the automatic stay and has also filed a motion to transfer the venue of the entire litigation to the United States District Court for the District of Delaware, where it will ultimately be referred to the United States Bankruptcy Court for the District of Delaware so as to resolve the litigation as part of NorthWestern’s pending bankruptcy reorganization. PPL has objected to such motion and a hearing is scheduled on NorthWestern’s motion in March 2004.

F -36

acquisitions, overstating earnings and net income, and that it lacked adequate internal controls. All of the lawsuits have now been consolidated and Gilbert H. Lamphere has been named as lead plaintiff. The actions have been stayed as to NorthWestern Corporation due to its bankruptcy filing. On October 27, 2003, the plaintiffs filed an amended consolidated class action complaint. The new complaint does not name NorthWestern as a defendant, although it alleges facts relating to NorthWestern’s conduct. Certain of our former officers and directors are named as defendants in the amended consolidated complaint. The plaintiffs seek compensatory damages, prejudgment and post judgment interest and costs, injunctive relief, and other relief. We intend to vigorously defend against these lawsuits. On November 6, 2003, the Bankruptcy Court entered an order approving a stipulation between NorthWestern and plaintiffs in this litigation. The stipulation provides that litigation as against NorthWestern shall be temporarily stayed for 180 days from the date of the stipulation. Pursuant to the stipulation and after providing notice to Northwestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

We were named in a complaint filed against CornerStone Propane GP, Inc., CornerStone Propane Partners LP and other defendants in a lawsuit entitled Leonard S. Mewhinney, Jr. v. Northwestern Corporation in the circuit court of the city of St. Louis, state of Missouri. The complaint alleges that the plaintiff purchased units of Cornerstone Propane Partners, LP between March 13, 1998 and November 29, 2001 and that NorthWestern owned and controlled all or the majority of stock or other indicia of ownership of Cornerstone Propane, GP, Inc. and all other entities that were the general partners of Cornerstone Propane Partners, LP. According to the plaintiff, NorthWestern, Cornerstone Propane GP, Inc., Coast Gas, Inc. and Cornerstone Propane Partners, LP breached fiduciary duties to the plaintiff by engaging in certain misconduct, including mismanaging Cornerstone Propane Partners, LP and transferring its assets for less than market value and other activities. The complaint further alleges that the defendants fraudulently failed to disclose material information regarding the value of units of Cornerstone Propane Partners, LP and violated the Florida Securities Act in connection with the sale of such units. The plaintiff seeks compensatory damages, punitive damages and costs. The complaint was amended to add a state class action claim. All defendants filed a petition to remove the case to the federal court in St. Louis, Missouri, but the federal court granted plaintiffs motion to remand. The case has now been stayed against NorthWestern due to its bankruptcy filing. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

Certain of our present and former officers and directors, and CornerStone Propane Partners, LP, as a nominal defendant, are among other defendants named in two derivative actions commenced in the Superior Court for the State of California, County of Santa Cruz, entitled Adelaide Andrews v. Keith G. Baxter, et al., Case No. CV146662 and Ralph Tyndall v. Keith G. Baxter, et al., Case No. CV146661. These derivative lawsuits allege that the defendants breached various fiduciary duties based upon the same general set of alleged facts and circumstances as the federal unitholder suits. The plaintiffs seek unspecified compensatory damages, treble damages pursuant to the California Corporations Code, injunctive relief, restitution, disgorgement, costs, and other relief. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition or ability to timely confirm a plan of reorganization.

On April 30, 2003, Mr. Richard Hylland, our former President and Chief Operating Officer, filed a demand for arbitration of contract claims under his employment agreement, as well as tort claims for defamation, infliction of emotional distress and tortious interference and a claim for punitive damages. Mr. Hylland is seeking relief in an amount of $25 million, plus interest, attorney’s fees, costs, and punitive damages. Mr. Hylland has also filed claims in our bankruptcy case similar to the claims in his arbitration demand. We dispute Mr. Hylland’s claims and intend to vigorously defend the arbitration and object to Mr. Hylland’s claims in our bankruptcy case. On May 6, 2003, based on the recommendations of the Special Committee of the Board formed to evaluate Mr. Hylland’s performance and conduct in connection with the management of NorthWestern and its subsidiaries, the Board determined that Mr. Hylland’s performance and conduct as President and Chief Operating Officer warranted termination under his employment contract. This arbitration has been stayed due to our bankruptcy filing.

F -37

proceeding is stayed as a result of our bankruptcy filing.

Other Contractual Obligations

On June 19, 2002, NorthWestern Energy Marketing, LLC (NEM), our power marketing subsidiary, 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. NEM secured supply to cover these contractual obligations through June 30, 2003. Due to our financial condition, NEM has been unable to secure a source of power to cover its contractual obligation subsequent to June 30, 2003. Based on the uncertainty of supply, as of July 1, 2003, the two customers elected to secure their power supply needs from the Montana default supply. Shortly thereafter, the customers notified NEM that they would seek damages to compensate them for their increased power supply costs. NEM reached a settlement with its two customers on October 27, 2003, and subsequently paid $1.5 million in full settlement of its obligations.

The maximum aggregate amount of payments that may be required of NorthWestern under various Blue Dot minority shareholder agreements is approximately $2.3 million as of December 31, 2003, of which approximately $0.4 million may be required within the next 12 months.

(22) Capital Stock

In December 1996, our Board of Directors declared, pursuant to a shareholders’ rights plan, a dividend distribution of one Right on each outstanding share of our common stock. Each Right becomes exercisable, upon the occurrence of certain events, at an exercise price of $50 per share, subject to adjustment. The Rights are currently not exercisable and will be exercisable only if a person or group of affiliated or associated persons (“Acquiring Person”) either acquires ownership of 15% or more of our common stock or commences a tender or exchange offer that would result in ownership of 15% or more. In the event we are acquired in a merger or other business combination transaction or 50% or more of our consolidated assets or earnings power are sold, each Right entitles the holder to receive such number of shares of common stock of the Acquiring Person having a market value of two times the then current exercise price of the Right. The Rights, which expire in December 2006, are redeemable in whole, but not in part, at a price of $.005 per Right, at our option at any time until any Acquiring Person has acquired 15% or more of our common stock.

In October 2002, we completed a common stock offering of 10,000,000 shares. The offering resulted in net proceeds of $81.0 million and the funds were used to reduce short-term debt. In October 2001 we completed a common stock offering of 3,680,000 shares. The offering resulted in net proceeds of $74.9 million and the funds were used to redeem certain subsidiary equity arrangements and for general corporate purposes, including reducing debt. We also issued 283,333 shares of common stock in 2003 under the stock option and incentive plan. (See Note 19, Stock Options and Warrants, for further details.). Our common stock will be cancelled in connection with the adoption of our plan of reorganization.

We are authorized to issue 1,000,000 shares of $100 par cumulative preferred stock. As of December 31, 2001, there were 37,500 shares outstanding of which 26,000 were 4¹/₂% Series and 11,500 were 6¹/₂% Series, all of the shares of which were redeemed during 2002.

We are authorized to issue a maximum of 1,000,000 shares of preference stock at a par value of $50 per share. No preference shares have been issued.

Treasury stock previously held by us represented shares held by our deferred compensation plan. This plan was terminated in 2003 and all treasury stock was distributed. (See Note 15, Employee Benefit Plans for further discussion.)

F -38

(23) Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

Series	Par Value		Shares	2003		2002
				(in thousands)
8.125%	$	25	1,294,200	$	32,355	$	32,500
7.20%	$	25	2,157,300	53,932		55,000
8.25%	$	25	4,228,400	105,710		106,750
8.10%	$	25	4,342,100	108,553		111,000
8.45% Montana Power	$	25	2,600,000	65,000		65,000
			14,622,000	$	365,550	$	370,250

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. Montana Power had established Montana Power Capital I (Trust) as a wholly owned business trust to issue common and preferred securities and hold Junior Subordinated Deferrable Interest Debentures. The sole assets of these trusts are the investments in Subordinated Debentures. The trusts use the interest payments received on the Subordinated Debentures to make quarterly cash distributions on the preferred securities. These Subordinated Debentures are unsecured and subordinated to all of our other liabilities and rank equally with the guarantees related to the other trusts.

As discussed in Note 4, under New Accounting Standards, these securities are now presented as liabilities on our December 31, 2003 Consolidated Balance Sheet. Pursuant to our bankruptcy filing, these trusts were terminated pursuant to their terms and the preferred securities became direct obligations of NorthWestern Corporation. These preferred securities are subject to compromise and they will be cancelled or converted to equity at a substantially reduced value upon emergence from bankruptcy.

(24) Segment and Related Information

We currently operate our business in three reporting segments: (i) electric utility operations, (ii) natural gas utility operations, and (iii) all other, which primarily consists of our other miscellaneous service and nonenergy-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. Items below operating income are not allocated between our electric and natural gas segments.

The results of operations of our electric and natural gas utility segments and all other operations for the year ended December 31, 2002, include the results of our Montana operations since February 1, 2002, the effective date of our acquisition. The operations of Expanets, Blue Dot and CornerStone, which were formerly additional reporting segments, and our interest in these subsidiaries has been reflected in the consolidated financial statements as Discontinued Operations (see Note 8 for further discussion).

F -39

The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses and interest expense to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments, excluding discontinued operations, are as follows (in thousands):

2003	Electric		Gas		Total Electric and Natural Gas			All Other			Total

Operating revenues	$	673,078	$	344,766	$	1,017,844		$	9,593		$	1,027,437
Cost of sales	312,756		235,019		547,775			2,814			550,589
Gross margin	360,322		109,747		470,069			6,779			476,848
Operating, general, and administrative	184,496		72,713		257,209			50,049			307,258
Impairment on assets held for sale	—		—		—			12,399			12,399
Depreciation	54,456		14,037		68,493			1,759			70,252
Reorganization expenses	—		—		—			8,280			8,280
Operating income (loss)	121,370		22,997		144,367			(65,708		)	78,659
Interest expense	N/A		N/A		(95,556		)	(52,070		)	(147,626		)
Gain on debt extinguishment	N/A		N/A		—			3,300			3,300
Investment income and other	N/A		N/A		2,970			(8,947		)	(5,977		)
Reorganization interest income	N/A		N/A		—			14			14
Income (loss) before taxes and minority interests	N/A		N/A		51,781			(123,411		)	(71,630		)
Benefit (provision) for taxes	N/A		N/A		(15,681		)	15,729			48
Income (loss) before minority interests	N/A		N/A		$	36,100		$	(107,682	)	$	(71,582	)
Total assets	N/A		N/A		$	2,058,248		$	279,760		$	2,338,008
Capital expenditures	N/A		N/A		$	70,653		$	84		$	70,737

2002	Electric		Gas		Total Electric and Natural Gas			All Other			Total

Operating revenues	$	533,929	$	239,799	$	773,728		$	10,016		$	783,744
Cost of sales	205,607		133,124		338,731			2,795			341,526
Gross margin	328,322		106,675		434,997			7,221			442,218
Operating, general, and administrative	169,729		60,237		229,966			38,252			268,218
Impairment on assets held for sale	—		—		—			35,729			35,729
Depreciation	48,888		12,551		61,439			1,801			63,240
Amortization	—		—		—			19			19
Operating income (loss)	109,705		33,887		143,592			(68,580		)	75,012
Interest expense	N/A		N/A		(81,149		)	(16,861		)	(98,010		)
Loss on debt extinguishment	N/A		N/A		—			(20,688		)	(20,688		)
Investment income and other	N/A		N/A		2,709			(8,190		)	(5,481		)
Income (loss) before taxes and minority interests	N/A		N/A		65,152			(114,319		)	(49,167		)
Benefit (provision) for taxes	N/A		N/A		(10,190		)	50,001			39,811
Income (loss) before minority interests	N/A		N/A		$	54,962		$	(64,318	)	$	(9,356	)
Total assets	N/A		N/A		$	2,186,817		$	157,725		$	2,344,542
Capital expenditures	N/A		N/A		$	119,664		$	28,183		$	147,847

F -40

2001	Electric		Gas		Total Electric and Natural Gas			All Other			Total

Operating revenues	$	106,995	$	144,213	$	251,208		$	3,943		$	255,151
Cost of sales	23,052		119,060		142,112			3,456			145,568
Gross margin	83,943		25,153		109,096			487			109,583
Operating, general, and administrative	27,734		14,550		42,284			19,446			61,730
Depreciation	13,193		3,235		16,428			1,495			17,923
Amortization of goodwill and other intangibles	—		—		—			269			269
Restructuring charge	3,329		1,170		4,499			7,272			11,771
Operating income (loss)	39,687		6,198		45,885			(27,995		)	17,890
Interest expense	N/A		N/A		(8,692		)	(19,017		)	(27,709		)
Investment income and other	N/A		N/A		306			6,828			7,134
Income (loss) before taxes and minority interests	N/A		N/A		37,499			(40,184		)	(2,685		)
Benefit (provision) for taxes	N/A		N/A		(11,857		)	18,717			6,860
Income (loss) before minority interests	N/A		N/A		$	25,642		$	(21,467	)	$	4,175
Capital expenditures	N/A		N/A		$	17,676		$	62,619		$	80,295

(25) Quarterly Financial Data (Unaudited)

The following table sets forth certain unaudited financial data for each of the quarters within fiscal 2003 and 2002. During the second quarter of 2003 we committed to a plan to sale or liquidate our interest in Expanets and Blue Dot and accounted for our interest in these subsidiaries as discontinued operations. Accordingly, the amounts below have been restated to reflect these subsidiaries as discontinued operations. The operating results for any quarter are not necessarily indicative of results for any future period. Amounts presented are in thousands, except per share data:

2003	First			Second			Third			Fourth
	(in thousands except per share amounts)

Operating revenues	$	288,723		$	235,529		$	235,388		$	267,797
Gross margin	133,564			106,231			114,302			122,751
Operating income	43,026			1,342			17,527			16,764
Net income (loss)	$	17,392		$	(50,337	)	$	(52,740	)	$	(28,040	)
Average common shares outstanding	37,397			37,397			37,397			37,397
Loss per average common share (basic and diluted):
Net income (loss) from continuing operations	$	(.17	)	$	(1.20	)	$	(.79	)	$	(.15	)
Discontinued operations	.44			(.35		)	(.62		)	(.60		)
Net income	.47			(1.35		)	(1.41		)	(.75		)
Earnings (loss) on common stock	.27			(1.55		)	(1.41		)	(.75		)
Dividends per share	—			—			—			—
Stock price:
High	$	6.18		$	3.09		$	2.12		$	.32
Low	1.41			1.65			.15			.08
Quarter-end close	2.10			2.00			.30			.08

F -41

2002	First			Second			Third			Fourth
	(in thousands except per share amounts)

Operating revenues	$	176,066		$	177,411		$	184,265		$	246,002
Gross margin	94,749			108,360			113,578			125,531
Operating income (loss)	38,165			27,631			30,588			(21,372		)
Net loss	$	(46,130	)	$	(13,893	)	$	(55,362	)	$	(748,557	)
Average common shares outstanding	27,397			27,397			27,397			36,636
Loss per average common share (basic and diluted): +
Net income (loss) from continuing operations	$	(.28	)	$	(.24	)	$	(.40	)	$	(.37	)
Discontinued operations	(1.63		)	(.55		)	(1.90		)	(20.27		)
Net loss	(1.68		)	(.51		)	(2.02		)	(20.43		)
Loss on common stock	(1.91		)	(.79		)	(2.30		)	(20.64		)
Dividends per share	$	.3175		$	.3175		$	.3175		$	.3175
Stock price:
High	$	23.64		$	22.30		$	16.90		$	9.79
Low	$	20.35		$	14.20		$	8.40		$	4.30
Quarter-end close	$	22.00		$	16.95		$	9.76		$	5.08

+ The quarterly per share amounts do not total to the annual per share amounts due to the effect of common stock issuances during the year.

F -42

INDEPENDENT AUDITORS’ REPORT

To the Shareholders and Board of Directors of NorthWestern Corporation

We have audited the consolidated financial statements of NorthWestern Corporation (a Delaware corporation) (Debtor-in-Possession) and Subsidiaries as of December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003, and have issued our report thereon dated March 15, 2004, which expresses an unqualified opinion and includes explanatory paragraphs relating to the bankruptcy proceedings and going concern uncertainty described in Note 3, the change in the methods of accounting for asset retirement obligations and company obligated mandatorily redeemable preferred securities in 2003 described in Note 4, and the change in the method of accounting for goodwill and other intangible assets in 2002 described in Note 6. Such consolidated financial statements and report are included elsewhere in this 2003 Annual Report on Form 10-K. Our audits also included the financial statement schedules of NorthWestern Corporation, listed in Item 15(a)(2). These financial statement schedules are the responsibility of the Corporation’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 15, 2004

F -43

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS

NORTHWESTERN CORPORATION AND SUBSIDIARIES

Column A	Column B		Column C				Column D			Column E
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts(1)		Deductions(2)			Balance End of Period
FOR THE YEAR ENDED DECEMBER 31, 2003 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts	$	1,837	$	5,010	—		$	(4,871	)	$	1,976
ACCRUED EXPENSES
Restructuring liability	$	1,783	—		—		$	(1,783	)	—
FOR THE YEAR ENDED DECEMBER 31, 2002 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts	$	444	$	3,883	$	1,675	$	(4,165	)	$	1,837
ACCRUED EXPENSES
Restructuring liability	$	10,401	—		—		$	(8,618	)	$	1,783
FOR THE YEAR ENDED DECEMBER 31, 2001 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts	$	536	$	1,052	—		$	(1,144	)	$	444
ACCRUED EXPENSES
Restructuring liability	—		$	11,770	—		$	(1,369	)	$	10,401

(1) Recorded via allocation of purchase price to fair value of assets and liabilities of acquired businesses.

(2) Utilization of previously recorded balances.

F -44

ITEM 1. BUSINESSES

ENERGY BUSINESSES

ITEM 6. SELECTED FINANCIAL DATA

Cash Flows

Capital Requirements

Capital Sources

Commodity Price Risk

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Changes in Internal Control Over Financial Reporting

REPORT OF COMPENSATION COMMITTEE ON EXECUTIVE COMPENSATION

REPORT OF COMPENSATION COMMITTEE
ON EXECUTIVE COMPENSATION