NorthWestern 10K/A 2001 Annual report (amended)

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United States
Securities and Exchange Commission
Washington, D.C. 20549

Form 10-K/A

(Amendment No. 2)

(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, 2001

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 (State of Incorporation)		46-0172280 (I.R.S. Employer Identification No.)
125 S. Dakota Avenue, Sioux Falls, South Dakota (Address of principal executive offices)		57104 (Zip Code)

Registrant's telephone number:605-978-2908
Securities registered pursuant to Section 12(b) of the Act:

(Title of each class)
Common Stock, $1.75 par value and related Common
Stock Purchase Rights
Company Obligated Mandatorily Redeemable Security of
Trust Holding Solely Parent Debentures, $25.00
liquidation amount
Common Stock Purchase Rights

(Name of each exchange on which registered)

All listed on New York Stock Exchange

Securities registered under Section 12(g) of the Act:
Preferred Stock, Par Value $100
(Title of Class)

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

Yes ý No o

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

The aggregate market value of the voting stock held by non-affiliates of the Registrant as of August 30, 2002 was $349,308,716.

The number of shares of Common Stock, Par Value $1.75, outstanding as of August 30, 2002 was 27,396,762.

The documents incorporated by reference are as follows:

Proxy Statement for 2002 Annual Meeting Part III

EXPLANATORY NOTE

This Amendment No. 2 (this "Amendment") to the Annual Report on Form 10-K of NorthWestern Corporation ("NorthWestern") for the year ended December 31, 2001, is filed solely for the purpose of amending Item 1 and Item 7 to provide additional disclosure in response to comments received from the Securities and Exchange Commission in connection with a review of NorthWestern's Registration Statement on Form S-4 (File No. 333-86888), which was declared effective on September 11, 2002, and to amend Item 6 and Item 8 to reflect the recharacterization of NorthWestern's investment in CornerStone Propane Partners, L.P. as a discontinued operation in NorthWestern's consolidated financial statements.

The information contained in this Amendment has been updated in certain respects to reflect developments since December 31, 2001, the date of the financial statements contained herein. This Amendment should be read together with NorthWestern's Quarterly Report on Form 10-Q, as amended, for the three month period ended March 31, 2002 and NorthWestern's Quarterly Report on Form 10-Q, as amended, for the three month period ended June 30, 2002.

REPORT CONTENTS

			Page
Part I.			3
	Special Note Regarding Forward-Looking Statements		3
	Item 1. Description of Business		4
		General Overview of Businesses	4
		Electric Operations	5
		Natural Gas Operations	15
		Communication, Network Services and Data Solutions	20
		HVAC, Plumbing and Related Services	23
		Discontinued Propane Business	26
		Environmental	28
		Intellectual Property	32
Part II.			33
	Item 6. Selected Financial Data		33
	Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations		34
	Item 8. Financial Statements and Supplementary Data		66
Part IV.			66
	Item 14. Exhibits, Financial Statement Schedules and Report on Form 8-K		66
Part V.			69
	Item 1. Index to Exhibits		69
Signatures			78
Index to Financial Statements			F-1

Part I

You should carefully consider the risk factors described below, as well as the other information included or incorporated by reference in this Annual Report on Form 10-K prior to making a decision to invest in our 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. Unless the context requires otherwise, references to "we," "us," "our" and "NorthWestern" refer specifically to NorthWestern Corporation and its subsidiaries and references to "NorthWestern Energy LLC" refer to NorthWestern Energy, L.L.C., our wholly-owned subsidiary, which was formerly known as The Montana Power, L.L.C.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements 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 in this Annual Report on Form 10-K or incorporated by reference therein or herein relating to expectation of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

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

In addition to other factors and matters discussed elsewhere in our quarterly, annual and current reports that we file with the Securities Exchange Commission, or the SEC, and which are incorporated by reference into this Annual Report on Form 10-K, some important factors that could cause actual results or outcomes for NorthWestern or our subsidiaries to differ materially from those discussed in forward-looking statements include:

•: the adverse impact of weather conditions and seasonal fluctuations;
•: unscheduled generation outages, maintenance or repairs;
•: unanticipated changes to fossil fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments;
•: developments in the federal and state regulatory environment and the terms associated with obtaining regulatory approvals and rate orders;
•: costs associated with environmental liabilities and compliance with environmental laws;
•: the rate of growth and economic conditions in our service territories and those of our subsidiaries;
•: the speed and degree to which competition enters the industries and markets in which our businesses operate;
•: the timing and extent of changes in interest rates and fluctuations in energy-related commodity prices;
•: risks associated with acquisitions, transition and integration of acquired companies, including NorthWestern Energy LLC and the Growing and Emerging Markets business, or the GEM

division, of Lucent Technologies, Inc., and the implementation of information systems and the realization of efficiencies in excess of any related restructuring charges;

•: a lack of minority interest basis, which would require us to recognize an increased share of operating losses at certain of our subsidiaries;
•: our ability to recover transition costs;
•: disallowance by the Montana Public Service Commission, or MPSC, of the recovery of the costs incurred in entering into our default supply portfolio contracts while we are required to act as the "default supplier;"
•: disruptions and adverse effects in the capital markets due to the changing economic environment;
•: our credit ratings with Standard & Poor's, Moody's and Fitch;
•: potential delays in financings or SEC filings because we changed auditors;
•: our substantial indebtedness, which could limit our operating flexibility or ability to borrow additional funds;
•: our ability to obtain additional capital to refinance our indebtedness that is scheduled to mature and for working capital purposes;
•: changes in customer usage patterns and preferences;
•: possible future actions and developments at CornerStone; and
•: changing conditions in the economy, capital markets and other factors identified from time to time in our filings with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all such factors.

Item 1. Description of Business

GENERAL OVERVIEW OF OUR BUSINESSES

We are a service and solutions company providing integrated energy, communications, air conditioning, heating, ventilation, plumbing and related services and solutions to residential and business customers throughout North America. We own and operate one of the largest regional electric and natural gas utilities in the upper Midwest of the United States. We have distributed electricity in South Dakota and natural gas in South Dakota and Nebraska since 1923 through our energy division, NorthWestern Energy, formerly NorthWestern Public Service.

On February 15, 2002, we completed the acquisition of the electric and natural gas transmission and distribution businesses of The Montana Power Company for approximately $1.1 billion, including the assumption of approximately $488.0 million in existing debt and preferred stock, net of cash received. As a result of the acquisition, we now also distribute electricity and natural gas in Montana through our wholly owned subsidiary, NorthWestern Energy LLC. We intend to transfer the energy and natural gas transmission and distribution operations of NorthWestern Energy LLC to NorthWestern Corporation during 2002 and to operate its business as part of our NorthWestern Energy division. We believe the acquisition creates greater regional scale allowing us to realize the full value of our existing energy assets and provides a strong platform for future growth. We are operating our utility business under the common brand "NorthWestern Energy" in all our service territories.

Our principal unregulated investment is in Expanets, Inc., or Expanets, a leading provider of networked communications and data services and solutions to medium-sized businesses nationwide. Expanets was founded by NorthWestern Growth Corporation, our strategic development and investment entity, in 1998. Expanets has acquired 27 independent voice and data communication equipment and service providers through December 31, 2001, including its purchase in March 2000 of the U.S. small and mid-sized business sales organization from Lucent's Enterprise Networks Group.

In addition, we own an investment in Blue Dot Services Inc., or Blue Dot, a nationwide provider of air conditioning, heating, plumbing and related services. Blue Dot was founded by NorthWestern Growth Corporation in 1997 as a combination of all of its then existing HVAC businesses. Blue Dot has acquired 94 independent HVAC service providers through December 31, 2001.

We also own an interest in CornerStone Propane Partners, L.P., or CornerStone, a publicly traded master limited partnership, which we acquired in December 1996, when it was formed. As of December 31, 2001, we controlled approximately 30% of the equity interests of CornerStone, which we operate through one of our wholly owned subsidiaries, CornerStone Propane GP Inc., that serves as managing general partner. We are the largest unitholder of CornerStone. CornerStone is a retail propane and wholesale energy related commodities distributor. For additional information relating to CornerStone, see "—Unregulated Businesses—Discontinued Propane Operations—CornerStone—Recent Developments" included elsewhere herein and Exhibits 99.2, 99.3, 99.4 and 99.5 to this Annual Report on Form 10-K for the year ended December 31, 2001.

We were incorporated in Delaware in 1923. Our principal office is located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104 and our telephone number is (605) 978-2908. We maintain an internet site athttp: //www.northwestern.com which contains information concerning us and our subsidiaries. The information contained on our internet site and those of our subsidiaries is not incorporated by reference in this Annual Report on Form 10-K and should not be considered a part of this Annual Report on Form 10-K.

For additional information related to our industry segments, see note 19 of "Notes to Consolidated Financial Statements" of our consolidated financial statements, which are included in Item 8 hereof. For information regarding our revenues, profits/losses and assets, see our consolidated financial statements included as Item 8 hereof.

REGULATED BUSINESSES

ELECTRIC OPERATIONS

Services, Service Areas and Customers

Montana

We operate a regulated electric utility business in Montana through our wholly owned subsidiary, NorthWestern Energy LLC. The electric utility business of NorthWestern Energy LLC consists of an extensive electric transmission and distribution network in Montana. NorthWestern Energy LLC's service territory covered approximately 107,600 square miles, representing approximately 73% of Montana's land area as of December 31, 2001, and included approximately 782,000 people according to the 2000 census. NorthWestern Energy LLC also transmits electricity for other utilities and power marketers in Montana. In 2001, by category, residential electric transmission and distribution sales, industrial transmission and distribution sales and commercial transmission and distribution sales accounted for approximately 28%, 38% and 34% of NorthWestern Energy LLC's electric utility revenue, respectively.

NorthWestern Energy LLC's electric transmission system consists of approximately 7,000 miles of transmission lines, ranging from 50 to 500 kilovolts, 270 circuit segments and 125,000 transmission poles with associated transformation and terminal facilities as of December 31, 2001, and extends throughout the western two-thirds of Montana from Colstrip in the east to Thompson Falls in the west. The 500

kilovolts transmission system is jointly owned and is part of the Colstrip Transmission System. Flows on this system are predominantly from east to west, transferring Colstrip generation to markets west of Montana. The 230 kilovolts and 161 kilovolts facilities form the backbone of NorthWestern Energy LLC's transmission system and are designed to deliver electricity to Montana customers. The lower voltage systems, which range from 50 Kilovolts to 115 kilovolts, provide for local area service needs. The system has interconnections with five major non affiliated transmission systems located in the Western Systems Coordinating Council area, as well as one interconnection to a system that connects with the Mid-Continent Area Power Pool region. With these interconnections, NorthWestern Energy LLC also transmits 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, 2001, NorthWestern Energy LLC delivered electricity to approximately 295,000 customers in 191 communities and their surrounding rural areas in Montana, including Yellowstone National Park. NorthWestern Energy LLC also delivered electricity to rural electric cooperatives that served approximately 76,000 customers as of December 31, 2001. NorthWestern Energy LLC's electric distribution system consisted of approximately 16,200 miles of overhead and underground distribution lines and approximately 376 transmission and distribution substations as of December 31, 2001.

South Dakota

We operate our regulated electric utility business in South Dakota through our energy division, NorthWestern Public Service, which also utilizes the NorthWestern Energy brand and operates as a vertically integrated generation, transmission and distribution utility. Our electricity revenues in South Dakota are generated primarily through:

•: residential transmission and distribution sales,
•: commercial and industrial transmission and distribution sales, and
•: wholesale sales.

We have the exclusive right to serve an assigned service area in South Dakota comprised of more than 26 counties with a combined population of approximately 101,000 people according to the 2000 census. We provided retail electricity to over 57,000 customers in 108 communities in South Dakota as of December 31, 2001. In 2001, by category (including supply for non-choice customers), commercial and industrial electric transmission and distribution sales, residential transmission and distribution sales, wholesale sales and other transmission and distribution sales accounted for approximately 43%, 33%, 21% and 3% of our electric utility revenue, respectively.

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

Our transmission and distribution network in South Dakota consisted 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, 2001. We have interconnections and pooling arrangements with the transmission facilities of Otter Tail Power Company, a division of Otter Tail Corporation; Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.; Xcel Energy Inc.; and the Western Area Power Administration. We have emergency interconnections with the transmission facilities of East River Electric Cooperative, Inc. and West Central Electric Cooperative. These interconnections and pooling arrangements enable us to arrange purchases or sales of substantial quantities of electric power and energy with other pool members and to participate in the benefits of pool arrangements.

Competition and Demand

Although Montana customers have a choice with regard to electricity suppliers, NorthWestern Energy LLC does not currently face material competition in the transmission and distribution of electricity within its Montana service territories. Direct competition does not presently exist within our South Dakota service territories for the supply and delivery of electricity. Our service area in South Dakota was assigned to us by the South Dakota Public Utilities Commission pursuant to the South Dakota Public Utilities Act, effective March 1976. Pursuant to the South Dakota Public Utilities Commission grant, we have the exclusive right to provide fully bundled services to all present and future electric customers within our assigned territory for so long as the service provided is adequate. There have been no allegations of inadequate service since assignment in 1976. The assignment of a service territory is perpetual under current South Dakota law.

We sell a portion of the electricity generated in facilities that we own jointly into the wholesale market. We face competition from other electricity suppliers with respect to our wholesale sales. However, we make such wholesale sales with respect to electricity in excess of our load requirements and such sales are not a material part of our business or operating strategy.

Competition for various aspects of electric services is being introduced throughout the country that will open utility markets to new providers of some or all traditional utility services. Competition in the utility industry is likely to result in the further unbundling of utility services as has occurred in Montana. Separate markets may emerge for generation, transmission, distribution, meter reading, billing and other services currently provided by utilities as a bundled service. At present it is unclear when or to what extent further unbundling of utility services will occur. We do not expect deregulation in South Dakota in the near future, but it is unclear if and when such competition will begin to affect our other territories. Some competition currently exists within our Montana, South Dakota and Nebraska 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 or Montana Energy LLC's operations. Potential competitors may also include various surrounding providers as well as national providers of electricity.

In our NorthWestern Energy LLC service areas, peak demand was approximately 1,290 megawatts, the average daily load was approximately 932 megawatts, and over 340,250 megawatts were delivered during the year ended December 31, 2001. In our South Dakota service areas, peak demand was approximately 294 megawatts, the average daily load was approximately 150 megawatts, and over 64,580 megawatts were delivered during the year ended December 31, 2001.

Electricity Supply

Montana

In Montana, NorthWestern Energy LLC purchases substantially all of its power from third parties. Electric resource capacity in Montana is currently provided by 15 "qualifying facility" contracts that The Montana Power Company was required to enter into under the Public Utility Regulatory Policies

Act of 1978, which provide a total of 101 megawatts of firm winter peak capacity. NorthWestern Energy LLC's Milltown Dam provides an additional three megawatts of gross capacity. NorthWestern Energy LLC also has power-purchase agreements with PPL Montana and Duke Energy that meet current energy requirements beyond what are received from the "qualifying facility" contracts and Milltown Dam. NorthWestern Energy LLC believes that these arrangements in conjunction with its ability to make open market purchases, are sufficient to meet its power supply needs through June 30, 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 will be able to choose their electric supplier during a transition period beginning on July 1, 2002 through June 30, 2007. NorthWestern Energy LLC is required to act as the "default supplier" for customers who have not chosen an alternate supplier. The Montana Restructuring Act provided for the full recovery of costs incurred in procuring default supply contracts during this transition period. In its 2001 session, the Montana Legislature passed House Bill 474, which, among other things, reaffirmed full cost recovery for the default supplier by mandating that the MPSC use an electric cost recovery mechanism providing for full recovery of prudently incurred electric energy supply costs. Initiative 117 has been approved for inclusion on the November ballot in Montana. If passed, Initiative 117 would repeal HB 474. In the event that HB 474 is repealed, Montana law would continue the transition period through at least June 30, 2007, and provide full cost recovery.

On October 29, 2001, The Montana Power Company filed with the MPSC its initial default supply portfolio, containing a mix of long and short-term contracts from new and existing power suppliers and generators. On April 25, 2002, the MPSC approved NorthWestern Energy LLC's proposed "cost recovery mechanism" in the form filed. On June 21, 2002, the MPSC issued a final order approving contracts meeting approximately 60% of the default supply winter peak load and approximately 93% of the annual energy requirements, and choosing not to preapprove five proposed contracts relating to new generation construction projects, including a contract for 150 megawatts in winter and 75 megawatts in summer with Montana First Megawatts, a 240 megawatt gas-fired generation project being constructed by a NorthWestern subsidiary in Great Falls, Montana. In refusing preapproval of the new generation contracts, the MPSC stated that "prudently incurred costs related to electricity procured from new generation projects are fully recoverable in rates," but that the former owner of NorthWestern Energy LLC did not adequately document and explain its analysis and judgments which led to the specific mix of resource types, products, contract lengths, price stability, dispatchability, risk and other characteristics of the chosen portfolio. As a result of the order, NorthWestern Energy LLC will seek to obtain the remainder of the default supply portfolio through a combination of resubmitting certain previously-denied power purchase contracts conforming to the MPSC's guidance, together with new power purchase contracts, and making open market purchases. Currently, NorthWestern Energy LLC 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 an annual electricity cost tracking process pursuant to which rates are based on estimated electricity loads and electricity costs for the upcoming tracking period and are annually reviewed and adjusted by the MPSC for any differences in the previous tracking year's estimates to actual information. This process is similar to the cost recovery process that has been successfully utilized for more than 20 years in Montana, South Dakota and other states for natural gas purchases for residential and commercial customers. The MPSC further stated that NorthWestern Energy LLC has an ongoing responsibility to prudently administer its supply contracts and the energy procured pursuant to those contracts for the benefit of ratepayers. We expect that the costs of the default supply portfolio and a competitive transition charge for out-of-market costs will increase residential electric rates in NorthWestern Energy LLC's service territories by less than 10% during the first year.

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.

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

South Dakota

Most of the electricity that we supply to customers in South Dakota is generated in power plants that we own jointly. In addition, we have peaking/standby generating units that are installed at nine locations throughout our service territory. Details of our generating facilities are described further in the chart below. Each of the jointly owned plants is subject to a joint management structure. Except as otherwise noted, we are entitled to a proportional share of the electricity generated in our jointly owned plants and are responsible for a proportional share of the operating expenses, based upon our ownership interest. Most of the power allocated to us from these facilities is distributed to our South Dakota customers, although in 2001, approximately 21% of the power was sold in the wholesale market. Our facilities had a total net summary peaking capacity in 2001 of approximately 312 megawatts.

Name and Location of Plant	Fuel Source	Our Ownership Interest		Our Share of 2001 Peak Summer Demonstrated Capacity	% of Total 2001 Peak Summer Demonstrated Capacity
Big Stone Generating Station, located near Big Stone City in northeastern South Dakota	Sub-bituminous coal	23.4	%	106.8 megawatts	34.2	%
Coyote I Electric Generating Plant, located near Beulah, North Dakota	Lignite coal	10	%	42.7 megawatts	13.7	%
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa	Sub-bituminous coal	8.7	%	55.9 megawatts	17.9	%
Miscellaneous combustion turbine units and small diesel units (used only during peak periods)	Combination of fuel oil and natural gas	100	%	106.6 megawatts	34.2	%

Total Capacity				312.0 megawatts	100.0	%

We have also entered into an agreement to purchase up to 28 megawatts of firm summer capacity from Basin Electric Generating Co. to assist in meeting peak demands during the summers of 2001-2003.

The 2001 peak demand in our South Dakota service areas was approximately 294 megawatts and the average daily load in South Dakota during 2001 was approximately 150 megawatts. Our share of generation capacity from jointly owned plants exceeded average daily load in 2001 and our total system capability through our generating facilities and supply contract with Basin Electric Generating at the time of peak demand was approximately 333 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 an integrated 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.

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 Federal Energy Regulatory Commission, or FERC.

On March 27, 2001, we announced our plan to construct Montana First Megawatts, a 240 megawatt, natural gas-fired, combined-cycle electric generation facility. We commenced construction of the facility, located in Great Falls, Montana, in early November 2001. The facility is fully permitted and we estimate that the construction time to complete the project is less than twelve months. We anticipate that the project will be completed in the fall of 2003 and that upon completion we, or one of our wholly owned subsidiaries, will own 100% of the facility. We estimate construction, development and related costs will be approximately $180.0 million. For further information relating to the financing of the Montana First Megawatts project, see "Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources—Material Borrowings—Nonrecourse Debt" included in Item 7 hereof.

Electricity Generation Costs

Coal was used to generate approximately 95% of our electricity for the year ended December 31, 2001. The balance was provided by our natural gas and fuel oil peaking units. We have no nuclear exposure. The fuel for our jointly owned generating plants is provided primarily through supply contracts of various lengths with several coal companies. Our coal supply costs have remained relatively stable during the past three years. 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,
Fuel Type	Cost per Million BTU for the Year Ended December 31,						Percent of 2001 Megawatt Hours Generated
Fuel Type	1999		2000		2001		Percent of 2001 Megawatt Hours Generated
Sub-bituminous-Big Stone	$	.95	$	.96	$	1.07	52.4	%
Lignite-Coyote **		.82		.83		.75	20.0
Sub-bituminous-Neal		.74		.80		.71	27.1
Natural Gas		2.78		5.40		4.26	*
Oil		4.23		4.31		5.16	*

*: Combined for approximately 0.5 percent.
**: Includes pollution control reagent.

During the year ended December 31, 2001, the average delivered cost per ton of fuel for our base load plants was $10.37 at Coyote, $17.96 at Big Stone and $12.08 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. See "Risk Factors—Changes in commodity prices may increase our cost of producing and distributing electricity and distributing natural gas or decrease the amount we receive from selling electricity and natural gas, adversely affecting our financial performance and condition" included in Item 7 hereof.

Our base load coal plants have contracts for the delivery of lignite and sub-bituminous coal covering various periods. The Big Stone facility currently burns Wyoming sub-bituminous coal from the Powder River Basin supplied under a contract that expires at the end of 2002. Big Stone also has optional fixed price renewable contracts for 2003 and 2004. The Coyote facility has a contract for the delivery of lignite coal which 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 2001, approximately 3.8% of the fuel consumption at Big Stone was derived from alternative fuels.

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

We must pay fees to third parties to transmit the power generated at our Big Stone and Neal plants to our South Dakota transmission system. In 2001, we entered into a new 10-year agreement with the Western Area Power Administration for transmission services, including transmission of electricity from Big Stone and Neal to our South Dakota service areas through seven points of interconnection on the Western Area Power Administration's system. Transmission services under this agreement, and our costs for such services, are variable and depend upon a number of factors, including the respective parties' system peak demand and the amount of our transmission assets that are integrated into the Western Area Power Authority's system. In 2001, our costs for services under this contract were approximately $3.24 million. Our tariffs in South Dakota generally allow us to pass costs with respect to power purchased from other suppliers to our customers.

Additional Regulation

Our operations and the operations of our subsidiary entities 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. We believe that we are in substantial compliance with applicable regulatory requirements relating to our operations. See "Risk Factors—We are subject to extensive governmental regulations which could impose significant costs on our operations and changes in existing regulations and future deregulation may have a detrimental effect on our business and could increase competition " included in Item 7 hereof.

Federal

We are a "public utility" within the meaning of the Federal Power Act. Accordingly, we are subject to the jurisdiction of, and regulation by, the FERC, with respect to the issuance of securities and the setting of wholesale electric rates. We are an exempt "holding company" under the Public Utility Holding Company Act.

In April 1996, the FERC issued Order No. 888 and Order No. 889 requiring utilities to allow open use of their transmission systems by other utilities and power marketers. We, The Montana Power Company 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 succeeded to The Montana Power Company's OATTs.

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

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 its transmission operations/reliability functions from its marketing/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 sponsor of a filing at the FERC which proposed to form an RTO, RTO West. RTO West will be a nonprofit organization with an independent board that will act as the independent system operator for the aggregated transmission systems of participating transmission owners. If RTO West is implemented and NorthWestern Energy LLC participates, NorthWestern Energy LLC will execute a transmission operating agreement with RTO West prior to startup of the RTO West operation, which is currently contemplated to occur in early 2006. We do not anticipate that the transmission operating agreement would include any of our transmission assets other than those used in Northwestern Energy LLC's Montana operations. RTO West may not own transmission assets pursuant to its charter, so the transmission operating agreement will not convey ownership of the assets to RTO West but will grant RTO West the right to operate the assets consistent with the obligation to provide services pursuant to applicable tariffs. A draft of the proposed transmission operating agreement can be found at the websitehttp://www.rtowest.org. The information contained on thehttp://www.rtowest.org website is not incorporated by reference in this Annual Report on Form 10-K and should not be considered a part of this Annual Report on Form 10-K.

NorthWestern Energy LLC, and other participating transmission owners, will likely retain the right and obligation to maintain the facilities that RTO West has authority to operate pursuant to the transmission operating agreements. NorthWestern Energy LLC may elect to transfer certain of its employees to RTO West, although there is no requirement or agreement with RTO West for NorthWestern Energy LLC to provide any of its employees, and NorthWestern Energy LLC does not expect any loss of employees to RTO West to have a material effect on its operations. Participation in RTO West will create a new commercial arrangement for the transmission of the energy we distribute in Montana, but NorthWestern Energy LLC does not anticipate any material change in the transmission related revenue stream as a result of participation in RTO West. Following

commencement of operations of RTO West, if NorthWestern Energy LLC participates in RTO West, all transmission services for NorthWestern Energy LLC's Montana operations will be provided by RTO West, albeit at least partially through transmission assets that NorthWestern Energy LLC owns. This means that NorthWestern Energy LLC will have to schedule transmission services through RTO West, rely on RTO West to provide such services and will generally receive no preference over any other member of RTO West with respect to the use of the transmission assets, including the assets NorthWestern Energy LLC currently owns. Members of RTO West will not collect transmission revenues from end-user customers, instead, RTO West will employ a paying agent that will collect transmission revenues in accordance with applicable tariffs. The paying agent will then distribute transmission revenues to RTO West and its members consistent with the terms of the transmission operating agreements as approved by FERC.

The Montana Power Company was also a sponsor of a second proposal filed in conjunction with its first filing at the FERC to establish an independent transmission company, TransConnect, LLC, which will be organized as a for-profit limited liability company. Those participating in TransConnect will exchange their transmission assets for a passive ownership interest in the company. TransConnect applicants have indicated that they intend to participate in RTO West as a single transmission owner by transferring control over their transmission assets to RTO West. In January 2002, The Montana Power Company determined that continued participation in TransConnect was not in its interest and withdrew from TransConnect. Neither we nor NorthWestern Energy LLC currently contemplate any further relationship with TransConnect.

In response to FERC Order No. 2000, 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.

The Montana Power Company provided wholesale power to two electric cooperatives, but the two cooperatives have chosen to obtain their power supply from another source, and NorthWestern Energy LLC will provide only transmission services to the cooperatives. In order to recover the transition costs associated with power that would have been supplied to these two cooperatives, the former owner of NorthWestern Energy LLC made a filing with the FERC in April 2000, seeking recovery of approximately $23.8 million in transition costs associated with serving both of the wholesale electric cooperatives. The FERC scheduled a hearing for the filing but suspended it after The Montana Power Company and the cooperatives jointly requested it be suspended so that the parties could attempt to settle the issues. The FERC recently terminated the settlement procedures and is expected to set a procedural schedule in the matter.

NorthWestern Energy LLC operates the Milltown Dam, a hydroelectric dam on the Clark Fork River, 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 2006, and NorthWestern Energy LLC is currently seeking to extend that license until 2008. Generally, under FERC rules, notice of intent to renew a license must be filed five years prior to its expiration. Thus, The Montana Power Company gave the FERC its notice to seek renewal of the license in 2001. In the event the FERC license were terminated, the FERC may require that the dam be removed. Several environmental and governmental groups, including the Department of the Interior, have voiced concerns over the license extension and may challenge the action in court. Were NorthWestern Energy LLC not to receive the license extension, it might be required to relinquish the license and cease operating the dam as early as 2006.

Montana

NorthWestern Energy LLC is 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.

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

On January 31, 2002, the MPSC approved a stipulation among The Montana Power Company, us and a number of other parties, which, among other things, conclusively established the pre-tax net present value of the retail transition costs relating to out-of-market power purchase contracts recoverable in retail rates to be approximately $244.7 million. 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 in the fourth year and thereafter. 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. The pre-tax net present value of the retail transition costs approved in the MPSC stipulation is approximately $60.0 million less than the former owner of NorthWestern Energy LLC estimated in its initial filing with the MPSC. We estimate that the annual after tax differences will be approximately $1.9 million in 2002, increasing to a high of approximately $13.2 million in the year 2017. The estimated aggregate after tax amount of the differences over the 28-year life of these contracts would be approximately $193.5 million. Although we believe we have opportunities to mitigate the impact of these differences through improved management of our obligations under these contracts, negotiating buyouts of certain of these contracts, selling non utility assets that are not part of our core strategy, reducing debt and other actions, we cannot assure you that our actions will be successful.

The stipulation also required The Montana Power Company and us to contribute $30.0 million to an account, which will fund credits to Montana electric distribution customers. The account will be applied on a per kilowatt hour basis beginning on July 1, 2002 and continuing for one year thereafter. Our allocable portion of the fund is $10.0 million. The Montana Power Company has already contributed the other $20.0 million allocable to it. See "Risk Factors—We may not be able to fully recover transition costs, which could adversely affect our net income and financial condition" and "Risk Factors—If the MPSC disallows the recovery of the costs incurred in entering into default supply portfolio contracts while we are required to act as the "default supplier," we may be required to seek alternative sources of supply and may not be able to fully recover the costs incurred in procuring default supply contracts, which could adversely affect our net income and financial condition" included in Item 7 hereof.

South Dakota

We are subject to the South Dakota Public Utilities Commission with respect to electric service territorial issues, rates, terms and conditions of service, accounting records and other aspects of our operations. Under the South Dakota Public Utilities Act, a requested rate increase may be implemented 30 days after the date of its filing unless its effectiveness is suspended by the South

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

Our retail electric rates, approved by the South Dakota Public Utilities Commission, provide several options for residential, commercial and industrial customers, including dual-fuel, interruptible, special all-electric heating, and other special rates, as well as various incentive riders to encourage business development. An adjustment clause provides for quarterly adjustment based on differences in the delivered cost of energy, delivered cost of fuel, ad valorem taxes paid and commission-approved fuel incentives.

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

NATURAL GAS OPERATIONS

Services, Service Areas and Customers

Our regulated natural gas utility operations purchase, transport, distribute and store natural gas for over 236,800 commercial and residential customers in Montana, South Dakota and Nebraska as of December 31, 2001, after giving effect to the acquisition of Montana Power LLC. 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

NorthWestern Energy LLC distributed natural gas to over 158,000 retail customers located in 109 Montana communities as of December 31, 2001. The MPSC does not assign service territories in Montana. However, NorthWestern Energy LLC has nonexclusive municipal franchises to purchase, transport, distribute and store natural gas in the Montana communities it serves. The terms of the franchises vary by community, but most are for 30 to 50 years. During the next five years, one of NorthWestern Energy LLC's Montana municipal franchises, which accounts for approximately 4,000 customers, is scheduled to expire. NorthWestern Energy LLC also serves several smaller distribution companies that provided service to approximately 28,000 customers as of December 31, 2001. NorthWestern Energy LLC's natural gas distribution system consisted of approximately 3,300 miles of underground distribution pipelines as of December 31, 2001.

NorthWestern Energy LLC also transmits natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. NorthWestern Energy LLC transported natural gas volumes of approximately 50 billion cubic feet in the year ended December 31, 2001. NorthWestern Energy LLC's peak capacity was approximately 300 million cubic feet per day during the year ended December 31, 2001. NorthWestern Energy LLC's natural gas transmission system consisted of over 2,000 miles of pipeline, which vary in diameter from 2 inches to 20 inches, and served over 130 city gate stations as of December 31, 2001. NorthWestern Energy LLC has strategic connections with four major, non-affiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas and Havre Pipeline. Seven compressor sites provided over 23,000 horsepower, capable of moving approximately 300 million cubic feet per day during the year ended December 31, 2001. In addition, NorthWestern Energy LLC owns and operates a

pipeline border crossing through its wholly owned subsidiary, Canadian-Montana Pipe Line Corporation.

South Dakota and Nebraska

We provided natural gas to approximately 81,000 customers in 59 South Dakota communities and four Nebraska communities as of December 31, 2001. The state regulatory agencies in South Dakota and Nebraska do not assign service territories. However, 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 46,000 customers, are scheduled to expire. We have never been denied the renewal of any of these franchises. We have approximately 1,996 miles of distribution gas mains in South Dakota and Nebraska with distribution capacity of approximately 15,000 MMBTU per day as of December 31, 2001. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska.

Competition and Demand

Montana's Natural Gas Utility Restructuring and Customer Choice Act, which was passed in 1997, provides that a natural gas utility may voluntarily offer its customers their choice of natural gas suppliers and provide open access in Montana. Although NorthWestern Energy LLC has opened access to its gas transmission and distribution systems and gas supply choice is available to all of its natural gas customers in Montana, NorthWestern Energy LLC currently does not face material competition in the transmission and distribution of natural gas in its Montana service areas. NorthWestern Energy LLC also provides default supply service to customers in its Montana service territories who have not chosen other suppliers under cost-based rates.

In South Dakota and Nebraska, we are subject to competition for natural gas supply. In addition, competition currently exists for commodity sales to large volume customers and for delivery in the form of system by-pass, alternative fuel sources such as propane and fuel oil, and, in some cases, duplicate providers. We do not face material competition from alternative natural gas supply companies in the communities in which we serve in South Dakota and Nebraska. We are currently the largest provider of natural gas in our South Dakota and Nebraska service territory service territories based on MMBTU sold. In South Dakota, we also transport natural gas for one gas marketing firm currently serving four customers through our distribution systems. In Nebraska, we transport natural gas for one customer, whose supply is contracted from another gas company. We delivered approximately 4.7 million MMTBU of third-party transportation volume on our South Dakota distribution system and approximately 0.9 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

Montana

Our natural gas supply requirements in Montana are fulfilled through third-party purchase contracts for natural gas delivered within Montana. In Montana our natural gas supply requirements for the year ended December 31, 2001, were approximately 19.5 million MMBTU, of which approximately 18.4 million MMBTU were purchased under third-party contracts with Montana suppliers, and approximately 1.1 million MMBTU were purchased under contracts with Canadian suppliers. During the year ended December 31, 2001, approximately 58% of our Montana natural gas supply requirements were covered under long-term contracts, approximately 18% were covered under one-year contracts, and the balance were covered under short-term contracts. During the year ended December 31, 2001, approximately 59% of our Montana contractual natural gas requirements were priced at current market levels and the remainder were fixed-price contracts at December 31, 2001. We believe our supply, storage and distribution facilities and agreements are sufficient to meet its needs in 2002.

NorthWestern Energy LLC owns and operates three working natural gas storage fields in Montana with aggregate storage capacity of approximately 17.2 billion cubic feet and maximum aggregate working gas capacity of approximately 178 million cubic feet per day. NorthWestern Energy LLC owns a fourth field that is being depleted at approximately 0.03 million cubic feet per day with approximately 85 million cubic feet of remaining reserves.

South Dakota and Nebraska

Our South Dakota natural gas supply requirements are fulfilled through third-party purchase contracts for natural gas delivered within South Dakota. Our South Dakota natural gas supply requirements for the year ended December 31, 2001, were approximately 5.5 million MMBTU, of which approximately 2.4 million MMBTU were purchased from Canadian sources, and approximately 3.1 million MMBTU were purchased from mid-continent sources. During the year ended December 31, 2001, approximately 39% of our South Dakota natural gas supply requirements were covered under long-term contracts, and the balance was covered under short-term contracts. All of our South Dakota contractual natural gas requirements were priced at current market levels.

Our Nebraska natural gas supply requirements are fulfilled through third-party purchase contracts for natural gas delivered within Nebraska. Our Nebraska natural gas supply requirements for the year ended December 31, 2001, were approximately 5.6 million MMBTU, of which approximately 0.6 million MMBTU were purchased from Rocky Mountain sources, and approximately 5 million MMBTU were purchased from mid-continent sources. During the year ended December 31, 2001, all of our Nebraska natural gas supply requirements were covered under long-term contracts.

We had financial swaps in place for approximately 60% of the estimated retail volume for the 2001/2002 heating season in South Dakota and Nebraska.

We also have pipeline capacity service agreements with Coast Energy Group, a division of CornerStone, for our South Dakota operations and ONEOK Gas Marketing for our Nebraska operations. The Coast Energy Group agreement terminates in July 2002, and the ONEOK agreement terminates in October 2003. To supplement firm gas supplies in South Dakota and Nebraska, our service agreements with Coast Energy Group and ONEOK also provide for underground natural gas storage services to meet the heating season and peak day requirements of our natural gas customers. We also have five propane-air gas peaking units with a daily capacity of approximately 1,800 MMBTU

per day. 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 South Dakota and Nebraska natural gas supply, storage and distribution facilities and agreements are sufficient to meet our needs in 2002.

Additional Regulation

Federal

A 1992 order of the 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 NorthWestern Energy LLC, 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. See "Risk Factors—We are subject to extensive governmental regulations which could impose significant costs on our operations and changes in existing regulations and future deregulation may have a detrimental effect on our business and could increase competition" included in Item 7 hereof.

Our natural gas transportation pipelines are generally not subject to the jurisdiction of the FERC, although we are subject to state regulation. NorthWestern Energy LLC conducts limited interstate transportation subject to the FERC jurisdiction, but the FERC has allowed the MPSC to set the rates for this interstate service.

Montana

As a public utility, NorthWestern Energy LLC is subject to MPSC jurisdiction when it issues, assumes or guarantees securities, or when it creates liens on its properties. Rates for NorthWestern Energy LLC's natural gas supply are set by the MPSC. The Montana Power Company used a system of annual cost tracking for approximately 20 years and consistently obtained rate increases that reflected cost increases. NorthWestern Energy LLC uses an annual gas tracking mechanism for the recovery of gas supply costs. NorthWestern Energy LLC prepares and files an annual natural gas cost tracking filing with the MPSC. The filing sets gas cost rates based on estimated gas loads and gas costs for the upcoming tracking period and adjusts for any differences in the previous tracking year's estimates to actual information. The MPSC has utilized this process since 1979.

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

In January 2001, The Montana Power Company submitted to the MPSC an annual gas cost tracker requesting an increase of approximately $51.0 million. At that time, the former owner also submitted a compliance filing for a credit of approximately $32.5 million associated with a sharing of the proceeds from the sale of gathering and production properties previously included in the natural gas utility's rate

base. As a result, effective February 1, 2001, The Montana Power Company began collecting a net amount of $18.5 million in revenues over a one-year period. In September 2001, after all testimony addressing the amount of sharing had been filed with the MPSC, The Montana Power Company 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, will be credited to customers' bills over a one to two-year period beginning February 1, 2002. The amount of this customer credit was funded by The Montana Power Company through a purchase price adjustment at the closing of acquisition.

On December 7, 2001, NorthWestern Energy LLC filed its annual gas cost tracker request with the MPSC for the tracking year beginning November 1, 2001.

South Dakota and Nebraska

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

Our retail natural gas tariffs, approved by the South Dakota Public Utilities Commission and filed with the municipalities we serve in Nebraska, 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.

The State of Nebraska has no centralized regulatory agency exercising jurisdiction over natural gas operations in that state; however, natural gas rates are subject to regulation by the municipalities in which gas utilities operate. Legislation has been discussed in Nebraska to transfer jurisdiction over natural gas rates and terms and conditions of service to the Nebraska Public Service Commission, but at this time it is uncertain whether such regulatory change will be introduced or implemented. Our retail natural gas tariffs, filed with the cities served, provide residential, general service and commercial and industrial options, as well as firm and interruptible transportation service. A purchased gas adjustment clause provides for adjustments based on changes in gas supply and interstate pipeline transportation costs.

Employees

As of December 31, 2001, we had 367 team members employed in our energy division, NorthWestern Energy. System Council U-26 of the IBEW is the bargaining entity for 210 team members. As of December 31, 2001, NorthWestern Energy LLC had 1,344 team members employed in its regulated electric and gas utilities business, approximately 442 of whom are covered by collective bargaining agreements. We consider our relations with team members to be good.

UNREGULATED BUSINESSES

COMMUNICATIONS, NETWORK SERVICES AND DATA SOLUTIONS

EXPANETS

We hold shares of capital stock of Expanets through our subsidiary NorthWestern Growth Corporation. As of December 31, 2001 and June 30, 2002, our investment in Expanets consisted of $313.6 million and $363.6 million, respectively, of 12% coupon Preferred Stock and $0.5 million and $0.5 million, respectively, of Class B Common Stock. We controlled approximately 99.2% and 99.3% of the voting power of Expanets' issued and outstanding shares of capital stock as of December 31, 2001 and June 30, 2002, respectively. We also loaned $51.4 million to Expanets for general operating purposes during 2001, which, together with other intercompany balances of $11.7 million and $113.4 million, was outstanding at December 31, 2001 and June 30, 2002, respectively. The loan bears interest at 17% per annum and repayment is anticipated during 2002.

Our Class B Common Stock is convertible into shares of Class A Common Stock from time to time at our option and will be automatically converted into shares of Class A Common Stock upon an initial public offering or sale of Expanets. In addition, two of the series of our Preferred Stock of Expanets are convertible into shares of Class A Common Stock from time to time at our option at a conversion ratio based on the value of the Class A Common Stock on the date of conversion and are redeemable for 110% of its liquidation preference, plus accrued and unpaid dividends, at our option prior to an initial public offering or sale of Expanets and two other of the Series of our Preferred Stock of Expanets are mandatorily redeemable upon an initial public offering or sale of Expanets. The outstanding class of Common Stock of Expanets held by third parties will be automatically converted into shares of Class A Common Stock upon an initial public offering or sale of Expanets at a ratio of 1 to 1. One outstanding series of Preferred Stock of Expanets held by Avaya is automatically redeemable for 100% of its liquidation preference, plus accrued and unpaid dividends, upon an initial public offering or sale of Expanets. The other two outstanding series of Preferred Stock of Expanets held by third parties will be automatically converted into shares of Class A Common Stock upon an initial public offering or sale of Expanets at a conversion ratio based on the value of the Class A Common Stock in the initial public offering or sale.

Our holdings of Common and Preferred Stock of Expanets were convertible into approximately 50% of the Class A Common Stock of Expanets as of December 31, 2001 and as of June 30, 2002 on a fully diluted basis assuming the conversion of all other outstanding convertible securities of Expanets, other than employee options, based on the originally issued value of the Class A Common Stock of Expanets. We have issued a warrant for the purchase of up to 10% of our Expanets Class B Common Stock based on the market value of our Expanets Class B Common Stock. Our two series of mandatorily redeemable Preferred Stock of Expanets were redeemable for an aggregate of approximately $275.0 million and $330.0 million upon an initial public offering or sale of Expanets as of December 31, 2001 and as of June 30, 2002, respectively.

Products and Services

Expanets is a leading provider of networked communications and data services and solutions to medium-sized businesses. Expanets is a leading independent distributor for Avaya's wide range of products and software, including the PARTNER™ Advanced Communication System, the MERLIN MAGIX™ Integrated System, Guestworks Systems and DEFINITY™ solutions and messaging solutions. Expanets is also a leading reseller of NEC America, Inc., Cisco Systems, Inc., Siemens Enterprise Networks, LLC and IBM Corporation products. Expanets designs, procures, implements, maintains and monitors voice, video and data systems, which provide a wide range of communications tools for its customers. Expanets' service offerings include voice networking, data networking, internet connectivity,

messaging systems, advanced call processing applications, computer telephony, network management, carrier services and e-business services. NorthWestern Growth Corporation, one of our wholly owned subsidiaries, owns a majority of the voting common and preferred stock of Expanets.

Expanets' communications and data solutions help businesses integrate and deploy reliable and responsive communications and data networks customized to their needs in a cost-effective manner. Expanets' target and market customers are mid-market businesses with five to 1,000 desktops at a single business location that are increasingly focusing on their core competencies and relying upon third parties who can supply a single point of contact for access to specialized technical skills and rapid implementation of communications and data networking solutions. Expanets served approximately 560,000 business customers through the efforts of more than 3,200 team members located in more than 150 operational centers in all 50 states during the year ended December 31, 2001.

Operating Developments

During 2001, Expanets made significant changes in its executive and regional management structures consistent with the goal of streamlining its management and cost structure. Expanets continued to integrate its March 31, 2000, purchase of the United States segment of the GEM division of Lucent Technologies' Enterprise Network Group during 2001. This process involved the integration of Lucent's domestic small and mid-sized business customers and approximately 1,800 Lucent sales and sales support personnel into Expanets' existing communications and data networking services and solutions business structure. Through the GEM transaction, Avaya, Inc. obtained a substantial equity interest in Expanets, became its primary vendor for products, maintenance and technical support services sold to Expanets' customers, and supplied Expanets with billing and other support and a short-term line of credit, secured by Expanets' inventory and receivables. Avaya is the spin-off of Lucent that continues Lucent's enterprise network business. Expanets intends to sell future Avaya enterprise products developed and manufactured for the identified small and mid-sized business market, although Avaya is under no obligation to grant Expanets distribution rights to those products.

Effective March 31, 2001, Expanets and Avaya completed a substantial restructuring of the GEM transaction. Significant aspects of the restructuring included a reconciliation of various financial and performance aspects of the original transaction, modifications to the Master Dealership Agreement under which Expanets purchases products from Avaya, clarification of the ownership of accounts receivable and customers, modification of a $35.0 million note held by Avaya to extend the payment deadline to March 31, 2005 and the creation of a $125.0 million secured equipment purchase financing facility between Expanets and Avaya related to purchases of Avaya's products by Expanets, which was recently amended to extend the maturity to December 31, 2002, with required interim paydowns. As part of the recent amendment, we agreed to purchase up to $50.0 million in selected inventory and receivables from Avaya in the event of a default by Expanets. In addition, a $15.0 million convertible note held by Avaya was converted to Series D Preferred Stock of Expanets prior to the end of 2001. Expanets believes that the restructuring has better positioned its relationship with Avaya to the advantage of both parties.

Expanets' revenues were adversely impacted during the year from factory interruptions at Avaya, which supplied approximately 80% of its communications products and services during 2001. The factory interruptions at Avaya occurred during August to December 2001 and are estimated to have cost Expanets approximately $47.0 to 48.0 million in lost revenues due to the unavailability or delay in delivery of products and services. Avaya incurred the factory interruptions as a result of delays in implementing an outsourcing model for certain manufacturing processes. Expanets believes that Avaya has now resolved the relevant issues. No similar interruptions have occurred since the end of December 2001. In addition, Expanets had a $47.5 million EBITDA loss, before restructuring charges,

during the year ended December 31, 2001, on revenues of approximately $1.0 billion as a result of overall weakness in the industry.

EBITDA represents earnings from continuing operations before interest income, interest expense, income taxes, depreciation, amortization and other income and minority interests in income of subsidiaries. We believe that EBITDA provides meaningful additional information concerning a company's operating results and its ability to service its debt and other fixed obligations and to fund its continued growth. Many financial analysts consider EBITDA to be a meaningful indicator of an entity's ability to meet its future financial obligations. You should not construe EBITDA as an alternative to operating income (loss) as determined in accordance with GAAP, as an alternative to cash flows from operating activities as determined in accordance with GAAP or as a measure of liquidity. Because EBITDA is not calculated in the same manner by all companies, it may not be comparable to other similarly titled measures of other companies.

Shipments of PBX systems, traditionally the core voice technology used by Expanets' customers, were approximately 12% less than in 2000, and more than 20% less than the record year of 1999, according to a recent TEQ Consult Group White Paper. Expanets responded to these developments with personnel reductions that resulted in the elimination of approximately 1,200 positions, or 27% of Expanets' work force by December 31, 2001.

Throughout 2001, and as part of our overall corporate initiative, Expanets developed and implemented an "Operational Excellence" plan which is intended to combine "best practices" with scale efficiencies and cost reductions. As part of this plan, during 2001, Expanets developed and began implementation of the "Expert System," which, using a combination of Oracle and Siebel software, gives it a central and common platform from which all aspects of its business can be operated and managed, including order entry, scheduling, forecasting, customer billing, trend analysis, compensation and margin calculation, product support, sales support and financial reporting. The design, construction and implementation of the "Expert System" resulted in approximately $21.4 million in expenses and approximately $58.7 million in capital costs during 2001 and entailed significant manpower and energy. Delays in implementation of the "Expert System" and less than full functionality of the "Expert System" following its initial use in late November 2001 caused further negative effects on Expanets' 2001 fiscal year performance. While Expanets is addressing these issues, it expects that they will adversely affect its performance to some degree through the first two quarters of fiscal year 2002. Notwithstanding these challenges, Expanets believes that the "Expert System" will provide a strong platform to achieve its operating strategy.

From the beginning to the end of 2001, through a combination of sales force reductions, office consolidations, reductions in general and administrative expenses and the implementation of the "Expert System," Expanets lowered the amount of revenue needed from its communications operations to achieve positive EBITDA by approximately $40.0 million per month to approximately $75.0 million per month at the end of the year. Expanets anticipates further reductions in monthly expenses upon full implementation of the "Expert System."

Expanets believes that the adjustments to its cost structure and the additional service offerings described above will enable it to improve operations and execute its business plan in the current economic environment. However, there are a number of challenges Expanets must address during 2002. If Expanets is not able to resolve these issues effectively, its performance could be adversely affected. These challenges include:

•: Expanets will need to complete the implementation and full functionality of the "Expert System" in the upcoming year in order to realize the contemplated cost savings and productivity enhancements. Further delays in this process could have a negative effect on its operations and cash flow.

•: Expanets' $125.0 million equipment purchase financing facility with Avaya expires on December 31, 2002 and was reduced to $100.0 million on March 5, 2002, $80.0 million on April 30, 2002 and $55.0 million on August 30, 2002, and which had an outstanding balance of $39.6 million as of August 30, 2002. In current market conditions Expanets can provide no assurance that the facility will be extended or replaced on favorable terms, which could have a negative effect on its performance.
•: Expanets continues to see a soft market for the communications and IT product industry. Although Expanets has attempted to address the possibility of a prolonged recession in its "Operational Excellence" initiatives, a further weakening of the economy could adversely affect its performance.
•: Expanets has a number of new products, technologies and solutions that it is marketing to customers. Expanets can provide no assurance that the market will accept these products, which could adversely affect its performance.
•: Although Expanets believes that its relationship with Avaya as currently structured is positive for both companies and the Avaya products it sells are competitive in price and performance, a change in its relationship with Avaya or a change in Avaya's competitive position could adversely affect its performance.

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

Employees

Expanets had approximately 3,200 full-time team members as of December 31, 2001. Expanets considers relations with current team members to be good. Approximately 102 team members are covered by collective bargaining agreements.

HVAC, PLUMBING AND RELATED SERVICES

BLUE DOT

We hold shares of capital stock of Blue Dot through our subsidiary NorthWestern Growth Corporation. As of December 31, 2001 and June 30, 2002, our investment in Blue Dot consisted of $329.4 million and $367.3 million, respectively, of 11% coupon Preferred Stock and $0.5 million and $0.5 million, respectively, of Class B Common Stock. We controlled approximately 96.6% and 97.1% of the total voting power of Blue Dot's issued and outstanding capital stock as of December 31, 2001 and June 30, 2002, respectively. Blue Dot also had intercompany balances of $16.2 million and $22.8 million outstanding to us at December 31, 2001 and June 30, 2002, respectively.

Our Class B Common Stock is convertible into shares of Class A Common Stock from time to time at our option and will be automatically converted into shares of Class A Common Stock upon an initial public offering or sale of Blue Dot. Our series of Preferred Stock of Blue Dot is mandatorily redeemable for 105% of its liquidation preference, plus accrued and unpaid dividends, upon an initial public offering of Blue Dot. Blue Dot has entered into agreements with the other holders of the outstanding class of Common Stock of Blue Dot for the conversion of such Common Stock into Class A Common Stock upon an initial public offering at a conversion ratio based on the value of the Class A Common Stock in the initial public offering, which increases based on the achievement of

operating income targets. The other outstanding series of Preferred Stock of Blue Dot held by third parties will be automatically converted into shares of Class A Common Stock upon an initial public offering of Blue Dot at a conversion ratio based on the value of the Class A Common Stock in the initial public offering.

Our holdings of Common Stock of Blue Dot were convertible into approximately 33% and approximately 36% of the Class A Common Stock of Blue Dot as of December 31, 2001 and as of June 30, 2002, respectively, on a fully diluted basis assuming the conversion of all other outstanding convertible securities of Blue Dot, based on the originally issued value of the Class A Common Stock of Blue Dot. Our series of mandatorily redeemable Preferred Stock of Blue Dot was redeemable for an aggregate of approximately $346.0 million and $386.0 million upon an initial public offering of Blue Dot as of December 31, 2001 and as of June 30, 2002, respectively.

Products and Services

Blue Dot is a national provider of comprehensive repair, replacement and maintenance services and products for HVAC, plumbing and related systems in homes and light commercial businesses. Blue Dot has a nationwide network of air conditioning, heating and plumbing professionals who install and maintain indoor comfort systems. Blue Dot primarily operates in the residential and light commercial markets and serviced approximately 850,000 customers in 29 states during the year ended December 31, 2001. NorthWestern Growth Corporation owns a majority of the voting common and preferred stock of Blue Dot.

Blue Dot's primary service offerings can be grouped into the following two main categories:

•: Repair, Replacement and Maintenance. These services include preventive maintenance, such as periodic checkups, cleaning and filter change-outs, emergency repairs and the replacement of air conditioning, heating and plumbing systems in conjunction with the retrofitting or remodeling of a residence or commercial building, or as a result of an emergency repair request. Blue Dot focuses on the repair, replacement and management segment of the industry rather than the new construction segment because it believes that it offers higher margins, less cyclicality and seasonality and exposes Blue Dot to less credit and interest rate risk. Growth in this segment is driven by a number of factors, particularly the aging of the installed base; the increasing efficiency, sophistication and complexity of air conditioning and heating systems, which encourage upgrades; the upgrading of existing homes to central air conditioning; and the increasing restrictions on the use of refrigerants commonly used in older systems. Blue Dot also pursues maintenance agreements which it believes lead to better utilization of personnel, develop customer loyalty, provide the opportunity for cross-marketing of our other services and products, provide regular access to customers in the event major repairs or replacements are necessary and result in recurring revenues.
•: New Construction. Blue Dot's team members work with home builders to estimate the equipment, materials and parts and direct and supervise the labor required for new residential installations. Blue Dot's team members coordinate and supervise the installation in conjunction with the builder's construction supervisors. Blue Dot's team members coordinate the actual field work, including the ordering of equipment and materials, the fabrication or assembly of certain components, the delivery of materials and components to the job site and the scheduling of work crews with the necessary skills, inspection and quality control.

Operating Developments

Since its inception, Blue Dot has expanded its HVAC, plumbing and related services and geographic territory through an aggressive strategy of acquiring local and regional service providers. By

December 31, 2001, Blue Dot had acquired over 90 companies, including 14 companies in 2001 for a total combined purchase price of approximately $27.6 million. Blue Dot's acquisition targets are experienced companies with strong management teams, an established reputation and a strong residential and light commercial repair, replacement and maintenance mix.

As part of our overall corporate initiative, Blue Dot developed and implemented an "Operational Excellence" plan in its HVAC, plumbing and related services operations, which is intended to combine "best practices" with scale efficiencies and cost reductions. Blue Dot expects to achieve certain cost savings as a result of certain integrated or centralized functions provided to all platform companies. These functions include back office and management functions performed from a central office in Sioux Falls, South Dakota, common team member benefit plans and training, and a national Yellow Pages advertising initiative.

Blue Dot's operations are subject to seasonal variations in its different lines of service. Except in certain regions, the demand for new installations can be substantially lower during the winter months. Demand for HVAC services generally varies based on weather conditions with demand generally being higher during periods of extremely cold or hot weather and lower in the spring and fall months. Blue Dot expects its revenues and operating results to generally be lower in the first and fourth quarters of each year. Weather cycles, such as unseasonably mild winters or summers can also adversely impact revenues and operating results.

Blue Dot is subject to a number of regulations, including permitting and licensing requirements, municipal codes and zoning ordinances, laws and regulations relating to consumer protection, occupational health and safety and protection of the environment. Blue Dot believes that it has all requisite permits and licenses to conduct its operations and is in substantial compliance with applicable regulatory requirements.

Competition

The market for HVAC, plumbing and related services is highly competitive. The principal competitive factors in the residential and commercial repair, replacement and maintenance segment of the industry are timeliness, reliability and quality of services provided. Blue Dot's principal methods of meeting competition are assurance of customer satisfaction, a history of providing quality service and name recognition within its markets. In order to be successful as a national provider of comprehensive services, Blue Dot must employ, train and retain highly motivated, professional service technicians. Blue Dot believes that it does so through training programs, compensation, health and savings benefit plans and career opportunities.

Many of Blue Dot's competitors are small, owner-operated companies that operate in a single market and provide a limited range of services. Many of these smaller competitors have lower overhead cost structures and may be able to provide their services at lower rates. Moreover, many homeowners have traditionally relied on individual persons or small repair service firms with whom they have long-established relationships for a variety of home repairs. In addition, there are a limited number of companies focused on providing comprehensive residential and/or commercial services, on a regional or national basis, in some of the same business lines Blue Dot provides. Because of the high degree of market fragmentation and lower capability of smaller firms to raise the capital necessary to expand their businesses, a number of firms have been consolidating smaller businesses. There also are a number of national retail chains that sell a variety of plumbing fixtures and equipment and air conditioning and heating equipment for residential use and offer, either directly or through various subcontractors, installation, warranty and repair services.

Employees

Blue Dot had approximately 3,340 team members as of December 31, 2001. Blue Dot considers its relations with team members to be good. Approximately 77 of Blue Dot's team members are represented by labor unions, but no Blue Dot team members are covered by collective bargaining agreements.

DISCONTINUED PROPANE OPERATIONS

CORNERSTONE

We control approximately 30% of the equity interests of CornerStone, which we operate through one of our subsidiaries, CornerStone Propane GP Inc., that serves as managing general partner. CornerStone is one of the nation's largest publicly held retail propane distributors.

Recent Developments

On January 18, 2002, CornerStone announced that the board of directors of its managing general partner had determined that it is in the best interests of CornerStone's unitholders to consider strategic opportunities, including a possible sale or merger of CornerStone. We are the largest unitholder of CornerStone and own all of the stock of CornerStone's managing general partner. We fully support CornerStone's action as it is consistent with our strategic intent to focus our resources on our energy and communications platforms. A special committee of the board of directors of the managing general partner, composed of directors that are not officers of NorthWestern, has been formed to pursue strategic options. As a result, we have recharacterized our investment in CornerStone to reflect the results of operations of CornerStone as discontinued operations. Accordingly, the results of CornerStone's operations, for all periods reported, are presented separately below income from continuing operations. In conjunction with the adoption of discontinued operations accounting for CornerStone, substantially all of our approximately $40.0 million net carrying value in the partnership was recorded as a noncash charge during the first quarter of 2002 and an additional charge of $5.1 million was recorded during the second quarter of 2002.

On August 5, 2002, CornerStone announced that it had elected not to make an interest payment aggregating approximately $5.6 million on three classes of its senior secured notes, which was due on July 31, 2002, and was continuing to review financial restructuring and strategic options, including the potential commencement of a Chapter 11 case under the United States Bankruptcy Code. After this announcement, the New York Stock Exchange announced that it had suspended trading in CornerStone's publicly traded partnership units and would seek to delist the partnership units due to their low price and CornerStone's decision not to make the scheduled interest payments. We will continue to evaluate CornerStone's financial restructuring and the impact upon creditors of CornerStone, including us, and we expect to reflect any resulting financial implication in our third quarter 2002 results.

Among the arrangements between us and CornerStone which may be adversely affected by CornerStone's pursuit of financial restructuring and strategic opportunities are:

•: our 82.5% interest in SYN, Inc., a special non managing general partner in CornerStone, which is reflected in assets of discontinued operations and represents approximately $20.0 million of SYN's approximately $26.0 million in liquid assets. As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Requirements" included in Item 7 hereof, SYN has agreed to lend $9.0 million to CornerStone to address the partnership's liquidity needs on a short term basis;

•: intercompany receivables, net of reserves, owed to us by CornerStone of $6.0 million; and
•: our letters of credit of $6.5 million for insurance loss claims.

In addition, on August 20, 2002, NorthWestern purchased the lenders' interest in approximately $19.9 million of short-term debt, together with approximately $6.1 million in letters of credit, of CornerStone outstanding under CornerStone's credit facility, which NorthWestern had previously guaranteed. No further drawings may be made under this facility.

For additional information relating to CornerStone, see Exhibits 99.2, 99.3, 99.4 and 99.5 to this Annual Report on Form 10-K.

Business Overview

CornerStone is principally engaged in:

•: the retail distribution of propane for residential, commercial, industrial, agricultural and other retail uses;
•: the wholesale marketing and distribution to suppliers and other end users of propane, natural gas liquids and crude oil to the retail propane industry, the chemical and petrochemical industries and other commercial and agricultural markets;
•: the repair and maintenance of propane heating systems and appliances; and
•: the sale of propane-related supplies, appliances and other equipment.

As of December 31, 2001, CornerStone served approximately 470,000 residential, commercial, industrial and agricultural customers in more than 30 states. Its operations are concentrated in the East Coast, South Central and West Coast regions of the United States.

Based on fiscal 2001 retail propane gallons sold, the customer base consisted of 61% residential, 20% commercial and industrial and 19% agricultural and other customers. Sales to residential customers have generally provided higher gross margins than other retail propane sales. While commercial propane sales are generally less profitable than residential retail sales, CornerStone has traditionally relied on this customer base to provide a steady, non cyclical source of revenues. No single customer accounted for more than 1% of total revenues.

Through Coast Energy Group, CornerStone engages in the marketing and distribution of propane to independent dealers, major interstate marketers and the chemical and petrochemical industries in addition to procurement and distribution of propane for the retail segment. Coast Energy Group also participates in the marketing of other natural gas liquids, the processing and marketing of natural gas and the marketing of crude oil. In January 2002, CornerStone announced that it was in the process of narrowing the focus of the Coast Energy Group unit to focus exclusively on Natural Gas Liquids in support of the CornerStone retail propane operations, wholesale distribution and logistics operations. As assets are sold, CornerStone will likely take significant nonrecurring charges, mostly non-cash, related to the disposal of assets and exit of certain businesses.

For the fiscal year ended June 30, 2001, CornerStone had retail propane sales of approximately 275 million gallons. CornerStone's propane supply is purchased from oil companies and natural gas processors at numerous supply points located in the United States and Canada. During the year ended June 30, 2001, virtually all of its propane supply was purchased pursuant to agreements with terms of less than one year, but the percentage of contract purchases may vary from year to year. Supply contracts generally provide for pricing based on market prices at the time of delivery, subject to

maximum and minimum seasonal purchase guidelines. In addition, purchases on the spot market are made from time to time to take advantage of favorable pricing.

During the year ended June 30, 2001, Louis Dreyfus was CornerStone's largest supplier, providing approximately 11% of CornerStone's total propane supply for its retail operations (excluding propane obtained from CornerStone's natural gas processing operations). CornerStone believes that if supplies from Louis Dreyfus were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations. Historically, supplies of propane from CornerStone's sources historically have been readily available. Although no assurance can be given that supplies of propane will be readily available in the future, we expect a sufficient supply to continue to be available. CornerStone has not experienced a shortage that has prevented it from satisfying its customers' needs, and we do not foresee any significant shortage in the supply of propane.

Because a substantial amount of propane is sold for heating purposes, the severity of winter and resulting residential and commercial heating usage have an important impact on CornerStone's earnings. Approximately two-thirds of CornerStone's retail propane sales usually occur during the six-month heating season from October through March. Cash flows from operations are greatest from November through April as customers pay for propane purchased during the heating season.

Competition

In addition to competing with alternative energy sources, CornerStone competes with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large full-service, multi-state propane marketers, thousands of smaller local independent marketers and a number of farm cooperatives. Based on industry publications, the domestic retail market for propane is approximately 8.8 billion gallons annually, with the 10 largest retailers, including CornerStone, accounting for approximately 45% of the total retail sales of propane in the United States, and with no single marketer having a greater than 10% share of the total retail market. Most of CornerStone's customer service centers compete with five or more marketers or distributors. Each customer service center operates in its own competitive environment, because retail marketers tend to locate in close proximity to customers. CornerStone's customer service centers generally have an effective marketing radius of approximately 25 to 50 miles, although in certain rural areas the marketing radius may be extended by a satellite storage location.

Employees

As of December 31, 2001, CornerStone had approximately 2,000 full-time team members, and approximately 20 of its team members were represented by labor unions. CornerStone generally hires seasonal workers to meet peak winter demand. We believe that CornerStone's relations with its team members and labor unions are satisfactory.

ENVIRONMENTAL

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

Department of Health, the Iowa Department of Environmental Quality and the Montana Department of Environmental Quality, or the MDEQ, as well as compliance with court decisions. See "Risk Factors—Our utility business is subject to extensive environmental regulations and potential environmental liabilities, which could result in significant costs and liabilities" included in Item 7 hereof.

We did not incur any significant environmental expenditures in 2001 and do not expect to incur any significant environmental capital expenditures during 2002. However, we are committed to remaining in compliance with all state and federal environmental laws and regulations and must take reasonable precautions to prevent any incidents that would violate any of these rules. We regularly monitor operations to prevent adverse environmental impacts. When we become aware of an environmental issue, we investigate the situation to gain facts as to the nature and magnitude of environmental impact, the extent to which we may be held responsible for costs incurred, and the extent to which we may be held responsible for taking action at a site. We also collect information as necessary to reasonably estimate potential costs attributable to any environmental issue. We believe that we currently are in compliance with all presently applicable environmental protection requirements and regulations, however we are unable to forecast the effect of any change in law or regulation, or interpretation thereof, on the cost of future compliance for our utility-related facilities and other operations.

The Clean Air Act Amendments of 1990, which prescribe limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants, required reductions in sulfur dioxide emissions at our Big Stone plant beginning in the year 2000. We currently satisfy this requirement through the purchase of sub-bituminous coal, which contains lower sulfur content. The plant is replacing a precipitator with an advanced hybrid particulate collector, at an approximate cost of $13.4 million. Roughly half of this cost will be paid for by the Department of Energy, and our project share of the remainder is approximately $1.2 million, payable over a four-year period. In 2000, the wall-fired boiler at our Neal 4 plant and the cyclone boilers located at our Big Stone and Coyote plants became subject to nitrogen oxide emission limitations. To satisfy these limits, the Neal 4 and Big Stone facilities purchase and burn sub-bituminous coal from the Powder River Basin, and the Coyote facility purchases and burns lignite coal. Low nitrogen oxide burners have been identified as additional possible control technology; however, installation of such burners has not yet been required. The Clean Air Act also contains a requirement for future studies to determine what, if any, limitations and controls should be imposed on coal-fired boilers to control emissions of certain air toxics, including mercury. Because of the uncertain nature the air toxic emission limits and the potential for development of more stringent emission standards in general, we cannot reasonably determine the additional costs we may incur under the Clean Air Act.

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

Blue Dot's capital expenditures related to environmental matters during fiscal 2000 were not material. Certain Blue Dot operations are subject to Title VI of the Clean Air Act, which governs air emissions and imposes specific requirements on the use and handling of substances known or suspected to cause or contribute significantly to harmful effects on the stratospherical ozone layer, such as chlorofluorocarbons, or CFCs. Clean Air Act regulations require the certification of service technicians

involved in the service or repair of systems, equipment and appliances containing these refrigerants and also regulate the containment and recycling of these refrigerants. These requirements have increased Blue Dot's training expenses and expenditures for containment and recycling equipment, although such increase has not been material. The Clean Air Act is intended to ultimately eliminate the use of CFCs in the United States and to require alternative refrigerants be used in replacement HVAC systems. The implementation of Clean Air Act restrictions has increased and is expected to continue to increase the cost of using CFCs in the future. As a result, we expect to increase the number of conversions of existing HVAC systems that use CFCs to use alternative refrigerants. Blue Dot does not currently anticipate any material adverse effect on its business or consolidated financial position as a result of this or other future compliance matters under existing environmental laws and regulations that control the discharge of materials into the environment. Future events, however, such as changes in existing laws and regulations, or in the interpretation of such laws and regulations, to impose more vigorous enforcement policies or stricter or different interpretations of existing laws and regulations may require additional expenditures by Blue Dot which may be material.

Both NorthWestern and The Montana Power Company 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. However, we cannot quantify costs associated with current site remediation efforts or future remediation efforts because of the following uncertainties:

•: We may not know all sites for which we are alleged or will be found to be responsible for remediation; and
•: We cannot estimate with a reasonable degree of certainty the total costs of remediation at sites where we have been identified as responsible for remediation.

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

A formerly operated manufactured gas plant in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System, or CERLIS, list as contaminated with creosote and coal tar. We are currently investigating the site pursuant to a work plan approved by the EPA and the South Dakota Department of Environment and Natural Resources. At this time, we do not know whether any remediation is necessary at the site. If, however, remediation is required at the site, we cannot estimate with a reasonable degree of certainty at this time the total costs of clean-up at the site, but based upon our investigations to date, we do not expect cleanup costs to be material.

We also own a site in North Platte, Nebraska on which a former manufactured gas facility was located and which is under investigation for alleged soil and groundwater contamination. At present, we cannot estimate with a reasonable degree of certainty the total costs of remaining clean-up at the site, but we do not expect cleanup costs to be material.

The Montana Power Company was identified as a Potentially Responsible Party, or a PRP, at the Silver Bow Creek/Butte Area Superfund Site. However, the company settled most of its liability in a

Consent Decree approved by the United States District Court for the District of Montana and received contribution protection in the event other PRPs claim contribution for cleanup costs they expend. The Atlantic Richfield Company, or ARCO, continues to address contamination of the site. The Montana Power Company continued to operate on and transferred 30 acres of the property to NorthWestern Energy LLC. 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, and any costs incurred will be limited by the indemnity provision described below.

Toxic heavy metals in the silts resting in Milltown Reservoir, which sits behind Milltown Dam, caused the EPA to identify Milltown Reservoir on its Superfund National Priority List. ARCO, as successor to the Anaconda Company, has been named as the party with responsibility for completing the remedial investigation and feasibility studies and conducting site cleanup, under the EPA's direction. The Montana Power Company did not undertake any direct responsibility in that regard, in light of a special statutory exemption from liability under CERCLA in relation to the Milltown Dam. By virtue of its acquisition of The Montana Power Company's utility business and the dam, NorthWestern Energy LLC succeeded to similar protection under this statutory exemption. ARCO has argued that The Montana Power Company should be considered a PRP and has threatened to challenge its exempt status. ARCO and The Montana Power Company entered into a settlement agreement to limit The Montana Power Company's and now NorthWestern Energy LLC's potential liability, 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 final Record of Decision is not expected to be issued until late 2002 or early 2003. Depending on the outcome of that decision, we may be required to defend our exempt position. We have established a reserve of approximately $30.0 million and approximately $20.0 million at December 31, 2001 and June 30, 2002, respectively, primarily for liabilities related to the Milltown Dam and other environmental liabilities. See "Risk Factors—Our utility business is subject to extensive environmental regulations and potential environmental liabilities, which could result in significant costs and liabilities" included in Item 7 hereof.

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," however, because of the low probability of direct human contact and the lack of evidence of migration to groundwater supplies, and no action has been required. Given the low priority designation for this site, we believe that the risk of material remediation is low. As discussed below, The Montana Power Company retained pre-closing environmental liability relating to this CECRA listing when it sold the Thompson Falls Dam to PPL Montana. We cannot estimate with a reasonable degree of certainty the total costs, if any, of cleanup, and this liability at the site passed to NorthWestern Energy LLC, but we do not expect cleanup costs to be material. If any such costs are incurred, they will be limited by the indemnity provision described below.

The Montana Power Company has voluntarily cleaned up two sites where it formerly operated manufactured gas plants and currently is investigating a third. The Helena site was placed into the MDEQ's voluntary remediation program through which program cleanup is taking place. While the site continues to experience exceedances of groundwater contamination levels, NorthWestern Energy LLC believes that natural attenuation should address the problem. NorthWestern Energy LLC continues to periodically monitor the groundwater and report results to the MDEQ. The Montana Power Company has stated that it believes that remediation is complete at a second site located in Missoula, and it has requested closure from the State for that site. A third former manufactured gas plant formerly owned by The Montana Power Company, located in Butte, is currently under investigation. We cannot estimate with a reasonable degree of certainty whether cleanup will be necessary or the total costs of

such cleanup. However, we do not expect any of the outstanding cleanup costs to be material. If any such costs are incurred, they will be limited by the indemnity provision described below.

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 NorthWestern Energy LLC, we assume the first $50.0 million of NorthWestern Energy LLC's pre-closing environmental liabilities, including these retained environmental liabilities. Thereafter, Touch America Holdings, Inc. agreed to assume any such costs that fall between $50.0 and $75.0 million, or the next $25.0 million in costs. NorthWestern Energy LLC and Touch America Holdings, Inc. agreed to equally split costs that fall between $75.0 and $150.0 million.

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. However, we believe that we accrue an appropriate amount of costs and estimate reasonably foreseeable potential costs related to such environmental regulation and cleanup requirements. We do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

INTELLECTUAL PROPERTY

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

Part II

Item 6. Selected Financial Data

FIVE-YEAR FINANCIAL SUMMARY**

	2001			2000			1999			1998			1997
	(in thousands except per share and shareholders data)
Financial Results
Operating revenues	$	1,723,978		$	1,709,474		$	757,940		$	419,452		$	175,032
Gross margins		654,622			608,990			328,889			198,419			92,292
Operating expenses		751,492			604,681			285,358			154,184			56,900
Operating income (loss)		(96,870	)		4,309			43,531			44,235			35,392
Interest expense		(49,248	)		(37,982	)		(20,978	)		(15,546	)		(12,496	)
Investment income and other		8,023			8,981			9,800			5,700			11,564
Income (loss) before income taxes and minority interests		(138,095	)		(24,692	)		32,353			34,389			34,460
Benefit (provision) for income taxes		42,470			6,467			(13,145	)		(10,223	)		(9,828	)
Income before minority interests		(95,625	)		(18,225	)		19,208			24,166			24,632
Minority interests		141,448			67,821			24,788			5,315			—
Discontinued operations, net of taxes and minority interests		(1,291	)		(43	)		667			910			1,632
Net income	$	44,532		$	49,553		$	44,663		$	30,391		$	26,264
Common Stock Data
Basic earnings per share*+	$	1.54		$	1.85		$	1.64		$	1.45		$	1.31
Diluted earnings per share*+	$	1.53		$	1.83		$	1.62		$	1.44		$	1.31
Basic earnings per share from continuing operations	$	1.59		$	1.85		$	1.61		$	1.40		$	1.22
Diluted earnings per share from continuing operations	$	1.58		$	1.83		$	1.59		$	1.39		$	1.22
Average shares outstanding*:
Basic		24,390			23,141			23,094			18,660			17,843
Diluted		24,455			23,338			23,372			18,816			17,843
Dividends paid per common share*	$	1.210		$	1.130		$	1.050		$	.985		$	.933
Annual dividend rate at year end*	$	1.27		$	1.19		$	1.11		$	1.03		$	.97
Book value per share at year end*	$	16.25		$	13.79		$	13.01		$	12.26		$	9.34
Common stock price range*:
High	$	26.750		$	23.937		$	27.125		$	27.375		$	23.500
Low	$	18.250		$	19.125		$	20.625		$	20.250		$	16.938
Close	$	21.050		$	23.125		$	22.000		$	26.438		$	23.000
Price earnings ratio		13.8x			12.6x			13.6x			18.4x			17.6x
Dividend payout ratio
(from ongoing operations)+		76.6	%		61.7	%		66.0	%		70.9	%		76.5	%
Return on average common equity		10.5	%		13.8	%		13.0	%		12.1	%		14.2	%
Common shareholders at year end		10,358			10,371			10,475			10,116			8,845
Financial Position (as of December 31)
Total assets	$	2,634,735		$	2,898,070		$	1,956,761		$	1,728,474		$	1,106,123
Working capital		(296,580	)		40,314			100,193			57,739			11,844
Short-term debt, including nonrecourse		356,445			49,207			37,554			16,554			5,570
Long-term debt, including nonrecourse debt excluding current portion		411,349			583,708			340,978			259,373			161,000
Total debt (including subsidiaries)		767,794			632,915			378,532			275,927			166,570
Shareholders' equity		396,578			319,549			300,371			282,134			166,603
Preferred stock not subject to mandatory redemption		3,750			3,750			3,750			3,750			3,750
Preferred stock subject to mandatory redemption		187,500			87,500			87,500			87,500			32,500
Other equity		221,317			284,117			208,224			199,158			36,250
Total equity	$	617,895		$	603,631		$	508,595		$	481,292		$	202,853

*: Adjusted for the two-for-one stock split in May 1997.
+: $2.04 Basic earnings per share; $2.03 Diluted earnings per share; and 59.6% Dividend payout ratio, exclusive of 2001 restructuring charge.
**: Excludes CornerStone Propane Partners, L.P., which is treated as a discontinued operation.

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 information regarding NorthWestern Energy LLC's results of operations, see Management's Discussion and Analysis of Financial Condition and Results of Operations included in Item 7 to the Annual Report on Form 10-K of NorthWestern Energy LLC for the year ended December 31, 2001, which is contained in Exhibit 99.6 to this Annual Report on Form 10-K for the year ended December 31, 2001, the combined financial statements and notes thereto of NorthWestern Energy LLC included in the Annual Report on Form 10-K of NorthWestern Energy LLC for the year ended December 31, 2001, which is contained in Exhibit 99.6 to this Annual Report on Form 10-K for the year ended December 31, 2001, and "Montana Power LLC Unaudited Pro Forma Combined Condensed Financial Data" contained in Exhibit 99.7 to this Annual Report on Form 10-K for the year ended December 31, 2001.

The following discussion and analysis reflects the recharacterization of our investment in CornerStone to reflect the results of operations of CornerStone as discontinued operations for all periods presented.

Overview

We are a service and solutions company providing integrated energy, communications, heating, ventilation, air conditioning, plumbing and related services and solutions to residential and business customers throughout North America. We own and operate one of the largest regional electric and natural gas utilities in the upper Midwest of the United States. We distribute electricity in South Dakota and natural gas in South Dakota and Nebraska through our energy division, NorthWestern Energy, formerly NorthWestern Public Service, and electricity and natural gas in Montana through our wholly owned subsidiary, NorthWestern Energy LLC. We are operating under the common brand "NorthWestern Energy" in all our service territories. On February 15, 2002, we completed the acquisition of the electric and natural gas transmission and distribution businesses of The Montana Power Company for approximately $1.1 billion, including the assumption of approximately $488.0 million in existing debt and preferred stock, net of cash received. We intend to transfer the energy and natural gas transmission and distribution operations of NorthWestern Energy LLC to NorthWestern Corporation during 2002 and to operate its business as part of our NorthWestern Energy division. We believe the acquisition creates greater regional scale allowing us to more fully realize the value of our existing energy assets and provides a strong platform for future growth.

Our principal unregulated investment is in Expanets, a leading provider of networked communications and data services and solutions to medium sized businesses nationwide. In addition, we own investments in Blue Dot, a nationwide provider of air conditioning, heating, plumbing and related services, and CornerStone, a publicly traded limited partnership, in which we hold a 30% interest and operate through one of our subsidiaries that serves as managing general partner. CornerStone is a retail propane and wholesale energy related commodities distributor. On January 18, 2002, the board of directors of the general partner of CornerStone announced it has retained Credit Suisse First Boston Corporation to pursue the possible sale or merger of CornerStone. We fully support the board's action as it is consistent with our strategy to focus our resources on our energy and communications platforms. A special committee of the board of directors of the managing general partner, composed of directors that are not officers of NorthWestern, has been formed to pursue strategic options. As a result, we have recharacterized our investment in CornerStone to reflect the results of operations of CornerStone as discontinued operations. Accordingly, the results of CornerStone's operations, for all periods reported, are presented separately below income from continuing operations. In conjunction

with the adoption of discontinued operations accounting for CornerStone, substantially all of our approximately $40.0 million net carrying value in the partnership was recorded as a noncash charge during the first quarter of 2002 and an additional charge of $5.1 million was recorded during the second quarter of 2002.

Results of Operations

The following is a summary of our results of operations for each of the three years ended December 31, 2001, 2000 and 1999.

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000 and Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

Consolidated Operating Results

The following is a summary of our results of operations in 2001, 2000 and 1999. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment. Our "All Other" category primarily consists of our other miscellaneous service activities, which are not included in the other identified segments together with unallocated corporate costs. See "—Segment Information—All Other Operations" for a discussion of the items contained in our "All Other" category. Product and service category fluctuations highlighted at the consolidated level are more fully explained in the segment discussion.

Consolidated Earnings and Dividends. Consolidated earnings in 2001 were $37.5 million, a decline of $5.2 million, or 12.3%, from 2000 results. Diluted earnings per share, or EPS, in 2001 was $1.53, a decline of $.30, or 16.4%, from 2000 results. Consolidated earnings were reduced by a $24.9 million restructuring charge ($12.1 million net of taxes and minority interests) taken in the fourth quarter of 2001. The 2001 restructuring charge reduced diluted EPS by $.50 per share. Diluted EPS in 2001 was $2.03 exclusive of the restructuring charge, an increase of $.20, or 10.9%, from diluted EPS in 2000. The $24.9 million restructuring charge related principally to facility closure costs, employee termination benefits and related costs incurred in connection with our Operational Excellence project, which is a series of companywide initiatives targeting reductions in annualized selling, general and administrative expenses by $150.0 million. While Expanets had significant operating losses in 2001, substantially all those losses were allocated to Minority Interests in Expanets as a result of its capital and ownership structure. To the extent basis was available, a portion of Blue Dot's losses were also allocated to Minority Interests. For further information about Minority Interest accounting, see our discussion of Significant Accounting Policies that follows. Consolidated earnings in 2000 were $42.8 million, an increase of $4.9 million, or 12.9%, from 1999. Diluted EPS in 2000 was $1.83, an increase of $.21, or 13.0%, from 1999. The increase in consolidated earnings and diluted EPS resulted from growth in our

electric and natural gas utility earnings and increased preferred stock investment income from our investments in Expanets and Blue Dot.

An annual dividend increase of $.08 per share to $1.27 per share was approved during the November 2001 Board of Directors' meeting and was effective for the December 1, 2001, dividend payment. Dividends were also increased in November 2000 from $1.11 per share to $1.19 per share. The increase in the 2001 dividend was our eighteenth consecutive annual dividend increase. The Board will continue to evaluate dividend policies in light of our consolidated financial condition.

Consolidated Operations. Consolidated revenues in 2001 were $1,724.0 million, an increase of $14.5 million, or 0.8%, from 2000 results. The increase was primarily due to increased revenues in our electric and natural gas segments of $69.9 million and increased revenues at Blue Dot of $15.0 million. The increase was partially offset by a decline in revenues at Expanets of $72.0 million as a result of the downturn in the economy and the telecommunications industry in particular, primarily due to volume declines. Consolidated revenues in 2000 were $1,709.5 million, an increase of $951.5 million, or 125.5%, from 1999 results. Growth in 2000 revenues resulted from increases within all of our segments. Expanets generated additional revenues of $809.2 million, primarily as a result of the acquisition of a portion of the Lucent Technologies' Growing and Emerging Markets business, or the Lucent GEM business, effective April 1, 2000. Blue Dot's revenues increased $115.1 million, while revenues in our electric and natural gas segments increased $29.1 million.

Consolidated cost of sales in 2001 were $1,069.4 million, a decline of $31.1 million, or 2.8%, from 2000 results. Expanets experienced a $92.5 million reduction in consolidated cost of sales. The reductions in cost of sales at Expanets were partially offset by increased cost of sales of $54.0 million in our electric and natural gas segments and increased cost of sales at Blue Dot of $7.0 million. Consolidated cost of sales in 2000 were $1,100.5 million, an increase of $671.4 million, or 156.5%, from 1999 results. Cost of sales in 2000 at Expanets increased $571.7 million primarily as a result of the inclusion of the cost of sales related to the Lucent GEM business acquisition in April 2000. Cost of sales at Blue Dot also increased $78.8 million and cost of sales in our electric and natural gas segments increased $22.6 million.

Consolidated gross margin in 2001 was $654.6 million, an increase of $45.6 million, or 7.5%, from 2000 results. Gross margin in 2001 increased across all of our segments. Expanets' gross margin increased $20.5 million, primarily as a result of the full year impact of the Lucent GEM business operations in 2001, which were acquired in April 2000. Gross margin in our electric segment increased $14.2 million, primarily as a result of increased wholesale electric margins during the first half of 2001, and gross margin in our natural gas segment increased $1.8 million. Blue Dot's gross margin increased $8.0 million as a result of acquisitions in 2001. Consolidated gross margin in 2000 was $609.0 million, an increase of $280.1 million, or 85.2%, from 1999 results. Gross margin in 2000 increased across all of our segments. Expanets' gross margin increased $237.5 million principally as a result of the additional margins from the Lucent GEM business acquisition. Acquisitions by Blue Dot also resulted in an increase in gross margin of $36.3 million. In addition, gross margins in our electric and natural gas segments increased $6.5 million in 2000.

Consolidated gross margin as a percentage of revenues in 2001 was 38.0%, compared to 35.6% in 2000 and 43.4% in 1999. Consolidated gross margin as a percentage of revenues in 2001 improved as a result of the gross margin gains described above, together with our efforts to reduce costs and increase higher-margin recurring service and maintenance revenues in our communications operations. Gross margin as a percentage of revenues declined from 43.4% in 1999 to 35.6% in 2000 as a result of lower-margin sales within the Lucent GEM business and a decline in Blue Dot's margin from a shift in business mix within the segment.

Consolidated operating expenses in 2001 were $751.5 million, an increase of $146.8 million, or 24.3%, from 2000 results. Operating expenses increased in each of our segments in 2001 due in part to

a $24.9 million restructuring charge related to our Operational Excellence project. Expanets incurred increased expenses of $92.6 million, excluding its portion of the Operational Excellence restructuring charge of $5.9 million, related to additional Lucent GEM business operating costs together with additional non-capitalizable integration/transition costs. Blue Dot's operating expenses also increased $19.1 million, excluding its portion of the Operational Excellence restructuring charge of $7.2 million, due to continued acquisition activities and infrastructure growth. The Operational Excellence program resulted in $3.3 million of the $6.2 million increase in operating expenses of our electric utility and $1.2 million of the $1.9 million increase in operating expenses of our natural gas segment. All Other operating expenses increased $6.6 million excluding the $7.3 million restructuring charge due to personnel additions and professional services to support our expanding subsidiary operations. Consolidated operating expenses in 2000 were $604.7 million, an increase of $319.3 million, or 111.9%, from 1999 results. Our results in 2000 included an additional $275.1 million of Expanets' operating expenses related primarily to the acquisition of the Lucent GEM business, together with associated transition/integration costs and increased amortization expenses from the additional intangibles. Blue Dot's operating expenses in 2000 increased $37.8 million due to acquisitions and corporate support expansion. Operating expenses in our electric and natural gas segments increased $3.2 million and All Other operating expenses increased $3.2 million in 2000.

Consolidated operating losses from continuing operations in 2001 were $96.9 million, compared to consolidated operating income from continuing operations in 2000 of $4.3 million. The $101.2 million change in operating income was due to a $78.0 million increase in operating loss at Expanets, an $18.4 million decline in operating income at Blue Dot, and a $12.7 million increase in All Other operating loss. These losses were partially offset by an $8.0 million operating income increase within our electric segment. Consolidated operating income from continuing operations in 2000 was $4.3 million, a decline of $39.2 million, or 90.1%, from 1999 results. The decrease in operating income in 2000 was primarily attributable to a $37.6 million decline in income at Expanets. Operating income at Blue Dot declined $1.5 million and All Other operating loss increased $3.4 million, but were partially offset by a $3.0 million operating income gain at our electric segment and a $0.3 million increase at our natural gas segment. While our communications and HVAC operations had significantly greater operating losses in 2001, substantially all of the Expanets' losses and a portion of Blue Dot's losses were allocated to Minority Interests as a result of the capital and ownership structures.

Investment income and other in 2001 decreased slightly to $8.0 million from $9.0 million in 2000. Gains from stock sales during the fourth quarter of 2001 were partially offset by realized losses on the write-down of certain investments. Overall investment income was also negatively impacted by lower interest rates and overall stock portfolio performance during 2001. Investment income and other in 2000 was $9.0 million, compared to $9.8 million in 1999. The decrease in 2000 was attributable to the increase of certain non-operating expenses within the line item and a decline in the overall level of investments.

Consolidated interest expense in 2001 was $49.2 million, an increase of $11.3 million, or 29.7%, from 2000 results. The increase in interest expense was primarily attributable to financings by Expanets, where interest expense increased $13.3 million, and was offset partially by a decrease in interest expense at Blue Dot resulting from reduced credit facility borrowings. Interest expense in 2000 was $38.0 million, an increase of $17.0 million, or 81.1%, over interest expense in 1999. Each of our segments incurred additional interest expense in 2000. Increased borrowings at the parent level to fund ongoing investments in operations also contributed to the increase in interest expense.

Consolidated income tax benefit in 2001 was $42.5 million, an increase of $36.0 million over the income tax benefit in 2000. Over 50% of the increase resulted from the tax benefit at Expanets which was the result of a significant increase in operating losses in 2001. Lower taxable income at Blue Dot as a result of operating losses further increased the benefit, as did higher All Other operating expenses. The income tax benefits were partially reduced by increased tax expense at our electric and natural gas

segments. Consolidated tax benefit in 2000 was $6.5 million, compared to an income tax expense of $13.1 million in 1999. The shift in taxes resulted principally from a decrease in taxable income at Expanets where taxes were $15.5 million less. All Other operating and interest expenses increased the tax benefit as well. The tax benefit increases were partially offset by higher income tax expense at our electric and natural gas segments.

Minority interests represent the net income or loss, after preferred dividends related to our preferred stock investments in Expanets and Blue Dot, which are allocable to common shareholders other than us. Minority interests were $141.4 million, an increase of $73.6 million in 2001. All of the increase was due to Expanets, where losses increased substantially in 2001, which was partially offset by reduced allocations at Blue Dot from a reduction in available basis to absorb the losses. Minority interests in 2000 were $67.8 million, an increase of $43.0 million. Over 80% of the increase was due to Expanets, while allocations for Blue Dot increased $7.5 million. Due to adequate basis in 2000 and 1999, substantially all losses by Expanets and Blue Dot were allocated to minority interests. Based on the entities' capital structures at December 31, 2001, and unless additional minority interest were to be created as a result of new acquisitions, our share of losses at Expanets exceeding $11.1 million after December 31, 2001, and our share of any losses at Blue Dot after December 31, 2001, would be allocated to us. See "—Significant Accounting Policies—Minority Interest in Consolidated Subsidiaries" for a discussion of the allocation of income (loss) to minority interests and the changes in such allocations during the periods discussed.

Segment Information

Electric Utility Segment Operations. We operate a vertically integrated utility through our NorthWestern Energy division, formerly known as NorthWestern Public Service. We generated and distributed electricity to over 57,000 retail customers in 108 communities throughout South Dakota as of December 31, 2001. Our regulated assets in South Dakota included approximately 3,100 miles of overhead and underground electric transmission and distribution lines, 120 substations and interests in generation facilities comprising approximately 312 megawatts of capacity as of December 31, 2001. Our South Dakota business enjoys competitive low cost fuel with no nuclear exposure. Coal was used to generate approximately 95% of our electricity during the year ended December 31, 2001.

Revenues from our electric utility operations in 2001 were $107.0 million, an increase of $20.4 million, or 23.6%, from 2000 results. The increase in revenues was principally the result of increased wholesale market prices for electricity. Revenues from our wholesale sales of electricity in 2001 were $13.6 million greater than the $9.3 million of revenues generated from such sales in 2000. The increase in wholesale sales revenues was principally due to unusual market conditions during the first half of 2001, and was partially offset by lower sales volume. The volume of wholesale megawatt hours sold in 2001 decreased by 3.4%; however, the volume of retail megawatt hours sold in 2001 increased by 4.4%. Revenues from retail sales of electricity increased by 8.9% in 2001, from $77.3 million in 2000 to $84.2 million in 2001. The increase in retail sales revenue in 2001 was principally due to a growing customer base combined with higher fuel costs that are passed through to customers. Revenues from our electric utility operations in 2000 were $86.6 million, an increase of $2.6 million, or 3.1%, from 1999 results. The increase in revenues in 2000 was primarily attributable to increased wholesale market prices for electricity, which rose sharply during the latter portion of 2000 as a result of unusual changes in market conditions. Revenues from retail sales of electricity remained flat between 1999 and 2000.

Cost of sales for our electric utility operations in 2001 was $23.1 million, an increase of $6.3 million, or 37.4%, from 2000 results. The increase in cost of sales in 2001 was due principally to retail fuel cost adjustments and increased volumes. The cost of sales for our electric segment in 2000 was $16.8 million, a decline of $1.7 million, or 9.1%, from 1999 results. The decline in cost of sales in 2000 was primarily the result of fuel cost adjustments that were passed through to retail consumers, which offset a 2.2% increase in volume.

Gross margin in 2001 was $83.9 million, an increase of $14.2 million, or 20.3%, over the 2000 gross margin of $69.8 million. The increase in gross margin in 2001 resulted primarily from the unusual wholesale market conditions and the 4.4% increase in retail sales. Gross margin in 2000 was $69.8 million, an increase of $4.3 million, or 6.6%, from the 1999 gross margin. The increase in gross margin between 1999 and 2000 was primarily a result of revenue gains from wholesale sales of electricity, the market prices for which increased through the latter portion of 2000, and increased margins on retail sales of electricity as a result of fuel cost adjustments.

Gross margin as a percentage of revenues in 2001 was 78.5%, compared to 80.6% in 2000, a decrease primarily as a result of increased fuel costs in 2001. Gross margin as a percentage of revenues increased from 78.0% in 1999 to 80.6% in 2000 primarily as a result of the unusual increase in higher margin wholesale sales.

Operating expenses of our electric segment in 2001 were $44.3 million, an increase of $6.2 million, or 16.3%, from 2000 results. The increase in operating expenses in 2001 was primarily caused by an Operational Excellence restructuring charge of $3.3 million, together with small increases in allocated power plant maintenance costs associated with increased generation, higher team member benefits expenses, increased customer service costs and higher depreciation related to additional investments in power plants. Higher operating expenses in 2001 were partially offset by lower transmission and distribution expenses. Operating expenses in 2000 were $1.3 million greater than 1999 operating expenses. The increase in operating expenses between 1999 and 2000 was primarily a result of increased depreciation costs from capital investments, increased team member salary and benefits costs and allocated plant associated expenses.

Operating income in 2001 was $39.7 million, or $43.0 million before restructuring charges, representing an increase of $8.0 million, or 25.1%, over 2000. The increase in operating income was a result of increased higher margin wholesale sales revenue, but the increase was partially offset by higher operating expenses in 2001. Operating income in 2000 was $31.7 million, an increase of $3.0 million, or 10.3%, from 1999 results. The increase in operating income between 1999 and 2000 was a result of gross margin improvements in 2000, which were partially offset by the higher operating expenses.

Natural Gas Utility Segment Operations. Our natural gas utility segment consists of the regulated natural gas utility operations of NorthWestern Energy. We purchased, transported, distributed, sold and stored natural gas for approximately 81,000 customers in 59 South Dakota communities and four Nebraska communities as of December 31, 2001. We have approximately 1,996 miles of distribution gas mains in South Dakota and Nebraska with distribution capacity of approximately 15,000 MMBTU per day as of December 31, 2001. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska. All natural gas is delivered through service agreements. Our natural gas supply requirements in South Dakota and Nebraska for the year ended December 31, 2001, were approximately 5.5 million MMBTU and approximately 5.6 million MMBTU, respectively.

Revenues from natural gas sales in 2001 were $144.2 million, an increase of $49.5 million, or 52.2%, from 2000 results. The increase was largely attributable to higher market prices for natural gas and a slight increase in the volume of sales. Revenues from natural gas sales in 2000 were $26.5 million higher than 1999 revenues of $68.2 million, due primarily to commodity price increases, particularly in the latter portion of 2000, as compared to 1999 prices, and increased volume of sales.

Cost of sales in 2001 was $119.1 million, an increase of $47.7 million, or 66.8%, from 2000 results. The increase in cost of sales was a result of the increased market prices for natural gas in 2001 and, to a lesser extent, the slight increase in our volume of sales. Cost of sales in 2000 was $71.4 million, an increase of $24.3 million from 1999 results. The increase in cost of sales between 1999 and 2000 was attributable to an increase in the market prices of natural gas and increased volumes.

Gross margin in 2001 was $25.2 million, an increase of $1.8 million, or 7.7%, from 2000 results. However, gross margin as a percentage of revenues decreased to 17.4% in 2001 from 24.7% in 2000. The increase in gross margin in 2001 was due to increased sales volumes and higher market prices for natural gas in 2001. Because the higher market prices for natural gas were passed along to consumers, the increase in gas commodity prices did not affect gross margin, but did have a positive impact on revenues and, therefore, adversely affected the gross margin percentage. Gross margin in 2000 was $23.4 million, an increase of 10.4% over gross margin in 1999. The increase in gross margin between 1999 and 2000 was a result of increased sales volume in 2000 and the rate increase in the fourth quarter of 1999. As a percentage of revenues, gross margins decreased to 24.7% in 2000 from 31.0% in 1999 due to increased gas commodity prices.

Operating expenses in 2001 were $19.0 million, an increase of $1.9 million, or 11.0%, from 2000 results. The increase was due principally to a $1.2 million restructuring charge related to Operational Excellence and small increases in team member benefit costs, customer care costs, and service expenses. Operating expenses in 2000 were $1.9 million higher than in 1999. The increase in operating expenses was attributable to increased salary and team member benefit costs, higher depreciation from increased capital investments and service expenses.

Operating income in 2001 was $6.2 million, or $7.4 million before restructuring charges, compared to operating income in 2000 of $6.3 million. The increase in operating income in 2001 before restructuring charges reflected gross margin increases, but was partially offset by increased operating expenses. Operating income in 2000 increased $0.3 million, or 5.5%, compared to 1999 results. The increase in operating income between 1999 and 2000 reflects increases in our gross margins in 2000 that exceeded the increases in our 2000 operating expenses.

Communications Segment Operations. Our communications segment consists of our investment in Expanets, a leading provider of networked communications and data services and solutions to medium-sized businesses. Expanets is a leading independent distributor for Avaya, Inc.'s wide range of products and software and is a significant independent distributor for a number of other major enterprise software providers. Expanets' services include the design, procurement, implementation, maintenance and monitoring of voice networking, data networking, internet connectivity, messaging systems, advanced call processing applications, computer telephony, network management, carrier services and e-business services. Expanets' business is not capital intensive and competition in Expanets' industries is fragmented. In addition, Expanets' maintenance services, which include the maintenance and upgrades of systems, provide recurring revenues. Expanets served approximately 560,000 business customers through more than 150 operational centers in all 50 states during the year ended December 31, 2001.

Operating revenues at Expanets in 2001 were $1,032.0 million, a decline of $72.0 million, or 6.5%, from 2000 results. In May 2001, Expanets revised certain portions of its original Lucent GEM business acquisition agreements with Avaya. The revised agreements eliminated minimum sales referral obligations from Avaya and increased the volume of recurring revenue service maintenance contracts assigned to Expanets. The 2001 results include a full year's results from the Lucent GEM business, which was acquired in April 2000, but revenues generally declined as a result of the restructured Lucent GEM business acquisition agreements and a downturn in the economy and the telecommunications market in particular. Expanets has focused on services and products that generate recurring revenues such as maintenance and warranty contracts, but traditional equipment sales that provide the basis for the provision of such services have been slowed by consumer cutbacks due to the downturn in the economy. Operating revenues in 2000 were $1,104.0 million, an increase of $809.2 million, or 274.4%, from 1999 results. The growth in revenues in 2000 was attributable primarily to the Lucent GEM business acquisition effective April 2000 and increased revenues from operation of the Lucent GEM business in the remainder of 2000.

Cost of sales in 2001 was $648.0 million, a decline of $92.5 million, or 12.5%, from 2000 results. The decline in cost of sales was attributable to a shift in sales mix from equipment sales to higher-margin service sales and a decline in sales volumes. In addition, management has increased its focus on cost reduction measures and improving margins, particularly since the first quarter of 2001. Cost of sales in 2000 was $740.6 million, an increase of $571.7 million, or 338.5%, from 1999 results. The increase in cost of sales in 2000 was principally attributable to the acquisition and operations of the Lucent GEM business. The former Lucent GEM division historically focused on equipment sales, which often generated recurring service and maintenance contracts, but had relatively lower margins than the other historical business lines conducted by Expanets.

Gross margin in 2001 was $384.0 million, an increase of $20.5 million, or 5.6%, from 2000 results. As a percentage of revenues, gross margin increased from 32.9% in 2000 to 37.2% in 2001. Gross margin dollars increased, in spite of an overall decline in operating revenues, as the result of increased solutions and services sales. The gross margin percentage improvement was a result of the increased mix of higher margin recurring service revenues as compared to lower margin equipment sales. Gross margin in 2000 was $363.5 million, an increase of $237.5 million, or 188.5%, from 1999 results. The growth in gross margin in 2000 was a result of the addition in April 2000 of the Lucent GEM business. Gross margin percentages fell from 42.7% to 32.9% in 2000, as a result of lower-margin equipment sales on which the Lucent GEM division historically focused.

Operating expenses in 2001 were $486.5 million, an increase of $98.5 million, or 25.4%, from 2000 results. Selling, general and administrative expenses in 2001 were $437.4 million, an increase of $86.5 million, or 24.6%, from 2000 results. The increase in selling, general and administrative expenses in 2001 was primarily a result of the additional transition/integration and other operating expenses related to the Lucent GEM business acquisition. Transition/integration costs of approximately $36.0 million were incurred during 2001, a $12.0 million increase over similar costs in 2000. Much of the integration/transition costs are a result of transition service agreements, or TSAs, under which Lucent (transferred in September 2000 to Avaya, Inc.) agreed to provide critical supporting systems such as accounting, information technology and customer care until Expanets could complete the necessary infrastructure internally. Expanets has developed an enterprise software system, called the EXPERT system, which was implemented in November 2001 by most of Expanets' operating units. Implementation of the EXPERT system through December 31, 2001 has allowed Expanets to terminate all but three of the TSAs. Approximately $21.0 million of noncapitalizable integration costs were incurred in association with the EXPERT project. While additional costs have been incurred during 2002 to enhance the EXPERT system's operational capabilities, the system is now operational and savings are expected to continue throughout 2002 both from efficiencies and the reduction of noncapitalizable integration costs from the project. Expanets also recognized an Operational Excellence program restructuring charge in 2001 of $5.9 million. Expanets has reduced staff levels by nearly 20% since 2000. Management of Expanets continues to focus on implementing cost savings initiatives and operating efficiencies. Depreciation and amortization costs increased $12.0 million in 2001 due to additional capitalized costs and intangibles associated with the Lucent GEM business acquisition. Operating expenses in 2000 were $388.1 million, an increase of $275.1 million, or 243.5%, from 1999 results. Selling, general and administrative expenses in 2000 were $350.9 million, an increase of $248.4 million, or 242.3%, from 1999 results. The increase in selling, general and administrative expenses in 2000 was due to the addition in April 2000 of the Lucent GEM business operations. Transition/integration costs of approximately $24.0 million were incurred in 2000 in connection with the acquisition. Depreciation and amortization costs in 2000 increased $26.7 million from expenses of $10.5 million in 1999, primarily due to higher amortization expense associated with the intangibles resulting from the Lucent GEM business acquisition and increased capital expenditures.

Operating losses in 2001 were $102.6 million, compared to $24.6 million in operating losses in 2000. Losses in 2001 were attributable to the general downturn in the economy and in the

communications market in particular, together with the additional integration/transition and other operating expenses incurred as a result of the Lucent GEM business acquisition and increased depreciation and amortization charges. Expanets' management continues to focus on reducing operating expenses and improving gross margin and anticipates improvements in 2002. Losses at Expanets in 2001 and prior years have been allocated to minority interests; however, based upon Expanets' capital structure at December 31, 2001, our share of any subsequent losses in 2002 that exceed $11.1 million would be allocated to us. See "—Significant Accounting Policies—Minority Interest in Consolidated Subsidiaries." Expanets had operating income in 1999 of $13.0 million. The $37.6 million decline between 1999 and 2000 was primarily due to increased selling, general and administrative costs, amortization expense and integration/transition costs related to the Lucent GEM business acquisition.

HVAC Segment Operations. Our HVAC segment consists of our investment in Blue Dot, a nationwide network of heating, ventilation, air conditioning, duct cleaning and plumbing professionals who install and maintain indoor comfort systems. Blue Dot primarily operates in the residential and light commercial markets and serviced approximately 850,000 customers in 29 states during the year ended December 31, 2001.

Operating revenues in 2001 were $423.8 million, an increase of $15.0 million, or 3.7%, from 2000 results. Operations from acquisitions completed during 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in the fourth quarter of 2000 contributed approximately $25.0 million in revenues, however, revenues at three previously acquired locations declined $26.4 million during 2001. Internal growth within the remainder of the HVAC business generated the remaining revenue increase. Blue Dot has made divisional closings and management changes at the three underperforming locations and expects the performance of those locations to improve in 2002. Operating revenues in 2000 were $408.8 million, an increase of $115.1 million, or 39.2%, from 1999 results. The operations of 17 companies acquired in 2000 added approximately $57.0 million in revenues, and the inclusion of the operations for a full year in 2000 of locations acquired during 1999 contributed most of the remaining additional revenues. Revenues from locations acquired before 1999 remained relatively flat in 2000.

Cost of sales in 2001 was $268.0 million, an increase of $7.0 million, or 2.7%, from 2000 results. The acquisition and operations of additional locations in 2001 and the inclusion of the operations for the full year in 2001 of the locations acquired in the fourth quarter of 2000 increased costs by approximately $13.7 million. Costs from additional locations were offset, however, by $16.2 million in reduced cost of sales in connection with division closings and restructurings at three underperforming locations. The remaining increase in cost of sales was due to internal growth in other locations. Cost of sales in 2000 was $261.0 million, an increase of $78.8 million, or 43.2%, from 1999 costs of $182.2 million. The acquisition and operations of additional locations in 2000 resulted in approximately $32.0 million of additional costs, with the remaining additional costs resulting from the inclusion of the operations for a full year in 2000 of locations acquired in 1999 and limited internal growth from previously acquired locations.

Gross margin in 2001 was $155.8 million, an increase of $8.0 million, or 5.4%, from 2000 results. The acquisition and operations of locations in 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in late 2000 contributed approximately $11.3 million to gross margin in 2001, while certain underperforming locations lowered gross margin $10.2 million. The remainder of the increase in gross margin in 2001 was due to internal growth in the previously acquired locations. Gross margin in 2000 was $147.8 million, an increase of $36.3 million, or 32.6%, from 1999 results. The operation of locations acquired in 2000 contributed approximately $24.0 million in gross margin, while the remaining growth was due to inclusion of the operations for a full year of prior acquisitions.

Gross margin as a percentage of revenues increased from 36.2% in 2000 to 36.8% in 2001, due to higher margin acquisitions and greater margin focus within the previously acquired locations. Gross

margin as a percentage of revenues declined to 36.2% in 2000 from 38.0% in 1999 due to margin deterioration within certain previously acquired locations and shifts in the overall business mix of the company.

Operating expenses in 2001 were $169.6 million, an increase of $26.3 million, or 18.4%, from 2000 results. Selling, general and administrative expenses in 2001 were $153.2 million, an increase of $23.7 million, or 18.3%, from 2000 results. Approximately $8.2 million of the additional expenses were incurred in connection with acquisitions in 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in late 2000. Expenditures also increased $2.7 million in 2001 at the corporate level for salaries and benefits of additional team members to support field operations. The remaining increase in expenses was attributable to the growth of previously acquired locations. Blue Dot recorded a $7.2 million Operational Excellence restructuring charge in 2001, which related primarily to severance and related team member benefits. Depreciation and amortization expenses in 2001 increased 18.9% due to the continued acquisition activity and capital expenditures. Operating expenses in 2000 were $143.2 million, an increase of $37.8 million, or 35.9%, from 1999 results. Selling, general and administrative expenses in 2000 were $129.4 million, an increase of $32.7 million, or 33.8%, from 1999 results. The acquisitions and operation of locations in 2000 accounted for over 50% of the increased selling, general and administrative expenses, while the inclusion of the operations for a full year in 2000 of locations acquired in 1999 and the expansion of the corporate offices also increased expenses. Depreciation and amortization expense in 2000 increased $5.1 million to $13.8 million due to continued acquisitions throughout 2000 and 1999.

Operating loss in 2001 was $13.8 million, a decline of $18.4 million from 2000 results. Acquisitions in 2001 and the inclusion of the operations for the full year in 2001 of the acquisitions made in 2000 increased earnings by approximately $3.1 million, but the Operational Excellence restructuring charge of $7.2 million, decline in operating income within three underperforming locations, margin shortfalls and an overall increase in operating expenses resulted in the net decline and operating loss in 2001. Operating income in 2000 was $4.6 million, a decline of $1.5 million from 1999 results. The increased operating expenses and gross margin deterioration in previously acquired locations exceeded the additional operating income from locations acquired in 1999, resulting in a decline in operating income.

All Other Operations. All Other primarily consists of our other miscellaneous service activities which are not included in the other identified segments, together with the unallocated corporate costs and investments, and any reconciling or eliminating amounts. The miscellaneous service activities principally include non-utility businesses engaged in voice and data networks and systems, and a portfolio of services to residential and business customers, including product sales and maintenance contracts in areas such as home monitoring devices and appliances.

Revenues for the segment in 2001 were $16.9 million, an increase of $1.6 million, or 10.7%, from 2000 results. The growth in 2001 was attributable to a small acquisition closed in December 2000, which was partially offset by business restructurings and reductions within certain other service activities. Revenues in 2000 were $15.3 million, a decline of $1.9 million, or 10.8%, from 1999 results. The decline in revenues in 2000 was due to business restructuring and realignments within the operations to focus on more profitable activities.

Cost of sales in 2001 was $11.2 million, an increase of $0.4 million, or 4.0%, from 2000 results. The increase was a result of the aforementioned acquisition offset by decreased costs from reductions in other service activities. Cost of sales in 2000 were $10.8 million, a decline of $1.7 million, or 13.3%, from 1999 results, principally due to business restructuring.

Gross margin in 2001 was $5.7 million, an increase of $1.2 million from 2000 results. As a percentage of revenues, gross margin improved from 29.4% in 2000 to 33.7% in 2001. The increases resulted from a focus on more profitable operations. Gross margin in 2000 was $4.5 million, a decrease of $0.2 million from 1999 results. The decrease was due to reductions in operations to focus on more

profitable activities. Gross margin as a percentage of revenues improved from 27.4% in 1999 to 29.4% in 2000.

Operating expenses in 2001 were $32.1 million, an increase of $13.9 million, or 76.4%, from 2000 results. The increase was due principally to $7.3 million of restructuring charges related to Operational Excellence, increased salaries, benefits and relocation expenses related to additional personnel in the corporate offices, additional costs from the acquisition, increased professional services expenses, and an increase in certain other benefit plan expenses. Operating expenses in 2000 were $18.2 million, an increase of $3.2 million, or 21.0%, from 1999 results. As with the increases in 2001, personnel additions and related benefit and relocation expenses represented the majority of the increase, which were offset slightly by decreased operating expenses within certain restructured service activities.

Operating losses in 2001 were $26.4 million, compared to losses of $13.7 million in 2000. The $12.7 million increase in operating losses in 2001 was attributable to the restructuring charges together with growth in corporate operating expenses, which were partially offset by an increase in gross margin. Losses in 2000 were $13.7 million, an increase of $3.3 million from 1999 losses. The additional losses in 2000 were due to increased corporate expenses without offsetting gross margin gains.

Discontinued Propane Segment Operations. Revenues in 2001 were $2,513.8 million, a decline of $2,908.8 million, or 53.6%, from 2000 results. The decrease was almost entirely attributable to wholesale operations, which in 2001 had revenues of $2,139.9 million, a decline of $2,893.2 million from 2000 results. The sale of the Canadian crude oil activities effective December 2000 contributed $1,730.7 million to the decrease. Approximately 75% of the remaining decrease of $1,162.5 million was due to volume decreases with price decreases responsible for the remainder. CornerStone's retail revenues in 2001 declined $15.6 million due to lower volumes as a result of warmer winter weather (especially the November-December timeframe) and lower commodity prices passed on to customers. Revenues in 2000 were $5,422.6 million, an increase of $3,176.2 million, or 141.4%, from 1999 results. The increase was primarily due to wholesale operations, which in 2000 had revenues of $5,033.2 million, an increase of $3,090.7 million from 1999 results. Price increases contributed approximately $1,583.0 million to the increase with volume increases representing the majority of the remaining increase.

Gross margin for propane in 2001 was $202.4 million, a decline of $23.9 million, or 10.6%, from 2000 results. Reduced wholesale gross margins constituted the entire decrease, while retail propane gross margin was flat. CornerStone's gross margin for wholesale operations in 2001 was $24.1 million, a decline of $23.9 million from 2000 results. The decline in gross margin was primarily due to the sale of the Canadian crude operations and losses due to unprofitable natural gas trading operations that have been discontinued. Retail gross margins remained flat in 2001, principally due to warmer weather, offset by an increase in nonpropane margins and management of the margins in times of volatile propane prices. Gross margin for propane in 2000 was $226.3 million, an increase of $18.6 million, or 9.0%, from 1999 results. Wholesale gross margin in 2000 was $48.0 million, an increase of $11.2 million, or 30.4%, from 1999. This increase was due to expanded operations in U.S. and Canadian crude oil activity, which were partially offset by the discontinued unprofitable natural gas trading losses. Retail margins increased 4.4% in 2000 to $178.3 million due primarily to the contribution of non-propane margins.

Operating income in 2001 was $12.9 million, a decline of $23.6 million, or 64.7%, from 2000 results. Operating income was lower in 2001 as a result of losses from the sale of the Canadian crude oil activities and warmer winter weather, the effects of which were partially offset by operating expense savings. Operating income in 2000 was $36.5 million, an increase of $0.5 million from 1999 results. The gross margin gains from expanded wholesale operations were tempered by high commodity prices, lower retail margin growth and discontinued unprofitable natural gas trading losses.

Liquidity and Capital Resources

Cash Flows and Cash Position

Operating Activities

We generate cash to fund our operations through a combination of cash flows from current operations, the sale of our securities and our borrowing facilities. We realized net positive cash inflows from operations of $85.6 million in 2001, $34.7 million in 2000 and $70.2 million in 1999. The increase in cash flows in 2001 was due in part to a $63.5 million increase in accrued expenses, a $51.0 million increase in accounts payable, a $32.3 million decrease in net assets of discontinued operations and a $20.3 million decrease in accounts receivables which were partially offset by a $19.0 million increase in other current assets and a $16.0 million increase in inventories. In 2001, we used our cash from operations, together with $6.2 million in existing cash and cash equivalents and $91.3 million in cash provided from financing activities, to fund $183.1 million in investment activities, including our acquisitions and growth expenditures. In 2000, we used a portion of our cash from operations, together with $150.0 million in cash provided from financing activities, to fund $163.9 million in investment activities, including our acquisitions and growth expenditures. In 1999, we used a portion of our cash from operations, together with $67.7 million in cash provided from financing activities, to fund $129.2 million in investment activities, including our acquisitions and growth expenditures.

We expect to generate net positive cash flows from operations during 2002 and to fund our day to day operations through our operating cash flows and our current cash and cash equivalents. Operating cash flows are expected to increase in 2002 as a result of our Operational Excellence initiatives, reduced integration and transition expenses and incremental operating cash flows from NorthWestern Energy LLC's Montana operations.

Investing and Financing Activities

Cash flows used in investing activities of $183.1 million in 2001 increased $19.2 million over 2000 investing activities. The increase was principally a result of increased growth of property, plant and equipment capital expenditures. Cash flows used in investing activities of $163.9 million in 2000 increased $34.7 million over 1999 investing activities of $129.2 million. The increase was principally due to a decline in sales of noncurrent investments and assets. Cash flows provided by financing activities of $91.3 million in 2001 declined $58.7 million compared to $150.0 million of financing cash inflows in 2000. The decrease is attributable to a decline in net debt issuances and repayments and an increase in cash used to repurchase subsidiary minority interests, offset by proceeds from common stock issuances in 2001. Financing cash inflows of $150.0 million in 2000 were $82.3 million higher than cash flows provided by financing activities of $67.7 million in 1999. The increase was principally a result of the issuance of $149.6 million of floating rate debt in 2000, which was partially offset by increased cash used to repurchase subsidiary minority interests and a decrease in debt repayments.

Our cash, cash equivalents, investments and marketable securities totaled $100.1 million, $106.9 million and $90.3 million at December 31, 2001, 2000 and 1999, respectively. During 2001 and early 2002, we raised cash proceeds from the following offerings of our securities and new debt facilities.

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

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

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

On February 15, 2002, in connection with our recently completed acquisition of The Montana Power Company's energy distribution and transmission business, we assumed $488.0 million of debt and preferred stock net of cash received from The Montana Power Company and we drew down a $720.0 million term loan and $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 $488.0 million of assumed debt and preferred stock includes various series of mortgage bonds, pollution control bonds and notes that bear interest rates of between 5.90% to 8.95%. These include both secured and unsecured obligations with maturities that range from 2003 to 2026.

On March 13, 2002, we issued $250.0 million of our 7⁷/8% senior notes due March 15, 2007, and $470.0 million of our 8³/4% senior notes due March 15, 2012, which resulted in net proceeds to us of $714.1 million. We have applied these net proceeds together with available cash to fully repay and terminate the $720.0 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 $250.0 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. The effective interest rate on our $250.0 million five-year senior notes was 4.28% as of July 8, 2002, after giving effect to the hedge agreements. Based on the June 30, 2002 calculation of future settlement value, the hedges had a value in our favor of $11.1 million.

On July 31, 2002, we redeemed the $2.6 million of our 26,000 outstanding shares of 4¹/2% series preferred stock at $110.75 per share resulting in a cash outlay of $2.9 million. On August 15, 2002, we redeemed the $1.2 million of our 11,500 outstanding shares of 6¹/2% series redeemable preferred stock at $101.35 per share resulting in a cash outlay of $1.2 million.

See "—Capital Requirements" below for more information regarding our future funding requirements.

Material Borrowings

We and our subsidiaries had the following long term and short term debt, mandatorily redeemable preferred securities and other commitments outstanding as of December 31, 2001:

		Total		2002		2003		2004-2006
		(in thousands)
*Recourse Debt:*
Mortgage Bonds, 6.99%, 7.00% and 7.10%		$	120,000	$	5,000	$	—	$	60,000
Senior Unsecured Debt, 6.95%			105,000		—		—		—
Pollution Control Obligations, 5.85% and 5.90%			21,350		—		—		—
Floating Rate Notes, LIBOR + 0.75%⁽¹⁾			150,000		150,000		—		—
Bank Credit Facility, Variable-Market Rate			132,000		—		132,000		—
*Nonrecourse Debt:*
Montana Megawatts facility, LIBOR + 1.50%⁽¹⁾⁽²⁾			53,603		53,603		—		—
CornerStone facility⁽³⁾			41,200		41,200		—		—
Expanets facility⁽⁴⁾			125,000		125,000		—		—
Blue Dot Facility			12,950		12,950		—		—
Other debt, various			26,981		717		869		25,395
*Capital and Operating Leases:*
Capital leases			20,910		9,589		5,782		5,539
Future minimum operating lease payments			64,492		23,436		15,699		22,951
*Mandatorily Redeemable Preferred Securities of Subsidiary Trusts:*
8.125% mandatorily redeemable preferred securities of subsidiary trust			32,500		—		—		—
7.20% mandatorily redeemable preferred securities of subsidiary trust			55,000		—		—		—
8¹/4% mandatorily redeemable preferred securities of subsidiary trust			100,000		—		—		—

	Total	$	1,060,986	$	421,495	$	154,350	$	113,885

(1): LIBOR refers to the London Interbank Offered Rates.
(2): NorthWestern has unconditionally guaranteed up to $27.5 million of this facility. The maximum amount that may be borrowed under the facility is $55.0 million.
(3): NorthWestern has unconditionally guaranteed 100% of this facility. The maximum amount that may be borrowed under the facility is $50.0 million. On August 20, 2002, NorthWestern purchased the lenders' interest in approximately $19.9 million of short-term debt, together with approximately $6.1 million in letters of credit, of CornerStone outstanding under CornerStone's credit facility, which NorthWestern had previously guaranteed. No further drawings may be made under this facility.
(4): The maximum amount that may be outstanding under this facility was initially $125.0 million, and was reduced to $100.0 million on March 5, 2002, $80.0 million on April 30, 2002 and $55.0 million on August 30, 2002, and which had an outstanding balance of $39.6 million as of August 30, 2002. If Expanets defaults under this facility, we may be obligated to purchase up to $50.0 million of inventory and accounts from Avaya.

Since we have accounted for CornerStone as a discontinued operation, the above table does not include $410.0 million of 7.33%, 7.53%, 8.08%, 8.27% and 10.26% senior secured notes of CornerStone, and $21.2 million of notes payable and capital lease obligations of CornerStone, which are non recourse to us, all of which was outstanding at December 31, 2001. $41.8 million of

CornerStone's senior secured notes mature in 2003 and $152.2 million of CornerStone's senior secured notes mature in 2004 through 2006. On August 5, 2002, CornerStone announced that it had elected not to make an interest payment aggregating approximately $5.6 million on three classes of its senior secured notes, which was due on July 31, 2002, and was continuing to review financial restructuring and strategic options, including the potential commencement of a Chapter 11 case under the United States Bankruptcy Code. For additional information relating to CornerStone, see "Business—Unregulated Businesses—Discontinued Propane Operations—CornerStone—Recent Developments" included in Item 1 hereto and Exhibits 99.2, 99.3, 99.4 and 99.5 to this Annual Report on Form 10-K for the year ended December 31, 2001.

The following is certain additional information relating to our debt facilities listed in the above table.

Recourse Debt

The Mortgage Bonds are three series of general obligation bonds we issued, that are secured by substantially all of our electric and natural gas assets. As reflected in the table above, these bonds mature in 2002, 2005 and 2023.

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

The Pollution Control Obligations are three obligations we issued in 1993 that are secured by substantially all of our electric and gas assets.

The Floating Rate Notes are notes we issued in a private placement in September 2000, which mature on September 23, 2002. The effective interest rate on the notes for the year ended December 31, 2001 was 5.2% with a rate at December 31, 2001 of 2.65%.

The Bank Credit Facility was refinanced and paid in full on February 15, 2002, in connection with our acquisition of NorthWestern Energy LLC. We have replaced the Bank Credit Facility with a new $280.0 million revolving credit facility, which bears interest at a variable rate tied to the London Interbank Offered Rate plus a spread of 1.5% based on our current credit ratings and accrued interest at 3.34% per annum as of June 30, 2002. At September 9, 2002, we had $68.0 million of indebtedness outstanding and letters of credit totaling $19.6 million outstanding under our $280.0 million credit facility and $192.4 million of availability under the facility. Our revolving credit facility expires on February 14, 2003, although we may convert up to $225.0 million of the aggregate amount outstanding as of February 11, 2003 into a term loan on a non-revolving basis that matures on February 14, 2004. The credit agreement with respect to our revolving credit facility contains a number of representations and warranties and imposes a number of restrictive covenants that, among other things, limit our ability to incur indebtedness and make guarantees, create liens, make capital expenditures, pay dividends and make investments in other entities. In addition, we are required to maintain certain financial ratios, including:

•: net worth on the last day of each fiscal quarter of at least $350.0 million;
•: a funded debt to capital ratio on the last day of each fiscal quarter of no greater than 72% as of the last day of each fiscal quarter ending prior to February 14, 2003 and 68% for any quarter ending thereafter; and
•: a ratio of utility business EBITDA to consolidated recourse interest expense on the last day of each fiscal quarter of at least 2.00 to 1.00. During 2002, the ratio is calculated for the period from January 1, 2002 through the end of the respective fiscal quarter. Thereafter, the ratio is calculated for the four most recent fiscal quarter period.

For purposes of the above ratios:

•: net worth includes the sum of shareholders' equity, preferred stock, preference stock and corporation obligated mandatorily redeemable preferred securities of subsidiary trusts;
•: funded debt includes our consolidated indebtedness, excluding non-recourse debt;
•: total capital includes the sum of funded debt, shareholders' equity, preferred stock, preference stock and corporation obligated mandatorily redeemable preferred securities of subsidiary trusts; and
•: utility business EBITDA includes the sum of the operating income of the utility business, plus, without duplication and to the extent reflected as a charge in the statement of income of the utility business, depreciation and amortization.

We were in compliance with all ratios for the quarters ended March 31 and June 30, 2002. As of June 30, 2002, our net worth was $776.4 million, our funded debt to capital ratio was 68.5% and our ratio of utility business EBITDA to consolidated recourse interest expense was 2.52 to 1.00.

For a description of our 7⁷/8% and 8³/4% senior notes and the trust preferred securities, see "—Cash Flows and Cash Position—Investing and Financing Activities."

Nonrecourse Debt

The Expanets facility represents a short term line of credit provided to Expanets by Avaya for the purpose of financing purchases of Avaya products. This facility was recently amended to extend the repayment term through December 31, 2002 and was reduced from $125.0 million to $100.0 million on March 5, 2002, $80.0 million on April 30, 2002 and $55.0 million on August 30, 2002, and which had an outstanding balance of $39.6 million as of August 30, 2002. If Expanets defaults on this facility, we may be obligated to purchase up to $50.0 million of inventory and accounts from Avaya. As of December 31, 2001, the effective interest rate of this loan was 12%.

Montana Megawatts I, LLC, one of our wholly owned subsidiaries, is a party to a 365 day term loan facility providing for loans in an aggregate principal amount of $55.0 million with ABN AMRO Bank N.V. and Bank of Scotland to finance the purchase of certain equipment and related expenses for a 240 megawatt natural gas fired generation project currently under construction in Great Falls, Montana. The loans bear interest at LIBOR plus 1.00% on the first $27.5 million outstanding and LIBOR plus 1.50% on amounts outstanding in excess of $27.5 million, $27.5 million of the facility is currently scheduled to mature on September 28, 2002 and the remainder of the facility is currently scheduled to mature on September 28, 2003. We have provided a guarantee on 50% of the borrowings outstanding on the facility, up to a maximum guarantee of $27.5 million. As of December 31, 2001, $53.6 million had been drawn on the facility with an effective interest rate of 4.63% and is reflected on the balance sheet as part of non-recourse short term debt. We intend to seek to extend the facility for up to one year while Montana Megawatts seeks to enter into power purchase agreements to sell output from the project, which may include agreements with NorthWestern Energy LLC as the default supplier, after which we, or one or more of our affiliates, will seek to enter into traditional construction finance arrangements in connection with the project. For further information about the financing and operation of our Great Falls electric generation project, see note 4 of the notes to our consolidated financial statements included elsewhere herein.

The CornerStone guarantee relates to CornerStone's $50.0 million credit facility. At December 31, 2001, $41.2 million was outstanding under CornerStone's credit facility. The credit facility bears interest at a variable rate tied to a certain Eurodollar index or prime rate plus a variable margin, which depends upon CornerStone's ratio of consolidated debt to consolidated cash flow. The effective rate on the CornerStone credit facility at December 31, 2001 was 4.65%. As part of this facility, we agreed to provide a guaranty for the entire $50.0 million. In consideration for providing this guarantee, CornerStone's independent Audit Committee and Board of Directors approved a cash payment to us of

$2.3 million and granted us 487,179 warrants to purchase common units at $.10 per unit. All of the commitment fee has been accrued, but remains unpaid at December 31, 2001. CornerStone was projected to not be in compliance with certain covenants under this facility and on January 18, 2002 received an amendment to the credit agreement relaxing certain financial maintenance covenants and requiring CornerStone to eliminate any quarterly distributions to common unitholders for the remaining term of the facility. On August 20, 2002, NorthWestern purchased the lenders' interest in approximately $19.9 million of short-term debt, together with approximately $6.1 million in letters of credit, of CornerStone outstanding under CornerStone's credit facility, which NorthWestern had previously guaranteed. CornerStone may not make further drawings under this facility.

On August 5, 2002, CornerStone announced that it had elected not to make an interest payment aggregating approximately $5.6 million on three classes of its senior secured notes, which was due on July 31, 2002, and was continuing to review financial restructuring and strategic options, including the potential commencement of a Chapter 11 case under the United States Bankruptcy Code. We will continue to evaluate CornerStone's financial restructuring and the impact upon creditors of CornerStone, including us, and we expect to reflect any resulting financial implication in our third quarter 2002 results. For additional information relating to CornerStone, see "Business—Unregulated Businesses—Discontinued Propane Operations—CornerStone—Recent Developments" included in Item 1 hereto and Exhibits 99.2, 99.3, 99.4 and 99.5 to this Annual Report on Form 10-K for the year ended December 31, 2001.

The Blue Dot Facility expired in February 2002, and was paid in full, but there was $13.0 million outstanding under the facility at December 31, 2001.

The Other Debt includes a $35.0 million subordinated note payable to Avaya. In April 2000, Expanets completed a transaction to purchase the Lucent GEM business and, as part of the transaction, Expanets issued Avaya a $35.0 million subordinated note and a $15.0 million convertible note. The $15.0 million note converted into Series D Preferred Stock of Expanets prior to the end of 2001. The $35.0 million subordinated note, which matures on March 31, 2005, is discounted at December 31, 2001, to $23.7 million, as it is noninterest bearing.

The capital lease obligations are principally used to finance equipment purchases and capital leases and notes payable assumed by our subsidiaries in connection with their respective acquisitions of other businesses. These leases have various implicit interest rates, which range from 7.25% to 10.50%.

Capital Requirements

We expect to fund our day to day operations through our operating cash flows and our current cash and cash equivalents. Our principal capital requirements include continued funding for growth of existing business segments; funding new corporate investment and development ventures; funding maintenance and expansion programs; funding debt and preferred stock retirements, sinking fund requirements, and the payment of dividends to our common shareholders, all of which may require us to incur additional debt or sell or issue additional equity securities.

Maintenance capital expenditures for property, plant and equipment for the years ended December 31, 2001, 2000 and 1999, were $47.5 million, $29.0 million, and $24.9 million, respectively. Maintenance capital expenditures are capital expenditures incurred in order to maintain our business as it exists at that time. We estimate that our maintenance capital expenditures for 2002 and 2003 will be $57.4 million and $75.5 million, respectively. Our maintenance capital expenditures are continually examined and evaluated and may be revised in light of changing business operating conditions, variation in sales, investment opportunities and other business factors.

As of December 31, 2001, debt facilities totaling $521.3 million maintained by us or our subsidiaries will mature in 2002 and 2003 and will need to be repaid or extended, including:

•: our $150.0 million aggregate principal amount of floating rate notes, which are scheduled to mature on September 23, 2002;
•: Montana Megawatts I, LLC's $55.0 million term loan facility, of which $27.5 million is currently scheduled to mature on September 28, 2002 and of which $27.5 million is currently scheduled to mature on September 28, 2002; and
•: Expanets' $125.0 million nonrecourse equipment purchase financing facility with Avaya, which expires on December 31, 2002 and was reduced to $100.0 million on March 5, 2002, $80.0 million on April 30, 2002 and $55.0 million on August 30, 2002, and which had an outstanding balance of $39.6 million as of August 30, 2002.

On February 15, 2002, in connection with our acquisition of NorthWestern Energy LLC, we entered into our new $280.0 million revolving credit facility, which is scheduled to mature on February 14, 2003 although we may convert up to $225.0 million of the aggregate amount outstanding as of February 11, 2003 into a term loan on a non revolving basis that matures on February 14, 2004. We used the proceeds from certain financings in 2001 and 2002 and borrowings under our $280.0 million revolving credit facility to repay our $132.0 million credit facility and the $13.0 million Blue Dot credit facility borrowings that were outstanding, as discussed above under "—Recourse Debt" and "—Nonrecourse Debt," respectively. In addition, on August 20, 2002, NorthWestern purchased the lenders' interest in approximately $19.9 million of short-term debt, together with approximately $6.1 million in letters of credit, of CornerStone outstanding under CornerStone's credit facility, which had an outstanding balance of $41.2 million on December 31, 2001 and which NorthWestern had previously guaranteed. No further drawings may be made under this facility.

We intend to finance these obligations in a number of ways, including the issuance of additional securities and by obtaining new credit arrangements. We intend to raise approximately $150.0 million to $200.0 million in additional equity in 2002 and 2003, through one or more public offerings and/or private placements, and use the proceeds to retire debt and for other corporate purposes, including funding new corporate investments and acquisition and growth ventures. We may also consider applying a portion of our free cash flow and/or the net proceeds from sales of non core assets to further reduce our debt. We may also issue additional other debt or equity during the year for these purposes. However, there can be no assurance that we will be successful in our refinancing endeavors. See "Risk Factors—Our growth strategy is subject to risks and uncertainties, including those related to the integration of acquired businesses" and "Risk Factors—We will need significant additional capital to refinance our indebtedness that is scheduled to mature and for other working capital purposes, which we may not be able to obtain."

Several of the maturing obligations are obligations of our subsidiaries. If the subsidiaries are unable to secure alternate financing, we may need to provide them with additional financing to repay these maturing obligations and to fund their operations.

Blue Dot has expanded its operations by acquiring existing complementary businesses. These acquisitions have been funded, in part, through Blue Dot's prior credit facility. Blue Dot is currently negotiating for a working capital facility. It will be likely that we will need to provide Blue Dot with additional funding for acquisitions and general operating purposes.

Expanets is in the process of seeking an asset based commercial credit facility to replace the Avaya line of credit and to provide operating capital to fund its day to day operations. If Expanets is unable to secure an acceptable facility, it will be likely that we will need to provide Expanets with additional funding for general operating purposes. Additionally, Expanets is in the process of enhancing the operational capabilities of its new enterprise software system, which it calls the EXPERT system. We expect that Expanets will need to invest additional funds in the EXPERT system to fully implement it.

We have in the past, and may need to in the future, provide Expanets with funding for other working capital purposes until Expanets refinances the Avaya line of credit.

In July 2001, CornerStone formed a Special Committee of its Board of Directors to review the partnership operating plan and capital structure. Cornerstone also announced it has engaged Credit Suisse First Boston Corporation to pursue the possible sale or merger of CornerStone. Based upon CornerStone's current situation, it is impossible to predict CornerStone's future capital expenditures or how CornerStone will obtain the necessary capital. While the operations of CornerStone have been reflected in the June 2002 financial statements as discontinued operations, and the associated liabilities reflected as such, we have provided a guaranty for the entire $50.0 million bank credit facility that CornerStone maintains. As of December 31, 2001, $41.2 million was outstanding under that facility along with $3.8 million in letters of credit. The facility expires November 2003. CornerStone has breached its covenants under this facility and through an amendment executed January 18, 2002, the facility was continued but Cornerstone's ability to pay minimum quarterly distributions to its common unit holders was suspended for the remaining term of the facility. On August 20, 2002, NorthWestern purchased the lenders' interest in approximately $19.9 million of short-term debt, together with approximately $6.1 million in letters of credit of CornerStone, outstanding under CornerStone's credit facility, which NorthWestern had previously guaranteed. No further drawings may be made under this facility. On August 5, 2002, CornerStone announced that it had elected not to make an interest payment aggregating approximately $5.6 million on three classes of its senior secured notes, which was due on July 31, 2002, and was continuing to review financial restructuring and strategic options, including the potential commencement of a Chapter 11 case under the United States Bankruptcy Code. SYN, Inc., a majority owned subsidiary of NorthWestern Corporation, extended a $9.0 million loan to CornerStone for immediate financing needs.

We will continue to review the economics of extending the maturity dates or refinancing short term debt and retiring or refunding remaining long term debt and preferred stock to provide financial flexibility and minimize long term financing costs. We may continue to make investments in Blue Dot and Expanets. We have made $313.6 million in aggregate preferred stock investments in Expanets and $329.4 million in aggregate preferred stock investments in Blue Dot through December 31, 2001. Additionally, we advanced $51.4 million in credit to Expanets during 2001, which, along with other intercompany balances, was outstanding as of December 31, 2001. The loan bears interest at 17% per annum and repayment is anticipated in 2002. Pursuant to our growth strategy, we have evaluated, and expect to continue to evaluate, possible acquisitions in related and other industries on an ongoing basis and at any given time may be engaged in discussion or negotiations with respect to possible acquisitions. Some of these acquisitions may be significant and might require us to raise additional equity and/or incur debt financings, which are subject to certain risks and uncertainties. See "Risk Factors—Our growth strategy is subject to risks and uncertainties, including those related to the integration of acquired businesses."

Significant Accounting Policies

The preparation of our financial statements includes the application of several significant accounting policies. Understanding these policies is critical to comprehending our financial statements. The following is a discussion of the most significant policies we apply. Additional policies are described in Note 1 of our audited annual consolidated financial statements included elsewhere herein.

Revenue Recognition

Revenues are recognized differently depending on the type of revenue. Electric and natural gas utility revenues are recognized when customers are billed on a monthly basis, rather than on the basis of meters read or energy delivered. Communications and HVAC revenues are recognized when goods are delivered to customers or services are performed, except for revenues for services performed under material installation or service contracts, which are recognized in any given period based on the

percentage of costs incurred to date in relation to total estimated costs to complete the contracts. Certain judgments affect the application of our revenue recognition policy, primarily percentage of project completion. Revenue estimates in these areas are difficult to predict, and any shortfall in revenue or delay in recognizing revenue could cause our operating results to vary significantly from quarter to quarter and could materially impact future operating results.

Regulatory Assets and Liabilities

Our regulated operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. If any part of our operations become no longer subject to the provisions of SFAS No. 71, the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities would need to be evaluated. In addition, we would need to determine if there was any impairment to the carrying costs of deregulated plant and inventory assets. While we believe that our assumption regarding future regulatory actions is reasonable, different assumptions could materially affect our results.

Minority Interest in Consolidated Subsidiaries

Many of our acquisitions at Expanets and Blue Dot have involved the issuance of common stock in those subsidiaries to the sellers of the acquired businesses. In connection with certain acquisitions of Expanets and Blue Dot, the sellers can elect to exchange the stock of Expanets and Blue Dot for cash at a predetermined exchange rate. Our investments in Expanets and Blue Dot are principally in the form of senior preferred stock with voting control and a liquidation preference over the common stock. We are required to consolidate the financial results of Expanets and Blue Dot because of our voting control. The common stock issued to third parties in connection with acquisitions creates minority interests which are junior to our preferred stock interests. Operating losses at Expanets and Blue Dot have been allocated first to the common shareholders of each subsidiary in proportion to common equity ownership to the extent the allocation does not exceed the minority interest of such common shareholders in the equity capital of the subsidiary after giving effect to any put options or exchange agreements, and thereafter is allocated to the preferred shareholders of each subsidiary in the order of priority equal to the liquidation preference of each series of preferred stock. Exchange agreements totaling $6.0 million for Expanets and $12.4 million for Blue Dot remained outstanding and were included in minority interests as of December 31, 2001. The equity held by third parties of these entities is as follows:

		Third Party Equity Reflected as Minority Interests At December 31,
		2001		2000
		(in thousands)
Expanets		$	17,124	$	140,390
Blue Dot			12,439		51,691
Other			504		751

	Total	$	30,067	$	192,832

The Minority Interests in Net Loss of Consolidated Subsidiaries contained in our consolidated statements of income is the income (loss) of our subsidiaries which is allocable to minority interests. In order to determine the allocation of income (loss) to minority interests, preferred dividends and corporate services allocations are deducted from the income (loss) before minority interests reported in our segment disclosures in order to arrive at the Minority Interests in Net Loss of Consolidated

Subsidiaries contained in our consolidated statements of income. The corporate services allocations relate to certain services NorthWestern provides to, and is reimbursed from, its subsidiaries for management services, including insurance, administrative support for employee benefits, transaction structuring, financial analysis and information technology. These services are discussed in Note 1 "Significant Accounting Policies—Related Party Transactions" to NorthWestern's annual consolidated financial statements. The preferred dividends relate to dividends on our 12% coupon Preferred Stock of Expanets and our 11% coupon Preferred Stock of Blue Dot. The preferred dividends and corporate services allocations are eliminated in consolidation. The net income (loss) before minority interests and net income (loss) available to common equity holders reported in our segment disclosures includes the portion of interest expense on our $51.4 million loan to Expanets which is allocable to third party minority interests.

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

			Year ended December 31, 2001
			HVAC (Blue Dot)			(in thousands) Communications (Expanets)			Total
Income (loss) before minority interests			$	(13,562	)	$	(87,008	)⁽¹⁾	$	(100,570	)
	Preferred dividends			(28,192	)		(33,062	)		(61,254	)
	Management fees			(3,047	)		(7,971	)		(11,018	)

		Net income (loss) available to common equity holders	$	(44,801	)	$	(128,041	)	$	(172,842	)

Income (loss) allocation to shareholders:
	NorthWestern		$	(31,246	)	$	(148	)	$	(31,394	)
	Minority interests			(13,555	)		(127,893	)		(141,448	)

	Total		$	(44,801	)	$	(128,041	)	$	(172,842	)

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

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

			Year ended December 31, 2000
			HVAC (Blue Dot)			(in thousands) Communications (Expanets)			Total
Income (loss) before minority interests			$	(2,265	)	$	(19,799	)⁽²⁾	$	(22,064	)
	Preferred dividends			(19,570	)		(25,907	)		(45,477	)
	Management fees			(2,324	)		(4,264	)		(6,588	)

		Net income (loss) available to common equity holders	$	(24,159	)	$	(49,970	)	$	(74,129	)

Income (loss) allocation to shareholders:
	NorthWestern		$	(6,246	)	$	(62	)	$	(6,308	)
	Minority interests			(17,913	)		(49,908	)		(67,821	)

	Total		$	(24,159	)	$	(49,970	)	$	(74,129	)

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

Preferred dividends for the year ended December 31, 2000 of $25.9 and $19.6 million for Expanets and Blue Dot, respectively, represent increases of $9.9 million and $7.0 million, respectively, which reflect increased investments by NorthWestern in the preferred stock of each entity. Corporate allocations for the year ended December 31, 2000 of $4.3 and $2.3 million for Expanets and Blue Dot, respectively, represent increases of $2.4 million and $2.3 million, respectively. The increase at Expanets is due to increased services provided by NorthWestern primarily related to the non-recurring transition and integration expenses related to the acquisition of the Lucent GEM assets. The increase at Blue Dot is due to continued increased involvement and corporate services provided by NorthWestern.

			Year ended December 31, 1999
			HVAC (Blue Dot)			(in thousands) Communications (Expanets)			Total
Income (loss) before minority interests			$	2,104		$	3,486		$	5,590
	Preferred dividends			(12,616	)		(16,037	)		(28,653	)
	Management fees			—			(1,860	)		(1,860	)

		Net income (loss) available to common equity holders	$	(10,512	)	$	(14,411	)	$	(24,923	)

Income (loss) allocation to shareholders:
	NorthWestern		$	(117	)	$	(18	)	$	(135	)
	Minority interests			(10,395	)		(14,393	)		(24,788	)

	Total		$	(10,512	)	$	(14,411	)	$	(24,923	)

As of December 31, 2001, no remaining minority interest basis existed with respect to Blue Dot against which to allocate losses and $11.1 million of minority interest basis existed with respect to Expanets against which to allocate losses. Accordingly, if such subsidiaries incur operating losses in the future, unless additional minority interest is issued as a result of new acquisitions, our share of any such losses with respect to Blue Dot and our share of any such losses in excess of $11.1 million with respect to Expanets will be recognized in our operating results. Different capital structures in the future or unanticipated future operating results, either positive or negative, could result in materially different results.

As of December 31, 2001, our common stock basis in Expanets and Blue Dot was $0.3 million and zero, respectively, as a result of losses applicable to common stock of those entities that was allocated to us based on our common stock ownership. As of December 31, 2001, our preferred stock basis in

Expanets and Blue Dot was $313.6 million and $292.3 million, respectively. In addition, we also loaned $51.4 million to Expanets for general operating purposes during 2001, which was outstanding at December 31, 2001, which we anticipate is likely to be repaid in 2002. We had an intercompany advance to Expanets totaling $11.7 million and $113.4 million as of December 31, 2001 and June 30, 2002, respectively, which we anticipate is likely to be repaid in 2003. We also had an intercompany advance to Blue Dot totaling $16.2 million and $22.8 million as of December 31, 2001 and June 30, 2002, respectively, which we anticipate is likely to be repaid in 2003.

Derivative Financial Instruments

We have entered into commodity futures contracts for natural gas to attempt to reduce the risk of future price fluctuations. Any increase or decrease in the values of these contracts are reported as gains and losses in our consolidated statements of income. The fair value of fixed price commodity contracts are estimated based on market prices of natural gas, natural gas liquids and crude oil for the periods covered by these contracts.

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, requires every derivative instrument, including certain derivative instruments imbedded in other contracts, to be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires any changes in the derivative's fair value to be currently recognized in earnings, unless specific hedge accounting criteria are met. We adopted the provisions of SFAS No. 133, as amended, effective July 1, 2000, consistent with the timing of CornerStone's adoption of SFAS No. 133. The initial adoption of SFAS No. 133 at CornerStone resulted in a charge of $5.3 million. Such charge is reflected in the consolidated statements of income as a cumulative effect of change in accounting principles and is shown net of taxes of $0.5 million and net of minority interest of $3.8 million. Pricing increases resulting in a change of the fair value of propane related and natural gas commodity futures were reported as part of cost of sales in the amount of $0.2 million and $0.3 million for the years ended December 31, 2001 and 2000. Changes in the commodity markets may materially impact our future estimates of fair value and operating results. 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."

SFAS No. 142, Goodwill and Other Intangible Assets and Long Lived Assets

SFAS No. 142, which was issued during 2001 and is effective for all fiscal years beginning after December 15, 2001, eliminates amortization of goodwill and allows amortization of other intangibles only if the assets have a finite, determinable life. Based on SFAS No. 142, we are required to perform an impairment analysis of intangible assets at the reporting unit level, at least annually to determine whether the carrying value exceeds the fair value. In instances where the carrying value is less than the fair value of the asset, an impairment loss must be recognized.

CornerStone adopted SFAS No. 142 effective July 1, 2001, and we adopted SFAS No. 142 effective January 1, 2002. CornerStone's initial assessment indicated no impairment associated with the adoption. CornerStone's amortization expense for the six month period ended December 31, 2001, was reduced by approximately $4.0 million as a result of the adoption. However, the effect of this reduction and all other impacts of CornerStone's adoption of SFAS No. 142 have been fully reversed in our financial statements as a result of our adoption of SFAS No. 142 on January 1, 2002. We are currently in the process of evaluating the impact of SFAS No. 142 on all reporting units. Amortization of goodwill totaled $11.3 million, $19.8 million and $7.0 million for the years ended December 31, 2001, 2000 and 1999, respectively, excluding CornerStone. Had we adopted the provisions of SFAS No. 142 in those years, it would have resulted in an increase to earnings on common stock, net of taxes and minority interests, of $8.6 million, $6.3 million and $20,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Basic earnings per share would have increased $0.35 and $0.27 for 2001 and 2000, respectively, with no impact for 1999. Diluted earnings per share would have increased by $0.36 and $0.27 for 2001 and 2000, respectively, with no impact for 1999.

Property, plant and equipment, and intangibles that may be amortized pursuant to SFAS No. 142 are depreciated and amortized over their useful lives. The useful life of an asset is based on our estimate of the period that the asset will provide benefit. We review all long lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as measured by the future net cash flows expected to be generated by the asset. If such an asset is considered impaired, the impairment recognized is measured by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

Additional New Accounting Standards

SFAS No. 141, Business Combinations, issued in June 2001, requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. In addition, it requires that all identifiable intangible assets be separately recognized and the purchase price allocated accordingly. In some cases, this will result in the recognition of substantially more categories of intangibles.

SFAS No. 143, Accounting for Asset Retirement Obligations, was issued in August 2001. It addresses financial accounting and reporting for obligations associated with the retirement of tangible long lived assets and the associated asset retirement costs. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The impact on our results of operations and financial position is currently under review by management.

SFAS No. 144, Accounting for the Impairment or Disposal of Long Lived Assets, was issued in October 2001. It establishes a single accounting model for long lived assets to be disposed of by sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The impact of the Statement on our results of operations and financial position is currently under review by management.

RELATED PARTY TRANSACTIONS

In order to provide a recruitment and retention incentive, NorthWestern adopted a long-term equity incentive program in September 1999 in which certain key executives of NorthWestern and key team members of NorthWestern Growth Corporation, which initiates strategic investments for NorthWestern, were provided the opportunity to make personal investments. The investment entity was structured as a limited liability company, is controlled and substantially owned by NorthWestern, and enables the investors to participate in long-term capital appreciation resulting from increases in the value of NorthWestern's interests in Blue Dot, Expanets and CornerStone above benchmark rates of return to NorthWestern approved by the independent Compensation Committee of NorthWestern's Board of Directors. Participants 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 NorthWestern. The interest of NorthWestern executives in the limited liability company upon formation collectively represented a less than 0.5% interest in each of Blue Dot, Expanets and CornerStone. The limited liability company has no indebtedness and is consolidated in NorthWestern's financial statements. No losses of these subsidiaries have been allocated to the minority interest owned by the limited liability company. NorthWestern has the right to acquire the limited liability company interests of the investors under specified circumstances, including termination of employment. In the year ended December 31, 2001, the following executive officers of NorthWestern received distributions in respect of the transfer to NorthWestern of a portion of their vested interests: M. Lewis, chief executive officer, $1.1 million; R. Hylland, president, $0.8 million; D. Newell, senior vice president, $0.8 million; E. Jacobsen, senior vice president, $0.4 million; and K. Orme, chief financial officer, $0.1 million. This recruitment and retention program is no longer being utilized to provide long-term equity incentives and is no longer open to new participants, although the pre-existing interests of the participants remain outstanding.

RISK FACTORS

You should carefully consider the risk factors described below, as well as other information included or incorporated by reference in this Annual Report on Form 10-K, before making an investment in our common stock. 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.

Our growth strategy is subject to risks and uncertainties, including those related to the integration of acquired businesses.

A substantial part of our growth has been from acquisitions and a substantial part of future growth in our utility business may come from acquisitions. Pursuant to our growth strategy, we have evaluated and expect to continue to evaluate possible acquisitions on an ongoing basis and at any given time may be engaged in discussions or negotiations with respect to possible acquisitions or strategic investments in the energy or communications industries. Some of these acquisitions may be significant and might require us to raise additional equity and/or incur debt financings. Our growth strategy is subject to certain risks and uncertainties, including:

•: the future availability of market capital to fund development and acquisitions,
•: our ability to develop and implement new growth initiatives,
•: our ability to identify acquisition targets,
•: our response to increased competition,
•: our ability to attract, retain and train skilled team members,
•: governmental regulations and
•: general economic conditions relating to the economy and capital markets.

Many of our acquisitions at Expanets and Blue Dot have involved the issuance of common stock in those subsidiaries to the sellers of the acquired businesses. Our investments in Expanets and Blue Dot are principally in the form of senior preferred stock with voting control and a liquidation preference over the common stock held by third parties. We are required to consolidate the financial results of Expanets and Blue Dot because of our voting control. The common stock issued to third parties in connection with acquisitions creates minority interests which are junior to our preferred stock interests and against which operating losses have been allocated. As of December 31, 2001, however, no remaining minority interest basis existed with respect to Blue Dot against which to allocate losses and only $11.1 million of minority interest basis existed with respect to Expanets against which to allocate losses. Accordingly, if such subsidiaries incur operating losses in the future, unless additional minority interests are issued as a result of new acquisitions, our share of any such losses with respect to Blue Dot and our share of any such losses in excess of $11.1 million with respect to Expanets will be recognized in our operating results. See note 1 to our annual consolidated financial statements included elsewhere herein.

In addition, our acquisition activities involve the risk of successfully transitioning, integrating and managing acquired companies, including assessing the adequacy and efficiency of information, technical and accounting systems, business processes and related support functions and realizing cost savings and efficiencies from integration in excess of any related restructuring charges. We could expend a substantial amount of time and capital integrating businesses that have been acquired or pursuing acquisitions we do not consummate, which could adversely affect our business, financial condition and results of operations.

The integration and management of NorthWestern Energy LLC into our existing NorthWestern Energy division could result in the expenditure of significant additional resources and may adversely affect our results of operations and financial condition.

Our acquisition of NorthWestern Energy LLC increased our revenues on a consolidated basis by approximately 38% on a pro forma basis for the year ended December 31, 2001 and the integration and management of NorthWestern Energy LLC into our existing NorthWestern Energy division may place significant strain on our management, financial and other resources. The integration of NorthWestern Energy LLC with our NorthWestern Energy division may involve, among other things, integration of operations, maintenance, billing, accounting, quality control, management, personnel, payroll, regulatory compliance and other systems and operating hardware and software, some of which may be incompatible with our existing systems and therefore may need to be replaced. To the extent we are required to incur significant additional costs integrating these operations, our results of operations and financial condition could be adversely affected.

The continuing integration of the Growing and Emerging Markets, or GEM, division of Lucent Technologies, Inc. into Expanets' business could adversely affect Expanets' operations and financial condition.

Expanets is subject to risks associated with its continuing integration of the significant acquisition of the GEM division of Lucent Technologies, Inc. and other acquired businesses into its operations. These risks include reliance upon transition services agreements entered into with the sellers of such businesses, substantial investments in corporate infrastructure systems to enable Expanets to terminate such transition services agreements and the integration of these systems into our existing operations, the successful integration of the much larger GEM business with the existing Expanets business and the successful transition of the historical GEM sales from voice equipment to relatively higher margin integrated voice and data services solutions despite weakness in the communications and data sectors generally. In particular, Expanets has undertaken a restructuring of its sales force for future growth initiatives, migration of the business to a common information technology platform and the elimination of costly transition expenses. Expanets has spent significant amounts integrating the GEM business to date. Although Expanets believes that the integration is substantially complete, we cannot assure that Expanets will not be required to incur additional costs in completing this integration. See "Business—Unregulated Businesses—Communications, Network Services and Data Solutions—Expanets" included in Item 1 hereof. To the extent Expanets incurs significant additional costs associated with the integration of the GEM business into its business, Expanets' operations and financial condition could be adversely affected.

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

Montana law requires that the MPSC determine the value of net unmitigable transition costs associated with the transformation of the former Montana Power utility business from a vertically integrated electric service company to a utility providing only default supply and transmission and distribution services. The MPSC is 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 former owner of NorthWestern Energy LLC was required to enter into with certain "qualifying facilities" as established under the Public Utility Regulatory Policies Act of 1978. The former owner of NorthWestern Energy LLC estimated the pre-tax 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 approved a stipulation among the former owner of NorthWestern Energy LLC, us and a number of other parties, which, among other things, conclusively established the

pre-tax net present value of the retail transition costs relating to out-of-market power purchase contracts recoverable in retail rates over the next 28 years to be approximately $244.7 million. 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 in the fourth year and thereafter. 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. The pre-tax net present value of the retail transition costs approved in the MPSC stipulation is approximately $60.0 million less than the former owner of NorthWestern Energy LLC estimated in its initial filing with the MPSC. We estimate that the annual after tax differences will be approximately $1.9 million in 2002, increasing to a high of approximately $13.2 million in 2017. The estimated aggregate after tax amount of the differences over the remaining 28-year life of these contracts would be approximately $193.5 million. Although we believe we have opportunities to mitigate the impact of these differences, we cannot assure you that we will be successful. To the extent we are unable to mitigate these differences, our net income and financial condition could be adversely affected.

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.

The 1997 Montana Restructuring Act provided that customers be able to choose their electricity supplier during a transition period ending on June 30, 2007. NorthWestern Energy LLC is required to act as the "default supplier" for customers who have not chosen an alternate supplier. The Restructuring Act provided for full recovery of costs incurred in procuring a default supply portfolio of electric power and required the default supplier to propose a "cost recovery mechanism" for electrical supply procurement costs before March 30, 2002. On October 29, 2001, the former owner of NorthWestern Energy LLC filed with the MPSC its initial default supply portfolio, containing a mix of long and short-term contracts from new and existing generators. On April 25, 2002, the MPSC approved NorthWestern Energy LLC's proposed "cost recovery mechanism" in the form filed.

On June 21, 2002, the MPSC issued a final order approving contracts meeting approximately 60% of the default supply winter peak load and approximately 93% of the annual energy requirements, and choosing not to preapprove five proposed contracts relating to new generation construction projects, including a contract for 150 megawatts in winter and 75 megawatts in summer with Montana First Megawatts, a 240 megawatt gas-fired generation project being constructed by a NorthWestern subsidiary in Great Falls, Montana. In refusing preapproval of the new generation contracts, the MPSC stated that "prudently incurred costs related to electricity procured from new generation projects are fully recoverable in rates," but that the former owner of NorthWestern Energy LLC did not adequately document and explain its analysis and judgments which led to the specific mix of resource types, products, contract lengths, price stability, dispatchability, risk and other characteristics of the chosen portfolio. As a result of the order, NorthWestern Energy LLC will seek to obtain the remainder of the default supply portfolio through a combination of new power purchase contracts conforming to the MPSC's guidance and open market purchases. In addition, the MPSC approved our "cost recovery mechanism" in the form filed. Currently, NorthWestern Energy LLC 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 to the cost recovery process that has been successfully utilized for more than 20 years in Montana, South Dakota and other states for natural gas purchases for residential and commercial customers. The MPSC further stated

that NorthWestern Energy LLC has an ongoing responsibility to prudently administer its supply contracts and the energy procured pursuant to those contracts for the benefit of ratepayers. We expect that the costs of the default supply portfolio and a competitive transition charge for out-of-market costs will increase residential electric rates in NorthWestern Energy LLC's service territories by less than 10% during the first year. The MPSC may disallow the recovery of the costs incurred under default supply portfolio contracts in the future, if it makes a determination that the contracts other than the contracts which were preapproved were not prudently entered into or that the contracts were not prudently administered. A failure to recover such costs could adversely affect our net income and financial condition.

We are subject to extensive governmental regulations which could impose significant costs on 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 and regulations 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.

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. To the extent competitive pressures increase and the pricing and sale of electricity assumes more characteristics of a commodity business, the economics of domestic independent power generation projects may come under increasing pressure.

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 day-to-day 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 regularly monitor our operations to prevent adverse environmental impacts. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills and the repair and upgrade of our facilities in order to meet

future requirements under environmental laws. Most of our generating capacity is derived from our non-operating minority interests in three coal burning generating facilities.

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, in which we own an approximate 23.4% interest, beginning in the year 2000. The Clean Air Act also contains a requirement for future studies to determine what, if any, limitations and controls should be imposed on coal-fired boilers to control emissions of certain air toxics, including mercury. Because of the uncertain nature the air toxic emission limits and the potential for development of more stringent emission standards in general, we cannot reasonably determine the additional costs we may incur under the Clean Air Act.

In addition, the U.S. Environmental Protection Agency, or the EPA, listed the Milltown Reservoir, which sits behind a hydroelectric dam owned by NorthWestern Energy LLC, on its Superfund National Priority List in 1983 as a result of the collection of toxic heavy metals in the silts. The Atlantic Richfield Company, or ARCO, as successor to the Anaconda Company, has been named as the party with responsibility for completing the remedial investigation and feasibility studies and conducting site cleanup, under the EPA's direction. The former owner of NorthWestern Energy LLC did not undertake any direct responsibility in that regard, in light of a special statutory exemption from liability under CERCLA in relation to the Milltown Dam. By virtue of its acquisition of The Montana Power Company's utility business and the dam, NorthWestern Energy LLC succeeded to similar protection under this statutory exception. ARCO has argued that the former owner of NorthWestern Energy LLC should be considered a Potentially Responsible Party, or PRP, and has threatened to challenge its exempt status. ARCO and the former owner of NorthWestern Energy LLC entered into a settlement agreement to limit the former owner's and now NorthWestern Energy LLC's potential liability, 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 final Record of Decision is not expected to be issued until late 2002 or early 2003. Depending on the outcome of that decision, we may be required to defend our exempt position. We cannot assure you that we will not incur costs or liabilities associated with the Milltown Dam site in the future, some of which could be significant. We have established a reserve of approximately $30.0 million at December 31, 2001, primarily for liabilities related to the Milltown Dam and other environmental liabilities. To the extent we incur liabilities greater than our reserve, our financial condition and results of operations could be adversely affected. See "Business—Environmental" contained in Item 1 herein.

You are unlikely to be able to exercise effective remedies or collect judgments against Arthur Andersen and we may incur material expenses or delays in financings or SEC filings because we changed auditors.

Arthur Andersen LLP has served as our independent accountants since 1932. On March 14, 2002, Arthur Andersen was indicted by a federal grand jury on obstruction of justice charges arising from the government's investigation of Enron Corp. In light of recent events concerning Arthur Andersen, we dismissed Arthur Andersen as our independent public accounting firm and retained Deloitte & Touche LLP in their stead on May 16, 2002, although Arthur Andersen has audited our consolidated financial statements contained in this Annual Report on Form 10-K. On June 15, 2002, Arthur Andersen LLP was found guilty by a jury in Houston, Texas of obstructing justice. In light of the jury verdict and the underlying events, Arthur Andersen has ceased practicing before the SEC. Because it is unlikely that Arthur Andersen will survive, you are unlikely to be able to exercise effective remedies or collect judgments against them.

As a public company, we are required to file with the SEC periodic financial statements audited or reviewed by an independent, certified public accountant. Our access to the capital markets and our ability to make timely filings with the SEC could be impaired if the SEC ceases accepting financial

statements audited by Arthur Andersen. In addition, because both the partner and the audit manager who were assigned to our account have left the firm, Arthur Andersen will be unable to provide other information or documents that would customarily be received in connection with financings or other transactions. As a result, we may encounter delays, additional expense and other difficulties in future financings. Any resulting delay in accessing or inability to access the public capital markets could be disruptive to our operations and could affect the price and liquidity of our securities.

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

In response to the occurrence of several recent events, including the September 11, 2001 terrorist attack on the United States, the ongoing war against terrorism by the United States and the bankruptcy of several large energy and telecommunications companies, the financial markets have been disrupted in general and the availability and cost of capital for our business and that of our competitors has been adversely affected. In addition, the credit rating agencies have initiated a thorough review of the capital structure and earnings power of certain energy companies. These events could constrain the capital available to our industry and could adversely affect our access to funding for our operations, including the funding necessary to refinance our indebtedness that is scheduled to come due in 2002 and 2003. See "—We will need significant additional capital to refinance our indebtedness that is scheduled to mature and for other working capital purposes, which we may not be able to obtain." The achievement of our growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be acceptable. If our ability to access capital becomes significantly constrained, our financial condition and future results of operations could be significantly adversely affected.

The insurance industry has also been disrupted by these events. As a result, 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.

A downgrade in our credit rating could negatively affect our ability to access capital.

S&P, Moody's and Fitch rate our senior, unsecured debt at "BBB" with a negative outlook, "Baa2" with a negative outlook and "BBB+," respectively. On September 3, 2002, S&P placed our ratings on rating watch negative to reflect changes in NorthWestern's plan for issuing equity and continued weakness in our unregulated businesses. On August 1, 2002, Moody's placed our ratings under review for possible downgrade and Fitch placed our ratings on rating watch negative following the announcement that CornerStone had exercised a five business day grace period with respect to interest payments on three classes of its outstanding senior secured notes. Credit ratings are dependent on a number of quantitative and qualitative factors. Moody's has stated that even though the acquisition of NorthWestern Energy LLC will benefit NorthWestern by increasing cash flow from more stable regulated operations, the reason for the negative outlook in its rating was primarily due to the combined effects of a general weakening of our credit profile over the past year and Moody's expectations for a significant increase in our debt leverage and correspondingly weaker cash flow coverage ratios in the near-term as a result of our acquisition of NorthWestern Energy LLC. Although we are not aware of any current plans of S&P, Moody's or Fitch to further lower their respective ratings on our debt, we cannot assure you that our credit ratings will not be downgraded if we do not reduce our leverage. Although none of our debt instruments contain acceleration and repayment provisions in the event of a downgrade in our debt ratings by S&P, Moody's or Fitch, if such a downgrade were to occur, particularly below investment grade, our ability to access the capital markets and utilize trade credit may be adversely affected and our borrowing costs would increase which would adversely impact our results and condition. In addition, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.

A downgrade in our credit rating could limit our ability to pay dividends or acquire shares of our capital stock.

If our credit rating by Standard & Poor's falls below BBB- or our credit rating by Moody's falls below Baa3, we will not be able to declare or pay dividends or make other distributions with respect to any class of our capital stock or purchase, redeem, retire or otherwise acquire any such stock without the consent of the lenders, under the terms of our $280.0 million revolving credit facility. In addition, in the event of such a downgrade in our credit rating by either rating agency, we may not permit any of our subsidiaries to pay dividends or make distributions with respect to any class of its capital stock other than dividends to be paid to us or another of our wholly owned subsidiaries or acquire shares of its capital stock other than as required by existing agreements, under the terms of our credit agreement.

We have substantial indebtedness, which could adversely affect our financial condition.

We have a significant amount of indebtedness outstanding as a result of our acquisition of NorthWestern Energy LLC. We had total consolidated indebtedness of approximately $0.8 billion outstanding as of December 31, 2001.

Our substantial indebtedness could have important consequences to you. For example, it could:

•: increase our vulnerability to general adverse economic and industry conditions;
•: require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures and other general corporate purposes;
•: limit our flexibility in planning for, or reacting to, changes in our business and the industries in which we operate;
•: result in vendors requiring additional credit support, such as letters of credit, in order for us to utilize trade credit;
•: place us at a competitive disadvantage compared to our competitors that have less debt; and
•: limit our ability to borrow additional funds.

Our failure to comply with any of the covenants contained in the instruments governing our indebtedness could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding indebtedness. We may not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

We could enter into acquisitions, changes of control, refinancings or other recapitalizations or highly leveraged transactions that could adversely affect the trading price of our common stock.

The indentures governing our indebtedness do not prevent us from entering into acquisitions, changes of control, refinancings or other recapitalizations or highly leveraged transactions. These transactions could increase the amount of our outstanding indebtedness or otherwise affect our capital structure or credit quality and could result in the acceleration of the indebtedness outstanding under our credit facility. If we enter into acquisitions, changes of control, refinancings or other recapitalizations or highly leveraged transactions, the trading price of our common stock could be adversely affected.

We will need significant additional capital to refinance our indebtedness that is scheduled to mature and for other working capital purposes, which we may not be able to obtain.

We have completed a number of financings during 2001 and the beginning of 2002 as discussed in "—Liquidity and Capital Resources—Cash and Cash Position—Investing and Financing Activities." In addition, we will be required to obtain significant additional capital in 2002, 2003 and 2004 to execute our business plan, including for working capital purposes and to repay existing indebtedness scheduled to mature during the period. In particular, we will be required to repay, refinance or extend the following indebtedness:

•: our $150.0 million aggregate principal amount of floating rate notes, which are scheduled to mature on September 23, 2002;
•: Montana Megawatts I, LLC's $55.0 million term loan facility, of which $27.5 million is currently scheduled to mature on September 28, 2002 and of which $27.5 million is currently scheduled to mature on September 28, 2003;
•: Expanets' $125.0 million nonrecourse equipment purchase financing facility with Avaya, which expires on December 31, 2002 and was reduced to $100.0 million on March 5, 2002, $80.0 million on April 30, 2002 and $55.0 million on August 30, 2002, and which had an outstanding balance of $39.6 million as of August 30, 2002. We expect to continue to reduce the balance of this facility on a monthly basis in the ordinary course of business. Amounts repaid under this facility may not be reborrowed; and
•: our new $280.0 million working capital facility, which is scheduled to mature on February 14, 2003, although we may convert up to $225.0 million of the aggregate amount outstanding as of February 11, 2003 into a term loan on a non-revolving basis that matures on February 14, 2004. If we elect to exercise our option to convert the balance under our revolving credit facility into a term loan, we will need to repay or refinance such debt on or prior to its maturity in February 2004.

We used the net proceeds from the issuance and sale of $250.0 million aggregate principal amount of our 7⁷/8% senior notes due March 15, 2007 and $470.0 million aggregate principal amount of our 8³/4% senior notes due March 15, 2012 to refinance the term loan portion of our acquisition credit facility. We intend to raise approximately $150.0 million to $200.0 million in additional equity in 2002, through one or more public offerings and/or private placements, and use the proceeds to retire debt and for other corporate purposes. We may also consider applying a portion of our free cash flow and/or the net proceeds from sales of non-core assets to further reduce our debt. Our ability to obtain additional financing will be dependent on a number of factors, including those discussed in "—We have substantial indebtedness, which could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes." See also "Management's Discussion and Analysis of Financial Condition and Results of Operations— Liquidity and Capital Resources." If we are unable to obtain additional financing, our working capital, results of operations and financial condition could be adversely affected and the trading price of our common stock could decline.

Our operating results may fluctuate on a seasonal and quarterly basis.

Our electric and gas utility business and, to a lesser extent, Blue Dot's HVAC business are seasonal businesses and weather patterns can have a material impact on their operating performance. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Similarly, Blue Dot's business is subject to seasonal variations in certain areas of its service

lines, with demand for residential HVAC services generally higher in the second and third quarters. 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, we could experience an adverse effect on our results of operations and financial condition.

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.

To the extent not covered by long-term fixed price purchase contracts, we are exposed to changes in the price and availability of coal because most of our generating capacity is coal-fired. Changes in the cost of coal and changes in the relationship between those costs and the market prices of power may affect our financial results. In addition, natural gas is a commodity, the market price of which can be subject to volatile changes in response to changes in the world crude oil market, refinery operations, supply or other market conditions. Because the rates at which we sell electricity and natural gas are set by state regulatory authorities, we may not be able to immediately pass on to our retail customers rapid increases in the wholesale cost of coal and natural gas, which could reduce our profitability.

Item 8. Financial Statements and Supplementary Data

The consolidated financial statements and supplementary data of NorthWestern required to be included in this Item 8 are set forth in a separate section of this report and commence on Page F-1 immediately following page 80.

Part IV

Item 14. Exhibits, Financial Statements and Reports on Form 8-K

(a) The following documents are filed as exhibits to this report:

(1) Financial Statements

The following items are included in Part II, Item 8 of this annual report:

FINANCIAL STATEMENTS:

Report of Independent Public Accountants

Consolidated Statements of Income for the Three Years Ended December 31, 2001

Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2001

Consolidated Balance Sheets as of December 31, 2001 and 2000

Consolidated Statement of Shareholders' Equity for the Three Years Ended December 31,
2001

Notes to Consolidated Financial Statements

Quarterly Unaudited Financial Data for the Two Years Ended December 31, 2001

(2) Financial Statement Schedules

Schedule II. Valuation and Qualifying Accounts

(3): The Exhibits filed as part of this report are listed in the Index to Exhibits immediately preceding such exhibits, which Index to Exhibits is incorporated herein by reference.

(b) Reports on Form 8-K

We filed a Current Report on Form 8-K with the SEC on December 21, 2001, to cause the underwriting agreement that we and NorthWestern Capital Financing II entered into on December 18, 2001, with respect to the sale of an aggregate of 4,000,000 of NorthWestern Capital Financing II's 8¹/4% Trust Preferred Securities, with an overallotment option of up to an aggregate of 600,000 additional Trust Preferred Securities of NorthWestern Capital Financing II, together with the consent of our independent accountants as to certain matters and the opinions and consents of our attorneys to be incorporated by reference into the registration statement on Form S-3 under Rule 429(b) under the Securities Act of 1933, as amended, which registration statement was declared effective on July 27, 1999 (File No. 333-82707).

We filed a Current Report on Form 8-K/A with the SEC on December 18, 2001, to amend the Current Report on Form 8-K filed with the SEC on December 12, 2001 to provide updated pro forma financial statements in Item 7(b), to provide an updated consent of experts relating to the financial statements and to provide updated Statements of Eligibility under the Trust Indenture Act of 1939 on Forms T-1.

We filed a Current Report on Form 8-K/A with the SEC on December 13, 2001, to include certain material agreements and to file a consent of experts relating to the financial statements as additional exhibits to the Current Report on Form 8-K filed with the SEC on December 12, 2001.

We filed a Current Report on Form 8-K with the SEC on December 12, 2001, to disclose under Item 5 of the Report (1) that our agreement to acquire the utility business of The Montana Power Company received approval of the Federal Energy Regulatory Commission and Hart-Scott-Rodino clearance as well as supermajority approval by The Montana Power Company's shareholders, (2) that we obtained a commitment for a $1.0 billion credit facility, with a term of 364 days following the closing date of the acquisition, to finance the transaction and refinance our existing credit facility and (3) that we filed a Rule 424(b) prospectus supplement under our previously filed Registration Statements File Nos. 333-58491 and 333-82707 with respect to the issue and sale by the NorthWestern Capital Financing II, a Delaware statutory business trust of up to $200.0 million aggregate amount of trust preferred securities. The Form 8-K also contained certain audited financial statements of The Montana Power Company Utility and certain unaudited pro forma financial statements related thereto.

We filed a Current Report on Form 8-K with the SEC on October 12, 2001, to disclose under Item 5 of the Report that on October 10, 2001, we agreed to sell up to 3,680,000 shares of our common stock in an underwritten public offering.

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
NORTHWESTERN CORPORATION AND SUBSIDIARIES

			Column C
Column A Description	Column B Balance Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (1)		Column D Deductions (2)			Column E balance End of Period
FOR THE YEAR ENDED DECEMBER 31, 2001 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts	$	8,258	$	13,972	$	745⁽³⁾	$	(11,612	)	$	11,363
OTHER DEFERRED CREDITS
Reserve for decommission costs	$	10,349	$	519	$	—	$	—		$	10,868
Reorganization/restructuring liabilities of acquired businesses	$	6,885	$	—	$	2,043	$	(5,877	)	$	3,051
Restructuring liability for Operational Excellence restructuring	$	—	$	24,916	$	—	$	(5,577	)	$	19,339
FOR THE YEAR ENDED DECEMBER 31, 2000 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts	$	4,548	$	6,844	$	1,788	$	(4,922	)	$	8,258
OTHER DEFERRED CREDITS
Reserve for decommission costs	$	9,877	$	472	$	—	$	—		$	10,349
Reorganization/restructuring liabilities of acquired businesses	$	9,857	$	—	$	654	$	(3,626	)	$	6,885
FOR THE YEAR ENDED DECEMBER 31, 1999 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS Uncollectible accounts	$	2,952	$	2,506	$	828	$	(1,738	)	$	4,548
OTHER DEFERRED CREDITS
Reserve for decommission costs	$	9,326	$	551	$	—	$	—		$	9,877
Reorganization/restructuring liabilities of acquired businesses	$	18,361	$	—	$	2,873	$	(11,377	)	$	9,857

(1): Recorded via allocation of purchase price to fair value of assets and liabilities of acquired businesses.
(2): Utilization of previously recorded balances.
(3): Reserve for purchased receivables.

Part V

Item 1. Index to Exhibits

Exhibit Number		Description of Document
1.1**		Purchase Agreement, dated as of March 8, 2002, among NorthWestern Corporation, Credit Suisse First Boston Corporation, Barclays Capital Inc. and Morgan Stanley & Co. Incorporated as representatives of the several initial purchasers named in Schedule A thereto, related to the purchase and sale of $250,000,000 aggregate principal amount of NorthWestern Corporation's 7⁷/8% Notes due March 15, 2007 and $470,000,000 aggregate principal amount of NorthWestern Corporation's 8³/4% Notes due March 15, 2012 (filed as Exhibit 4(f)(1) to NorthWestern Corporation's Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 0-692).
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, L.L.C. (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 1, 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 February 7, 2001 (incorporated by reference to Exhibit 3(b) of NorthWestern Corporation's Annual Report on Form 10-K for the year ended December 31, 2000, Commission File No. 0-692).
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 September 1, 1995, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit (4)(a)(5) of NorthWestern Corporation's Annual Report on Form 10-K for the year ended December 31, 1995, 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).
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, (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)†		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(o)†		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(p)†		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).
4.2(q)†		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(r)†		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(s)†		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(t)†		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(u)†		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).
4.3(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 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).
4.4(b)†		Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Grant County, South Dakota, related to 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 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 City of Salix, Iowa, related to 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)†		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).
4.4(f)†		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).
4.5(a)†		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, L.L.C.'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, L.L.C.'s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 001-31276).
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).
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).
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)*†		Comprehensive Employment Agreement and Investment Program for Merle D. Lewis, dated as of June 1, 2000 (incorporated by reference to Exhibit 10.1 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(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 Daniel K. Newell, dated as of March 1, 2001 (incorporated by reference to Exhibit 10.3 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)*†		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(l)*†		Comprehensive Employment Agreement and Equity Plan Participation Program for Walter A. Bradley, III, dated as of March 1, 2001 (incorporated by reference to Exhibit 10.5 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(m)*†		Comprehensive Employment Agreement and Equity Plan Participation Program for Kipp D. Orme, dated as of March 1, 2001 (incorporated by reference to Exhibit 10.6 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(n)*†		Comprehensive Employment Agreement and Equity Plan Participation Program for Eric R. Jacobsen, dated as of March 1, 2001 (incorporated by reference to Exhibit 10.7 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(o)*†		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).

10.1(p)*†		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(q)*†		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(r)*†		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).
10.2(a)†		Credit Agreement, dated as of June 10, 1999, among NorthWestern Corporation, Canadian Imperial Bank of Commerce, as agent, and the several lenders parties thereto (incorporated by reference to Exhibit 4(d) of NorthWestern Corporation's Annual Report on Form 10-K for the year ended December 31, 1999, Commission File No. 0-692).
10.2(b)**		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(c)†		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(d)†		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.)
10.3(a)**		Guaranty of certain obligations of Montana Megawatts I, LLC, dated as of September 28, 2001, furnished by NorthWestern to ABN AMRO Bank N.V. (filed as Exhibit 10(c)(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)†		Guaranty of certain obligations of CornerStone Propane Partners, L.P., dated as of November 30, 2001, furnished by NorthWestern to Credit Suisse First Boston (incorporated by reference to Exhibit 10(c)(2) of NorthWestern Corporation's Annual Report on Form 10-K/A (Amendment No. 1) for the year ended December 31, 2001, Commission File No. 0-692).

10.4(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).
10.4(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).
10.4(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).
10.5**		Registration Rights Agreement, dated as of March 13, 2002, among NorthWestern Corporation, Credit Suisse First Boston Corporation, Barclays Capital Inc. and Morgan Stanley & Co. Incorporated for the benefit of the several initial purchasers named in Schedule A to the Purchase Agreement, dated as of March 8, 2002, and the holders of the 7⁷/8% Notes due March 15, 2007 and 8³/4% Notes due March 15, 2012 (filed as Exhibit 4(f)(2) to NorthWestern Corporation's Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 0-692).
13**		Report Furnished to Security Holders—Annual Report for Fiscal Year ended December 31, 2001, furnished to shareholders of record on April 1, 2002.
21.1**		Subsidiaries of NorthWestern Corporation.
23.1***		Consent of Independent Public Accountants.
24.1**		Power of Attorney.
99.1**		Representations of Arthur Andersen LLP
99.2†		Press Release of NorthWestern Corporation. dated January 18, 2002 (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated January 18, 2002, Commission File No. 0-692).
99.3†		Press Release of NorthWestern Corporation, dated April 15, 2002 (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated April 15, 2002, Commission File No. 0-692).
99.4†		Press Release of NorthWestern Corporation, dated July 31, 2002 (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 2, 2002, Commission File No. 0-692).
99.5†		Press Release of NorthWestern Corporation, dated August 8, 2002 (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 8, 2002, Commission File No. 0-692).
99.6†		Annual Report on Form 10-K for the year ended December 31, 2001 of NorthWestern Energy LLC (incorporated by reference to the Annual Report on Form 10-K for the year ended December 31, 2001, filed with the Securities and Exchange Commission on April 1, 2002, Commission File No. 001-31276).

99.7†		Unaudited Pro Forma Combined Condensed Financial Data of The Montana Power, L.L.C. as of and for the year ended December 31, 2001 (incorporated by reference to Exhibit 99.5 of NorthWestern Corporation's Current Report on Form 8-K, dated February 15, 2002, Commission File No. 0-692).
99.8***		Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.9***		Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*: Management contract or compensatory plan or arrangement.
**: Previously filed.
***: Filed herewith.
†: Incorporated by reference.

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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Amendment No. 2 to the Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

		NORTHWESTERN CORPORATION
Dated: September 20, 2002		By:	/s/ MERLE D. LEWIS Merle D. Lewis Chairman of the Board of Directors and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Amendment No. 2 to the 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/ MERLE D. LEWIS Merle D. Lewis	Chief Executive Officer and Chairman of the Board	September 20, 2002
* Richard R. Hylland	President, Chief Operating Officer and Director	September 20, 2002
* Kipp D. Orme	Vice President and Chief Financial Officer	September 20, 2002
* Kurt D. Whitesel	Controller and Treasurer	September 20, 2002
* Jerry W. Johnson	Director	September 20, 2002
* Larry F. Ness	Director	September 20, 2002
* Marilyn R. Seymann	Director	September 20, 2002

* Randy G. Darcy	Director	September 20, 2002
* Gary G. Drook	Director	September 20, 2002
* Bruce I. Smith	Director	September 20, 2002
Lionel L. Nowell III (elected to the Board of directors on August 7, 2002)	Director

*By:

/s/ MERLE D. LEWIS

Merle D. Lewis
Attorney-in-Fact

I, Merle D. Lewis, certify that:

1.: I have reviewed this annual report on Form 10-K/A of NorthWestern Corporation;
2.: Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.: Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

Date: September 20, 2002

/s/ MERLE D. LEWIS

Merle D. Lewis

I, Kipp D. Orme, certify that:

1.: I have reviewed this annual report on Form 10-K/A of NorthWestern Corporation;
2.: Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.: Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

Date: September 20, 2002

/s/ KIPP D. ORME

Kipp D. Orme

EXPLANATORY NOTE REGARDING CERTIFICATIONS: Representations 4, 5 and 6 of the Certifications as set forth in Item 14 of the Form 10-K General Instructions have been omitted, consistent with the Transition Provisions of SEC Exchange Act Release No. 34-46427, because this Annual Report on Form 10-K covers a period ending before the Effective Date of Rules 13a-14 and 15d-14.

INDEX TO FINANCIAL STATEMENTS

		Page
Report of independent public accountants		F-2
Consolidated statements of income for the years ended December 31, 2001, 2000 and 1999		F-3
Consolidated statements of cash flows for the years ended December 31, 2001, 2000 and 1999		F-4
Consolidated balance sheets as of December 31, 2001 and 2000		F-5
Consolidated statements of shareholders' equity for the years ended December 31, 2001, 2000 and 1999		F-6
Notes to consolidated financial statements		F-7

F-1

This report is a copy of a previously issued Arthur Andersen LLP report and has not been reissued by Arthur Andersen LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of NorthWestern Corporation:

We have audited the accompanying consolidated balance sheets of NORTHWESTERN CORPORATION (a Delaware corporation) AND SUBSIDIARIES as of December 31, 2001 and 2000, and the related consolidated statements of income, cash flows and shareholders' equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Corporation's 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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, the financial statements referred to above present fairly, in all material respects, the financial position of NorthWestern Corporation and Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

As discussed in Note 1 to the consolidated financial statements, NorthWestern Corporation adopted the provisions of Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities, effective July 1, 2000.

As discussed in Note 4, the consolidated financial statements have been revised to reflect the Corporation's interest in CornerStone Propane Partners, LP as a discontinued operation.

/s/ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
May 16, 2002

F-2

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF INCOME

	YEAR ENDED DECEMBER 31
	2001			2000			1999
	(in thousands except per share amounts)

OPERATING REVENUES	$	1,723,978		$	1,709,474		$	757,940
COST OF SALES		1,069,356			1,100,484			429,051

GROSS MARGIN		654,622			608,990			328,889

OPERATING EXPENSES
Selling, general and administrative		642,379			536,437			250,858
Depreciation		41,036			32,762			23,015
Amortization of goodwill and other intangibles		43,161			35,481			11,485
Restructuring charge		24,916			—			—

		751,492			604,681			285,358

INCOME (LOSS) FROM CONTINUING OPERATIONS		(96,870	)		4,310			43,531
Interest Expense		(49,248	)		(37,982	)		(20,978	)
Investment Income and Other		8,023			8,981			9,800

Income (Loss) From Continuing Operations Before Income Taxes and Minority Interests		(138,095	)		(24,691	)		32,353
Benefit (Provision) for Income Taxes		42,470			6,467			(13,145	)

Income (Loss) From Continuing Operations Before Minority Interests		(95,625	)		(18,224	)		19,208
Minority Interests in Net Loss of Consolidated Subsidiaries		141,448			67,820			24,788

Income From Continuing Operations		45,823			49,596			43,996
Discontinued Operations, Net of Taxes and Minority Interests		(1,291	)		(43	)		667

Net Income		44,532			49,553			44,663
Minority Interests on Preferred Securities of Subsidiary Trusts		(6,827	)		(6,601	)		(6,601	)
Dividends on Preferred Stock		(191	)		(191	)		(191	)

Earnings on Common Stock	$	37,514		$	42,761		$	37,871

Average Common Shares Outstanding		24,390			23,141			23,094
Basic Earnings per Average Common Share:
Continuing operations	$	1.59		$	1.85		$	1.61
Discontinued operations		(.05	)		—			.03

Basic	$	1.54		$	1.85		$	1.64

Diluted Earnings per Average Common Share:
Continuing operations	$	1.58		$	1.83		$	1.59
Discontinued operations		(.05	)		—			.03

Diluted	$	1.53		$	1.83		$	1.62

Dividends Declared per Average Common Share	$	1.21		$	1.13		$	1.05

See Notes to Consolidated Financial Statements

F-3

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

				YEARS ENDED DECEMBER 31
				2001			2000			1999
				(in thousands)
Operating Activities:
	Net Income			$	44,532		$	49,553		$	44,663
	Items not affecting cash:
		Depreciation			41,036			32,762			23,015
		Amortization			43,161			35,481			11,485
		Deferred income taxes			(33,661	)		1,877			(10,913	)
		Minority interests in net losses of consolidated subsidiaries			(141,448	)		(67,821	)		(24,788	)
	Changes in current assets and liabilities, net of acquisitions:
		Accounts receivable			20,325			(142,328	)		(1,887	)
		Inventories			(15,989	)		(15,293	)		(26,507	)
		Other current assets			(19,046	)		(7,294	)		38,422
		Accounts payable			50,965			138,247			8,284
		Accrued expenses			63,535			96,812			(29,990	)
	Change in net assets of discontinued operations				32,318			(69,994	)		7,510
	Other, net				(172	)		(17,269	)		30,919

			Cash flows provided by operating activities		85,556			34,734			70,213

	Investment Activities:
		Property, plant, and equipment additions			(34,959	)		(28,988	)		(24,864	)
		Sale of noncurrent investments and assets, net			(433	)		2,873			37,524
		Acquisitions and growth expenditures			(147,665	)		(137,736	)		(141,833	)

			Cash flows used in investing activities		(183,057	)		(163,851	)		(129,173	)

	Financing Activities:
		Dividends on common and preferred stock			(29,956	)		(26,312	)		(24,447	)
		Minority interest on preferred securities of subsidiary trusts			(6,827	)		(6,601	)		(6,601	)
		Proceeds from issuance of common stock and common units			74,868			—			—
		Proceeds from exercise of warrants			—			182			1,657
		Issuance of long term debt			—			149,625			—
		Repayment of long-term debt			(5,000	)		(5,000	)		(5,000	)
		Line of credit borrowings, net			16,931			53,300			58,000
		Issuance of preferred securities of subsidiary trusts			96,833			—			—
		Subsidiary repurchase of minority interests			(57,768	)		(20,773	)		(7,669	)
		Line of credit (repayments) borrowings of subsidiaries, net			(35,528	)		21,670			28,010
		Issuance of nonrecourse subsidiary debt			2,884			16,377			110
		Repayment of nonrecourse subsidiary debt			(18,766	)		(6,816	)		(2,025	)
		Short-term borrowings of subsidiaries, net			53,603			(14,700	)		14,700
		Commercial paper (repayments) borrowings, net			—			(11,000	)		11,000

			Cash flows provided by financing activities		91,274			149,952			67,735

	Increase (Decrease) in Cash and Cash Equivalents				(6,227	)		20,835			8,775
	Cash and Cash Equivalents, beginning of period				43,385			22,550			13,775

	Cash and Cash Equivalents, end of period			$	37,158		$	43,385		$	22,550

See Notes to Consolidated Financial Statements

F-4

NORTHWESTERN CORPORATION
CONSOLIDATED BALANCE SHEETS

		December 31,
		2001			2000
		(in thousands)
ASSETS
Current Assets:
	Cash and cash equivalents	$	37,158		$	43,385
	Accounts receivable, net		260,486			277,235
	Inventories		79,719			63,465
	Other		69,486			50,764
	Current assets of discontinued operations		181,697			566,142

Total current assets			628,546			1,000,991

Property, Plant, and Equipment, Net			496,241			359,506
Goodwill and Other Intangible Assets, Net			640,590			669,511
Other:
	Investments		62,959			63,472
	Deferred tax asset		17,374			—
	Other assets		93,828			73,923
	Noncurrent assets of discontinued operations		695,197			730,667

Total assets		$	2,634,735		$	2,898,070

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
	Current maturities of long-term debt	$	155,000		$	5,000
	Current maturities of long-term debt of subsidiaries- nonrecourse		22,817			44,207
	Short-term debt of subsidiaries — nonrecourse		178,628			—
	Accounts payable		122,266			193,151
	Accrued expenses		216,345			168,449
	Current liabilities of discontinued operations		230,070			549,870

Total current liabilities			925,126			960,677

Long-term Debt			373,350			507,650
Long-term Debt of Subsidiaries — nonrecourse			37,999			76,058
Deferred Income Taxes			—			17,408
Other Noncurrent Liabilities			75,040			59,524
Noncurrent Liabilities and Minority Interests of Discontinued Operations			605,325			673,122

Total liabilities			2,016,840			2,294,439

Commitments and Contingencies (Notes 2, 7, 8, 15)
Minority Interests			30,067			192,832
Preferred Stock, Preference Stock, and Preferred Securities:
	Preferred stock — 4¹/2% series		2,600			2,600
	Redeemable preferred stock — 6¹/2% series		1,150			1,150
	Preference stock		—			—
	Corporation obligated mandatorily redeemable preferred securities of subsidiary trusts		187,500			87,500

Total preferred stock, preference stock and preferred securities			191,250			91,250

Shareholders' Equity:
	Common stock, par value $1.75; authorized 50,000,000 shares; issued and outstanding 27,396,762 and 23,411,333		47,942			40,968
	Paid-in capital		240,797			165,932
	Treasury stock, 155,943 shares at cost		(3,681	)		—
	Retained earnings		112,307			111,355
	Accumulated other comprehensive income (loss)		(787	)		1,294

Total shareholders' equity			396,578			319,549

Total liabilities and shareholders' equity		$	2,634,735		$	2,898,070

See Notes to Consolidated Financial Statements

F-5

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

	Number of Common Shares	Number of Treasury Shares	Common Stock		Paid in Captial		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders' Equity
	(in thousands)
Balance at December 31, 1998	23,017	—	$	40,279	$	158,530	$	—		$	81,100		$	2,225		$	282,134
Comprehensive Income:
Net income	—	—		—		—		—			44,663			—			44,663
Other comprehensive income (loss), net of tax:
Unrealized gain on marketable securities net of reclassification adjustment	—	—		—		—		—			—			2,965			2,965
Exercise of warrants	92	—		159		1,498		—			—			—			1,657
Distributions on minority interests in preferred securities of subsidiary trusts	—	—		—		—		—			(6,601	)		—			(6,601	)
Dividends on preferred stock	—	—		—		—		—			(191	)		—			(191	)
Dividends on common stock	—	—		—		—		—			(24,256	)		—			(24,256	)

Balance at December 31, 1999	23,109	—		40,438		160,028		—			94,715			5,190			300,371
Comprehensive Income:
Net income	—	—		—		—		—			49,553			—			49,553
Other comprehensive income (loss), net of tax:
Unrealized loss on marketable securities net of reclassification adjustment	—	—		—		—		—			—			(3,896	)		(3,896	)
Issuances of common stock	292	—		512		5,740		—			—			—			6,252
Proceeds from exercise of warrants	10	—		18		164		—			—			—			182
Distributions on minority interests in preferred securities of subsidiary trusts	—	—		—		—		—			(6,601	)		—			(6,601	)
Dividends on preferred stock	—	—		—		—		—			(191	)		—			(191	)
Dividends on common stock	—	—		—		—		—			(26,121	)		—			(26,121	)

Balance at December 31, 2000	23,411	—		40,968		165,932		—			111,355			1,294			319,549
Comprehensive Income:
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
Purchases of treasury stock	—	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

See Notes to Consolidated Financial Statements

F-6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

Nature of Operations

NorthWestern Corporation ("Corporation") is a service and solutions company providing integrated energy, communications, air conditioning, heating, ventilating, plumbing and related services and solutions to residential and business customers throughout North America. A division of the Corporation is engaged in the regulated energy business of production, purchase, transmission, distribution and sale of electricity and the delivery of natural gas to customers located in the upper Midwest region of the United States. The Corporation has investments in Expanets, Inc. ("Expanets"), a national provider of integrated communications, data solutions and network services to business customers; Blue Dot Services Inc. ("Blue Dot"), a national provider of heating, ventilating, air conditioning, plumbing and related services ("HVAC") and CornerStone Propane Partners, L.P. ("CornerStone"), a publicly traded Delaware master limited partnership, formed to engage in the retail propane and wholesale energy-related commodities distribution business throughout North America. CornerStone has announced it has retained Credit Suisse First Boston Corporation to pursue the possible sale or merger of CornerStone.

Basis of Consolidation

The accompanying consolidated financial statements include the accounts of the Corporation and all wholly and majority-owned or controlled subsidiaries. The financial statements of Expanets, Blue Dot and CornerStone are included in the accompanying consolidated financial statements by virtue of the voting and control rights, and therefore included in referencing to "subsidiaries." (see Note 2, Business Combinations and Acquisitions. All significant intercompany balances and transactions have been eliminated from the consolidated financial statements. The operations of CornerStone and the Corporation's interest in CornerStone have been reflected in the consolidated financial statements as Discontinued Operations (see Note 4 for further discussion).

Minority Interests in Consolidated Subsidiaries

The income or loss allocable to minority interests will vary depending on the underlying profitability of the consolidated subsidiaries. Losses allocable to minority interests, which include the effect of dividends on the outstanding preferred stock owned by the Corporation and applicable allocations from the Corporation (see Related Party Transactions), are charged to minority interests. Losses are allocated to minority interests to the extent they do not exceed the minority interest in the equity capital of the subsidiary, after giving effect for any exchange agreements (see Note 2, Business Combinations and Acquisitions). Losses in excess of the minority interests are allocated to the Corporation.

Losses allocated to Minority Interests were $141.4 million, $67.8 million, and $24.8 million for the fiscal years ended December 31, 2001, 2000, and 1999, respectively. Minority Interests balances were $30.1 million and $192.8 million at December 31, 2001 and 2000, respectively. The Corporation will recognize future losses of the subsidiaries to the extent these losses exceed the Minority Interest

F-7

balance after the effect of exchange agreements, totaling $18.4 million as of December 31, 2001. Accordingly, based on the capital structures of Expanets and Blue Dot at December 31, 2001, losses in excess of $11.1 million at Expanets and all losses at Blue Dot will be allocated to the Corporation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in its consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Cash Equivalents

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

Accounts Receivable, Net

Accounts receivable are net of $11.4 million and $8.3 million of allowances for uncollectible accounts at December 31, 2001 and 2000.

Inventories

Natural gas inventories for the regulated energy business are stated at lower of cost or market, using the first-in, first-out ("FIFO") method. Materials and supplies for the regulated energy business are stated at the lower of cost or market, with cost determined using the average cost method. Inventories for Expanets consist of voice and data equipment, parts and supplies held for use in the ordinary course of business and are stated at the lower of cost (weighted average) or market. Inventories for Blue Dot consist of air conditioning units and parts and supplies held for use in the ordinary course of business and are stated at the lower of cost or market using the FIFO method.

Investments

The Corporation classifies its investments as available-for-sale in accordance with Statement of Financial Accounting Standards ("SFAS") No. 115,Accounting for Certain Investments in Debt and Equity Securities. SFAS 115 states that certain investments in debt and equity securities be reported at fair value. Investments consist primarily of short-maturity, fixed-income securities and corporate preferred and common stocks. In addition, the Corporation has investments in privately held entities and ventures and various money market and tax-exempt investment programs.

The Corporation's available-for-sale securities are classified under the provisions of SFAS 115 as follows:

	Fair Value		Cost		Unrealized Gain (Loss)
	(in thousands)
December 31, 2001
Preferred stocks	$	31,460	$	32,660	$	(1,200	)
Marketable securities		31,499		31,508		(9	)
December 31, 2000
Preferred stocks	$	36,507	$	41,110	$	(4,603	)
Marketable securities		26,965		21,667		5,298

F-8

The combined unrealized gain (loss), net of tax, at December 31, 2001 and 2000, was ($0.8 million) and $0.5 million.

The Corporation uses the specific identification method for determining the cost basis of its investments in available-for-sale securities. Realized gains and losses on its available-for-sale securities were $2.3 million, $3.2 million, and $0.6 million in 2001, 2000 and 1999.

Derivative Financial Instruments

The Corporation manages risk using derivative financial instruments for changes in natural gas supply prices, liquefied petroleum prices and interest rate fluctuations.

The Corporation uses commodity futures contracts to reduce the risk of future price fluctuations for natural gas inventories and contracts. Increases or decreases in contract values are reported as gains and losses in the Corporation's Consolidated Statements of Income.

The fair value of fixed-price commodity contracts were estimated based on market prices of natural gas covered by the contracts. The net differential between the prices in each contract and market prices for future periods has been applied to the volumes stipulated in each contract to arrive at an estimated future value. Total contracts of $4.0 million at December 31, 2001 existed with estimated future liabilities of $4.0 million.

The Corporation has entered into an interest rate swap agreement to fix the interest rate on $55.0 million of its term loan obligations of Montana Megawatts I (a wholly-owned subsidiary of the Corporation) at an average rate of 2.83% per annum. The agreement expires December 31, 2002. The differential paid or received on interest rate swap agreements is recognized as an adjustment to interest expense. Cash flows from the interest rate swap agreement are classified in cash flows from operations.

The Corporation is exposed to credit loss in the event of nonperformance by counter parties. The Corporation minimizes its credit risk on these transactions by only dealing with leading, credit-worthy financial institutions having long-term credit ratings of "A" or better and, therefore, does not anticipate nonperformance. In addition, the contracts are distributed among several financial institutions, thus minimizing credit risk concentration.

Property, Plant and Equipment

Property, plant and equipment are stated at cost less depreciation. Depreciation is computed using the straight-line method based on the estimated useful lives of the various classes of property, which range from three to 40 years. The Corporation includes 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. During 2001, 2000 and 1999, the Corporation capitalized costs for internally developed software of $60.7 million, $1.8 million and $10.3 million. Internal costs capitalized for other property, plant and equipment were $16.2 million, $8.3 million and $7.4 million.

Depreciation rates include a provision for the Corporation's 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 other noncurrent liabilities.

When property for the communications or HVAC or propane interests are retired or otherwise disposed, the cost and related accumulated depreciation is removed from the accounts, and the

F-9

resulting gain or loss is reflected in operations. No profit or loss is recognized in connection with ordinary retirements of depreciable electric and natural gas utility property. Maintenance and repairs are expensed as incurred, while replacements and betterments that extend estimated useful lives are capitalized.

Construction work in process is composed principally of costs incurred to date on the construction of a 240-megawatt natural gas-fired generation project currently under construction in Great Falls, MT. The remaining costs are for various projects underway in the regulated energy segment.

Property, plant and equipment at December 31 consisted of the following:

	2001			2000
	(in thousands)
Land and improvements	$	3,159		$	3,141
Building and improvements		57,709			59,454
Storage, distribution, transmission and generation		381,910			371,135
Construction work in process		70,025			13,342
Other equipment		249,457			134,238

		762,260			581,310
Less accumulated depreciation		(266,019	)		(221,804	)

	$	496,241		$	359,506

Goodwill and Other Intangibles

Goodwill and other intangibles consist of the following at December 31:

	2001			2000
	(in thousands)
Goodwill	$	437,292		$	412,321
Noncompete agreements		—			1,001
Other intangibles		296,269			307,118

		733,561			720,440
Less accumulated amortization		(92,971	)		(50,929	)

	$	640,590		$	669,511

The excess of the cost of businesses acquired over the fair value of all tangible and intangible assets acquired, net of liabilities assumed, has been recorded as goodwill. Other intangibles primarily consist of dealer agreements, maintenance contracts and assembled work force costs. Intangibles and goodwill are being amortized over the estimated periods benefited, which range from three to 40 years. Financing costs are amortized over the term of the applicable debt.

The Corporation's policy is to review property, goodwill and other intangible assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable as measured by the comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered impaired, the impairment recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. If such review indicates that the carrying amount is not recoverable, the Corporation's policy is to reduce the carrying amount of these assets to fair value.

F-10

Insurance Subsidiary

Risk Partners, Inc. is a wholly owned non-United States insurance subsidiary established in 2001 to insure worker's compensation, general liability and automobile liability risks. At December 31, 2001, Expanets and CornerStone were insured through Risk Partners, Inc. 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, Inc. has purchased reinsurance policies through a third-party reinsurance company to transfer a portion of the insurance risk.

Revenue Recognition

Electric and natural gas utility revenues are based on billings rendered to customers. Customers are billed monthly on a cycle basis. Communications and HVAC revenue is recognized as services are performed and products are shipped with the exception of maintenance, construction, and installation contracts. Maintenance contract revenues are recognized over the life of the respective contracts.

Construction and installation contract revenue is recognized on the percentage-of-completion method, under which the amount of contract revenue recognizable at any given time during a contract is determined by multiplying the total estimated contract costs incurred at any given time to total estimated contract costs. Accordingly, contract revenues recognized in the statement of operations can and usually do differ from the amounts that can be billed or invoiced to the customer at any given point during the contract.

Changes in contract performance, conditions, estimated profitability, and final contract settlements may result in revisions to estimated costs and, therefore, revenues. Such revisions are frequently based on estimates and subjective assessments. The effects of theses revisions are recognized in the period in which the revisions are determined. When such revisions lead to a conclusion that a loss will be recognized on the contract, the full amount of the estimated ultimate loss is recognized in the period such conclusion is reached, regardless of what stage of completion the contract has reached. Depending on the size of a particular contract, variations from estimated project costs could have significant impact on operating results.

Income Taxes

Deferred income taxes relate primarily to the difference between book and tax methods of depreciating property, the difference in the recognition of revenues 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 carryforwards.

For book purposes, deferred investment tax credits are being amortized as a reduction of income tax expense over the useful lives of the property which generated the credits.

Regulatory Assets and Liabilities

The regulated operations of the Corporation are subject to the provisions of SFAS No. 71,Accounting for the Effects of Certain Types of Regulations. 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.

F-11

If all or a separable portion of the Corporation's 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, the Corporation would determine any impairment to the carrying costs of deregulated plant and inventory assets.

New Accounting Standards

SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments imbedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The Corporation adopted the provisions of SFAS No. 133, as amended, effective July 1, 2000, consistent with the timing of CornerStone's adoption of SFAS No. 133. The initial adoption of SFAS No. 133 at CornerStone resulted in a charge of $5.3 million and is reflected in the consolidated statements of income within the Discontinued Operations line item net of taxes of $0.5 million and net of minority interest of $3.8 million. Propane related and natural gas commodity pricing gains relating to the change in derivatives' fair value since the date of adoption total $0.2 million and $0.3 million for the years ended December 31, 2001 and 2000.

In evaluating the requirements of Staff Accounting Bulletin No. 101, an adjustment for certain activities of CornerStone was required. Certain natural gas and crude oil activities were recorded on a one-month-lag basis as sufficient information was not available to recognize current month activity. In connection with the implementation of improved information systems and because of the increase in these activities, CornerStone began to recognize such activities in the month in which they occurred, beginning with the quarter ended December 31, 2000. Accordingly, additional revenue and accounts receivable of $321.1 million, cost of sales and accounts payable of $319.3 million and gross margin of $1.8 million were recorded in the fourth quarter of 2000.

SFAS No. 141,Business Combinations, issued in June 2001, requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. In addition, it requires that all identifiable intangible assets be separately recognized and the purchase price allocated accordingly, which will result in the recognition, in some instances, of substantially more categories of intangibles.

SFAS No. 142,Goodwill and Other Intangible Assets, was also issued in June 2001 and eliminates amortization of goodwill and allows amortization of other intangibles only if the assets have a finite, determinable life. At adoption, and at least annually thereafter, companies must also perform an impairment analysis of intangible assets at the reporting unit level, to determine whether the carrying value exceeds the fair value of the assets. In instances where the carrying value is less than the fair value of the asset, an impairment loss must be recognized. Subsequent reversal of a previously recognized impairment loss is prohibited. SFAS No. 142 is effective for all fiscal years beginning after December 15, 2001, with early application permitted in some instances for entities with fiscal years beginning after March 15, 2001. CornerStone adopted the provisions of SFAS No. 142 effective July 1, 2001 and the initial impairment assessment is that there is no impairment associated with adoption. CornerStone's amortization expense for the six-month period ended December 31, 2001 was reduced by approximately $4.0 million, but the effect of this reduction and all other impacts of CornerStone's adoption of SFAS No. 142 have been fully reversed in the Corporation's financial statements since the Corporation will adopt SFAS No. 142 effective January 1, 2002. The Corporation is currently in the process of evaluating the impact of SFAS No. 142 on all reporting units. Amortization of goodwill

F-12

totaled $11.3 million, $9.8 million and $7.0 million for the years ended December 31, 2001, 2000 and 1999, respectively, excluding CornerStone.

The following table presents a reconciliation of net income and earnings per share adjusted for the exclusion of goodwill amortization, net of taxes and minority interests:

	2001		2000		1999
Reported earnings on common stock	$	37,514	$	42,761	$	37,871
Add: Goodwill amortization, net of taxes and minority interests		8,619		6,271		20

Adjusted net income	$	46,133	$	49,032	$	37,891

Basic earnings per share	$	1.54	$	1.85	$	1.64
Add: Goodwill amortization, net of taxes and minority interests		0.35		0.27		—

Adjusted basic earnings per share	$	1.89	$	2.12	$	1.64

Diluted earnings per share	$	1.53	$	1.83	$	1.62
Add: Goodwill amortization, net of taxes and minority interests		0.36		0.27		—

Adjusted diluted earnings per share	$	1.89	$	2.10	$	1.62

SFAS No. 143,Accounting for Asset Retirement Obligations, was issued in August 2001 and addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002 and the impact on the Corporation's results of operations and financial position is currently under review by management.

SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, was issued in October 2001 and establishes a single accounting model for long-lived assets to be disposed of by sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001 and management is currently evaluating the impact of the Statement on the Corporation's results of operations and financial position.

Related Party Transactions

The Corporation provides certain services to its subsidiaries, including insurance, administrative support for employee benefits, transaction structuring, financial analysis and information technology. These services are provided under arrangements that include reimbursements for certain costs (primarily salaries) under terms that approximately reflect the Corporation's actual costs. These fees were $15.2 million and $11.5 million in 2001 and 2000 with no fees charged in 1999.

The Chief Executive Officer for Qwest Cyber.Solutions ("QCS") was also a director of the Corporation in 2001. During that year, Expanets entered into an agreement with QCS, following a competitive bidding process, in which QCS was the lowest qualifying bidder, to provide application hosting services, consisting of computer servers and related support services. The five-year agreement is currently valued at approximately $52.7 million for services to be provided throughout the agreement term. In order to accept a position as Chief Executive Officer of NorthWestern Communications Group, our newly formed subsidiary, the director resigned from his position at QCS and from his position on the Corporation's board in 2002.

F-13

Reclassifications

Certain 1999 and 2000 amounts have been reclassified to conform to the 2001 presentation. Such reclassifications had no impact on net income or shareholders' equity as previously reported.

Supplemental Cash Flow Information

		2001		2000		1999
		(in thousands)
Cash paid for
	Income taxes	$	7,297	$	7,306	$	24,020
	Interest		55,648		39,937		20,649
Noncash transactions for
	Exchange of warrants for common stock		6,797		—		—
	Issuance of restricted stock		760		—		—
	Issuance of common stock for acquisitions and repurchases of subsidiary stock		—		6,252		—
	Assets acquired in exchange for current liabilities and debt		21,712		65,118		338
	Subsidiary stock issued to third parties for acquisitions, debt, earn-outs and notes receivable		28,738		176,252		41,852
	Inventory purchased using short-term debt		125,000		—		—

2. Business Combinations and Acquisitions

Expanets

On March 31, 2000, Expanets acquired a portion of Lucent Technologies' Growing and Emerging Markets division. As part of the purchase, Lucent received $145.0 million in junior convertible preferred stock in Expanets, which is subordinated to the Corporation's preferred stock investment and ispari passu with Expanets common stock. The purchase price also included $64.0 million in cash, a $15.0 million convertible note and a $35.0 million nonrecourse subordinated note. As of December 31, 2001, the $15.0 million convertible note had been converted to Expanets junior convertible Series D preferred stock.

At December 31, 2001, Expanets had 152 operational centers located across the United States. The Corporation's investment in Expanets at December 31, 2001, consisted of $313.6 million of 12% coupon convertible and nonconvertible mandatorily redeemable Preferred Stock and $0.5 million of convertible Class B Common Stock. As of December 31, 2001, the Corporation's Class B Common Stock of Expanets was convertible into 40% of the originally issued Class A Common Stock equivalents of Expanets, which comprise all of the shares of Class A Common Stock ever issued, plus the shares of Class A Common Stock issuable upon the conversion of the other Common Stock of Expanets and the Preferred Stock of Expanets held by Avaya. In addition, two of the series of our Preferred Stock of Expanets are convertible into shares of Class A Common Stock from time to time at our option and are redeemable at our option prior to an initial public offering or sale of Expanets and two other of the series of our Preferred Stock of Expanets are mandatorily redeemable upon an initial public offering or sale of Expanets. All of the other outstanding Preferred and Common Stock of Expanets held by third parties will be automatically converted into shares of Class A Common Stock upon an initial public offering or sale of Expanets. The aggregate percentage of Class A Common Stock of Expanets into which our holdings of Common and Preferred Stock is convertible is approximately 50% of the Class A Common Stock of Expanets on a fully-diluted basis, assuming the conversion of all other outstanding convertible securities of Expanets, other than employee options, based on the originally

F-14

issued value of the Class A Common Stock of Expanets. The Corporation controlled approximately 99.2% of the total voting power of Expanets' issued and outstanding capital stock as of December 31, 2001.

Blue Dot

At December 31, 2001, Blue Dot had acquired 91 companies in 29 states. The Corporation's investment in Blue Dot at December 31, 2001, consisted of $329.4 million of 11% coupon Preferred Stock and $0.5 million of convertible Class B Common Stock. As of December 31, 2001, the Corporation's Class B Common Stock of Blue Dot was convertible into approximately 40% of the originally issued Class A Common Stock equivalents of Blue Dot, which comprise all of the shares of Class A Common Stock ever issued, plus the shares of Class A Common Stock issuable upon the conversion of the Class B Common Stock of Blue Dot. The series of our Preferred Stock of Blue Dot is mandatorily redeemable upon an initial public offering of Blue Dot. The other outstanding series of Preferred Stock of Blue Dot held by third parties will be automatically converted into shares of Class A Common Stock upon an initial public offering of Blue Dot and Blue Dot has entered into agreements with the holders of the other outstanding class of Common Stock of Blue Dot for the conversion of such Common Stock into Class A Common Stock upon an initial public offering. The aggregate percentage of Class A Common Stock of Blue Dot into which our holdings of Blue Dot Common Stock is convertible is approximately 36% of the Class A Common Stock of Blue Dot on a fully-diluted basis assuming the conversion of all other outstanding convertible securities of Blue Dot, based on the originally issued value of the Class A Common Stock of Blue Dot. The Corporation controlled approximately 96.7% of the total voting power of Blue Dot's issued and outstanding capital stock as of December 31, 2001.

Cornerstone

At December 31, 2001, CornerStone's capital consisted of 17,293,340 Common Units, 6,597,619 Subordinated Units representing limited partner interests, a 2% aggregate general partner interest and approximately 676,000 warrants to purchase Common Units. At December 31, 2001, the Corporation's wholly and majority-owned subsidiaries owned all 6,597,619 Subordinated Units, 379,438 Common Units, all outstanding warrants and the entire general partner interest in CornerStone, for a combined approximate 30% effective interest. See Note 4 for further discussion.

The Montana Power Company

On October 2, 2000, the Corporation announced it had entered into a definitive agreement to acquire The Montana Power Company's energy distribution and transmission business.

On February 15, 2002, the Corporation completed the acquisition for $602.0 million in cash and the assumption of $488.0 million in existing Montana Power Company debt and preferred stock, net of cash received. As a result of the acquisition, the Corporation will be the provider of natural gas and electricity to more than 590,000 customers in Montana, South Dakota and Nebraska and the capacity to provide service to wider regions of the country. See Note 18 for further discussion of this transaction.

Other

Acquisitions made by Expanets and Blue Dot generally utilize a combination of cash and stock (of Expanets or Blue Dot). In connection with certain acquisitions of Expanets and Blue Dot, the sellers can elect to exchange the stock of Expanets or Blue Dot for cash at a predetermined exchange rate. Alternatively, Blue Dot, in certain circumstances, may, at its election, purchase the stock directly from the seller at the same predetermined exchange rate using their choice of cash or common stock of the

F-15

Corporation. During 2001, Expanets exchanged $20.3 million in cash for Expanets stock issued in prior acquisitions and Blue Dot exchanged $37.5 million in cash. As of December 31, 2001, exchange agreements totaling $6.0 million for Expanets and $12.4 million for Blue Dot remained outstanding and are included in Minority Interests.

The acquisitions made by Expanets and Blue Dot have been accounted for using the purchase method of accounting and, accordingly, the assets acquired and liabilities assumed have been recorded at their fair values as of the dates of acquisitions. The excess of the purchase price over the fair value of the assets acquired and liabilities assumed has been recorded as goodwill. The assets acquired and liabilities assumed in the current year acquisitions have been recorded based upon preliminary estimates of fair value as of the dates of acquisition. The Corporation does not believe the final allocation of purchase price will be materially different from preliminary allocations. Any changes to the preliminary estimates will be reflected as an adjustment to goodwill. Results of operations for these acquisitions have been included in the accompanying consolidated financial statements since the dates of acquisition. The accompanying unaudited consolidated pro forma results of operations for the years ended December 31, 2001 and 2000 give effect to the acquisitions as if such transactions had occurred at the beginning of the period:

	Unaudited
	2001		2000
	(in thousands except per share amounts)
Revenues	$	1,755,921	$	1,792,851
Net income		46,810		53,619
Diluted earnings per share		1.63		2.01

Liabilities for costs associated with the shutdown and consolidation of certain acquired facilities and severance costs at December 31, 2001 and 2000 are as follows (in thousands):

	2001		2000
Facility closing and other costs	$	2,856	$	5,830
Severance		195		1,750

	$	3,051	$	7,580

3. Restructuring Charge

The restructuring charge of $24.9 million recognized in the fourth quarter of 2001 relates to the Corporation's Operational Excellence Initiative which is targeting selling, general and administrative cost reductions of approximately $150.0 million. The Board of Directors approved this initiative in November 2001.

The following components of the restructuring charge to expense for the year ended December 31, 2001 were as follows:

	(in thousands)
Employee termination benefits	$	16,643
Facility closure costs		4,745
Other		3,528

	$	24,916

The employee-related termination benefits include severance costs for 474 employees. Facility closure costs include lease payments for remaining lease terms of unused facilities after closure as well

F-16

as any early exit costs that the Corporation is contractually liable for. Restructuring expenses of $5.6 million had been paid as of December 31, 2001. The remaining balance of $19.3 million is part of Accrued Expenses on the Consolidated Balance Sheets.

4. Discontinued Operations

On January 18, 2002, CornerStone announced that it had retained Credit Suisse First Boston Corporation to pursue the possible sale or merger of the Partnership. Accordingly, the Corporation has adopted discontinued operations accounting for its CornerStone interests. As such, the assets, liabilities and results of operations of CornerStone and those representing the Corporation's interests in CornerStone are presented as discontinued operations in the consolidated financial statements. Summary financial information is as follows (in thousands):

	December 31, 2001		December 31, 2000
Accounts receivable, net	$	121,843	$	433,205
Other current assets		59,854		132,937

Current assets of discontinued operations	$	181,697	$	566,142

Property, plant and equipment, net	$	322,126	$	336,459
Goodwill and other intangibles, net		339,058		363,524
Other noncurrent assets		34,013		30,684

Noncurrent assets of discontinued operations	$	695,197	$	730,667

Accounts payable	$	142,578	$	445,667
Other current liabilities		87,492		104,203

Current liabilities of discontinued operations	$	230,070	$	549,870

Long-term debt	$	424,524	$	430,157
Minority interests		153,245		205,172
Other noncurrent liabilities		27,556		37,793

Noncurrent liabilities and minority interest of discontinued operations	$	605,325	$	673,122

	2001			2000			1999
Revenues	$	2,513,777		$	5,422,616		$	2,246,400
Income (loss) before income taxes and minority interests		(28,297	)		(2,262	)		3,849
Income (loss) from discontinued operations, net of income taxes, minority interests and intercompany charges		(1,291	)		(43	)		667

5. Short-Term Debt

The Corporation may issue short-term debt in the form of commercial paper as interim financing for general corporate purposes. The Corporation also maintains other secured and unsecured lines of credit as described in Note 6, Long-Term Debt. At December 31, 2001, the Corporation did not have any commercial paper borrowings outstanding.

In May 2001, Expanets obtained a short-term line of credit to finance product purchases from Avaya, Inc. (successor to Lucent.) Borrowings under the line are limited to the lesser of $125.0 million or the borrowing base (75% of eligible customer accounts plus 60% of eligible inventory). $125.0 million was outstanding at December 31, 2001, bearing interest at 12% on any borrowings

F-17

outstanding greater than 45 days. The Corporation is obligated by virtue of a purchase participation obligation, to purchase up to $25.0 million of inventory and accounts upon event of default by Expanets. The line expires December 31, 2002 with scheduled interim payments.

Montana Megawatts I, LLC, a wholly owned subsidiary of the Corporation, entered into a 365-day term loan in September 2001 to finance the purchase of certain equipment and related expenses for a 240-megawatt natural gas-fired generation project currently under construction in Great Falls, Montana. The loan bears interest at LIBOR plus 1.50%. The Corporation has provided a guarantee on 50% of the borrowings outstanding (maximum of $27.5 million) on the loan. As of December 31, 2001, $53.6 million had been drawn on the loan with an effective interest rate of 4.63% and is reflected on the balance sheet as part of non-recourse short-term debt.

6. Long-Term Debt

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

	Due	2001			2000
Long-Term Debt
Senior unsecured debt—6.95%	2028	$	105,000		$	105,000
General mortgage bonds—
6.99%	2002		5,000			10,000
7.10%	2005		60,000			60,000
7.00%	2023		55,000			55,000
Pollution control obligations—
5.85%, Mercer Co., ND	2023		7,550			7,550
5.90%, Salix, IA	2023		4,000			4,000
5.90%, Grant Co., SD	2023		9,800			9,800
Bank credit facility	2003		132,000			111,300
Floating rate notes	2002		150,000			150,000
Less current maturities			(155,000	)		(5,000	)

		$	373,350		$	507,650

Substantially all of the Corporation's electric and natural gas utility plant is subject to the lien of the indentures securing its general mortgage bonds and pollution control obligations. General mortgage bonds of the Corporation may be issued in amounts limited by property, earnings and other provisions of the mortgage indenture.

The Corporation entered into an unsecured Bank Credit Facility with a group of commercial banks in June 1999. The Bank Credit Facility was amended in October 2001 to increase the available credit to $315.0 million and extend the Facility maturity date to January 1, 2003. The Bank Credit Facility is used for general corporate purposes including acquisitions. There were $132.0 million of borrowings outstanding and $115.0 million available under the Bank Credit Facility at December 31, 2001 after consideration of nonrecourse debt guaranties and borrowings outstanding. The Bank Credit Facility bears interest at a variable rate tied to a certain Eurodollar index or prime rate plus a variable margin, which depends upon the total borrowings outstanding on the Bank Credit Facility and can range from zero to 2.0%. The effective interest rate on borrowings outstanding for the year ended December 31, 2001 was 5.1% with a rate at December 31, 2001 of 3.19%. The Bank Credit Facility contains restrictive covenants, which require the Corporation to maintain a minimum net worth and a maximum debt to equity ratio. The Corporation was in compliance with all terms and covenants at December 31, 2001. The facility expires January 2003.

F-18

6. Long-Term Debt (Continued)

On September 21, 2000, the Corporation completed a private placement of $150.0 million principal amount of medium term floating rate notes. Net proceeds of $149.6 million were used to repay a portion of the debt outstanding from the Corporation's Bank Credit Facility. The notes mature September 21, 2002 and bear interest at LIBOR plus .75%. The effective interest rate on the notes for 2001 was 5.2% with a rate at December 31, 2001 of 2.65%.

The following table summarizes the long-term nonrecourse obligations of subsidiaries (in thousands):

	Due	2001			2000
Bank Credit Facility (Blue Dot)	2002	$	12,950		$	48,478
Subordinated note			23,743			35,000
Convertible promissory note			—			15,000
Other term debt	Various		24,123			21,787
Less current maturities			(22,817	)		(44,207	)

		$	37,999		$	76,058

As of December 31, 2001, Blue Dot has a Bank Credit Facility with a group of commercial banks that originally provided for advances up to $135.0 million. The Bank Credit Facility is used for working capital and to finance business acquisitions. There were $13.0 million and $48.5 million of borrowings outstanding under the Bank Credit Facility at December 31, 2001 and 2000. Under terms of the Bank Credit Facility, no additional borrowings are available at December 31, 2001. The Bank Credit Facility bears interest at a variable rate tied to certain LIBOR rate or prime rate plus a variable margin, which depends upon Blue Dot's interest coverage rates. The effective interest rate for 2001 was 8.52% with a rate at December 31, 2001 of 7.50%. The Bank Credit Facility matured in February 2002 and all borrowings under the Bank Credit Facility were repaid January 31, 2002.

The balance of other nonrecourse debt of $24.1 million and $21.8 million at December 31, 2001 and 2000 is generally comprised of debt assumed and issued in conjunction with acquisitions.

Annual scheduled consolidated retirements of long-term debt, including nonrecourse debt, during the next five years are $177.8 million in 2002, $137.3 million in 2003, $4.5 million in 2004, $86.6 million in 2005 and $1.4 million in 2006.

The Corporation and its subsidiaries expect to repay or refinance all short and long-term debt coming due in 2002 using proceeds from long-term financings expected to be completed in 2002.

7. Income Taxes

Prior to 2000, the Corporation filed separate federal income tax returns for Expanets, Blue Dot and the regulated, unregulated and corporate activities of the Corporation. In 2000, the Corporation determined that control levels for Blue Dot, as defined by the applicable tax regulations, had been met and allowed for the entity to be included in the regulated, unregulated and corporate tax return filed for the year ended December 31, 2000. For 2001, the Corporation has determined that the control levels for Expanets have been met as well and the entity will also be included in the consolidated tax return to be filed for the year ended December 31, 2001. The net operating losses identified in the tables below have a twenty-year carryforward period.

F-19

Income tax expense (benefit) for the years ended December 31 is comprised of the following (in thousands):

		2001			2000			1999
Federal income
	Current	$	(6,374	)	$	(3,749	)	$	25,236
	Deferred		(31,708	)		(2,009	)		(13,657	)
	Investment tax benefit		(535	)		(539	)		(562	)
State income tax			(3,853	)		(170	)		2,128

		$	(42,470	)	$	(6,467	)	$	13,145

The following table reconciles the Corporation's effective income tax rate to the federal statutory rate:

		2001		2000		1999
Federal statutory rate		(35.0	)%	(35.0	)%	35.0	%
	State income, net of federal benefit	(2.8	)	(4.0	)	4.0
	Amortization of investment tax credit	(0.4	)	(2.0	)	(1.0	)
	Taxable dividends from subsidiaries	—		13.0		5.0
	Nondeductible goodwill amortization	4.0		20.0		11.0
	Dividends received deduction and other investments	(0.5	)	(15.0	)	(10.0	)
	Valuation allowance	8.1		—		—
	Other, net	(4.2	)	(3.0	)	(3.4	)

		(30.8	)%	(26.0	)%	40.6	%

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

	2001			2000
Excess tax depreciation	$	(62,909	)	$	(41,653	)
Safe harbor leases		—			1,238
Regulatory assets		4,189			4,189
Regulatory liabilities		(3,138	)		(2,838	)
Unbilled revenue		2,304			7,135
Unamortized investment tax credit		2,205			2,740
Unrealized gain (loss) on investments		144			(3,464	)
Compensation accruals		8,010			2,054
Reserves and accruals		29,192			22,702
Recognition of net operating loss carryforward		48,712			—
AMT credit carryforward		1,577			—
Valuation allowance on net operating loss		(11,035	)		—
Other, net		(1,877	)		(9,511	)

	$	17,374		$	(17,408	)

F-20

8. Jointly Owned Plants

The Corporation has an ownership interest in three electric generating plants, all of which are coal fired and operated by other utility companies. The Corporation has an undivided interest in these facilities and is responsible for its proportionate share of the capital and operating costs while being entitled to its proportionate share of the power generated. The Corporation's interest in each plant is reflected in the consolidated balance sheets on a pro rata basis and its share of operating expenses is reflected in the consolidated statements of income. The participants each finance their own investment.

Information relating to the Corporation's ownership interest in these facilities at December 31, 2001, is as follows:

	Big Stone (S.D.)		Neal #4 (Iowa)		Coyote I (N.D.)
Ownership percentages		23.4%		8.7%		10.0%
Plant in service	$	48,267	$	34,441	$	47,120
Accumulated depreciation	$	29,978	$	21,518	$	25,414

9. Operating Leases

The Corporation, Expanets and Blue Dot lease office, office equipment and warehouse facilities under various long-term operating leases. At December 31, 2001, future minimum lease payments under noncancelable lease agreements are as follows (in thousands):

2002	$	23,436
2003		15,699
2004		10,764
2005		7,769
2006		4,418
Thereafter		2,406

Lease and rental expense incurred were $23.7 million, $16.5 million and $7.9 million in 2001, 2000 and 1999, respectively.

10. Team Member Benefit Plans

The Corporation maintains a noncontributory defined benefit pension plan for team members of corporate and the regulated utility division. The benefits to which a team member is entitled under the plan are derived using a formula based on the number of years of service and compensation levels, as defined. The Corporation determines the annual funding for its plan using the frozen initial liability cost method. The Corporation's annual contribution is funded in accordance with the requirements of the Employee Retirement Income Security Act. Assets of the plan consist primarily of debt and equity securities.

F-21

Following is a reconciliation of the changes in the plan's benefit obligations and fair value of assets over the two-year period ended December 31, 2001, and a statement of the funded status as of December 31 of both years:

		2001			2000
		(in thousands)
Reconciliation of Benefit Obligation
Obligation at January 1		$	46,304		$	57,549
	Service cost		780			922
	Interest cost		3,280			3,805
	Actuarial (gain) loss		2,450			(120	)
	Benefits paid		(4,642	)		(8,316	)
	Plan amendments		—			(264	)
	Settlement cost		—			(11,885	)
	Special termination benefits		—			4,613

Benefit obligation at end of year		$	48,172		$	46,304

Reconciliation of Fair Value of Plan Assets
Fair value of plan assets at January 1		$	58,438		$	84,135
	Actual return on plan assets		(4,925	)		(5,496	)
	Benefits paid		(4,642	)		(8,316	)
	Settlements		—			(11,885	)

Fair value of plan assets at end of year		$	48,871		$	58,438

Funded Status
Funded status at December 31		$	699		$	12,134
	Unrecognized transition amount		618			772
	Unrecognized net actuarial loss (gain)		3,109			(9,220	)
	Unrecognized prior service cost		1,642			2,099

Prepaid benefit cost		$	6,068		$	5,785

The following table provides the components of net periodic benefit cost for the plans for 2001, 2000 and 1999:

	2001			2000			1999
	(in thousands)
Service cost	$	780		$	922		$	1,149
Interest cost		3,280			3,805			3,682
Expected return on plan assets		(4,738	)		(6,318	)		(6,059	)
Amortization of transition obligation		155			155			155
Amortization of prior service cost		457			457			501
Amortization of net gain		(215	)		(729	)		(672	)
Special termination benefits		—			4,613			—
Settlement cost		—			(3,067	)		—

Net periodic benefit income	$	(281	)	$	(162	)	$	(1,244	)

F-22

10. Team Member Benefit Plans (Continued)

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.

The assumptions used in calculating the projected benefit obligation for 2001, 2000, and 1999 were as follows:

	2001		2000		1999
Discount rate	7.00	%	7.50	%	6.75	%
Expected rate of return on assets	8.50	%	8.50	%	8.50	%
Long-term rate of increase in compensation levels	3.50	%	3.00	%	3.00	%

During 1999, the Corporation made available to eligible team members the option to convert their pension plan benefit to a cash balance plan. Effective January 1, 2000, eligible new team members hired after December 31, 1999, are automatically enrolled in the cash balance plan as there are no new participants in the pension plan after December 31, 1999. The result of team members choosing the cash balance plan did not materially impact the Corporation's 2000 financial statements. The pension plan will continue for those eligible team members who did not elect the cash balance plan.

During 2000, the Corporation made available to select team members an early retirement window. The impact of that reduction in participants resulted in the Settlement Costs and Special Termination Benefits presented in the above table.

The Corporation, Expanets and Blue Dot provide various team member savings plans, which permit team members to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the Plans, the team member may elect to direct a percentage of their gross compensation to be contributed to the Plans. The Corporation contributes up to a maximum of 3.5% of the team member's gross compensation contributed to the Plan. Expanets contributes up to 66.67% of the first 6% of team member contributions. Blue Dot contributes 25% of the first 6% of team member contributions. Costs incurred under all of these plans were $8.0 million, $5.3 million and $2.6 million in 2001, 2000 and 1999.

The Corporation also has various supplemental retirement plans for outside directors and selected management team members. The plans are nonqualified defined benefit plans that provide for certain amounts of salary continuation in the event of death before or after retirement or certain supplemental retirement benefits in lieu of any death benefits. In addition, the Corporation provides predetermined death benefits based upon compensation to beneficiaries of eligible team members who represent a reasonable insurable risk. To minimize the overall cost of plans providing life insurance benefits, the Corporation has obtained life insurance coverage to fund the benefit obligations. Costs incurred under the plans were $4.1 million, $1.9 million and $2.1 million in 2001, 2000 and 1999.

The Corporation has a deferred compensation trust available to all team members of corporate and the regulated utility division who are participants in the team member savings plan and whose maximum elective contribution permissible under that plan could be limited by any provision of the Internal Revenue Code. Trust participants may invest contributions in common stock of the Corporation or other diversified investments available in the plan. Any investment elections in common stock are 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. Contributions by the Corporation to the plan were $64,000, $56,000 and $36,000 in 2001, 2000 and 1999.

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11. Employee Stock Ownership Plan

The Corporation provides an Employee Stock Ownership Plan ("ESOP") for full-time team members of corporate and the regulated utility division. The ESOP acquired the majority of its shares through leveraged loans from a financial institution. The ESOP is funded primarily with federal income tax savings which arise from the deductibility of dividends, as allowed by the tax laws applicable to such team member benefit plans. Active team members enrolled in the plan prior to 1989 receive annual cash dividend payments, and may voluntarily contribute back to the plan a percentage of these dividends subject to discrimination rules of the IRS and ERISA. The Corporation then contributes a matching contribution equal to two times the voluntary contribution. Any excess after payment of the match is allocated pro rata to all participants. All dividends received on unallocated shares of participants enrolling subsequent to 1989 are used to repay the loans of the leveraged loan segment of the Plan. Shares on this leveraged portion of the plan are released as principal and interest on the loans are made. Certain Corporation contributions and shares of stock acquired by the ESOP are allocated to participants' accounts in proportion to the compensation of team members during the particular year for which the allocation is made subject to certain IRS limits. At December 31, 2001 and 2000, the ESOP had an outstanding loan balance of $7.0 million and $8.0 million, respectively, which is secured by the unallocated assets of the ESOP and guarantees of future minimum debt funding payments by the Corporation to the ESOP. Costs incurred under the plan were $0.8 million in 2001 and $1.0 million each year in 2000 and 1999, respectively.

The shares held by the plan are included in the number of average shares outstanding when computing the Corporation's basic and diluted earnings per share and any dividends paid to the plan are included in the common dividend totals. The number, classification and fair value of shares held by the plan at December 31 are as follows:

	2001				2000
	Allocated		Unallocated		Allocated		Unallocated
Number of shares		677,769		387,447		653,209		451,757
Fair value	$	14,267,037	$	8,155,759	$	15,108,724	$	10,449,139

12. Regulatory Assets and Liabilities

The Corporation's regulated business prepares their financial statements in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow the Corporation to collect, or may require amounts paid back to customers in future electric and natural gas rates. The components of unamortized regulatory assets and liabilities shown on the balance sheet at December 31 were as follows (in thousands):

	Remaining Amortization Period	2001			2000
Environmental costs	1 year	$	1,100		$	2,215
Unrecovered gas costs	1 year		7,347			6,911
Investment tax credit deferrals	12 years		(6,704	)		(7,239	)
Other	1 year		(246	)		(21	)

		$	1,497		$	1,866

13. Stock Options and Warrants

Under the NorthWestern Stock Option and Incentive Plan ("Plan"), the Corporation has reserved 2,750,000 shares for issuance to officers, key team members and directors as either incentive-based options or nonqualified options. The Nominating and Compensation Committee ("Committee") of the

F-24

Corporation's 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 the Corporation's common stock at the grant date. The options expire 10 years following the date of grant and vest over a three-year period beginning in the third year. As of December 31, 2001, 72,488 options were exercisable with a weighted average exercise price of $23.11. No options were exercisable as of December 2000 or 1999. In addition, the Corporation issued 1,279,476 warrants to non employees to purchase shares of NorthWestern common stock at $18.225 per share in connection with a previous acquisition. During 2001, all of those remaining warrants were extinguished through a cashless exchange whereby holders received shares of the Corporation's common stock equivalent to the difference between the warrant price and the market price of the Corporation's common stock on the date of the exchange. 271,949 shares of common stock were issued in association with these transactions. A summary of the activity of stock options and warrants is as follows:

	Shares		Stock Options Range	Weighted
Balance December 31, 1998	225,463		23.00-24.88	23.11
Issued	449,604		21.19-26.13	25.67
Canceled	(11,000	)	26.13	26.13
Balance December 31, 1999	664,067		23.00-26.13	24.39
Issued	741,454		21.50-23.31	21.95
Canceled	(14,000	)	20.63-23.00	21.98
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

	Stock Warrants Shares
Balance December 31, 1998	1,105,158
Exercised	(90,896	)
Balance December 31, 1999	1,014,262
Exercised	(10,000	)
Balance at December 31, 2000	1,004,262
Extinguished	(1,004,262	)

Balance December 31, 2001	—

F-25

13. Stock Options and Warrants (Continued)

The Corporation follows 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 123, "Accounting for Stock-Based Compensation.' Under SFAS 123, stock options are valued at grant date using the Black-Scholes valuation model and compensation cost is recognized ratably over the vesting period. Had compensation cost for the Corporation's stock option plan been determined as prescribed by SFAS 123, the pro forma information for 2001, 2000 and 1999 would have been as follows (in thousands except per share amounts):

		2001		2000		1999
Earnings on common stock
	As reported	$	37,514	$	42,761	$	37,871
	Pro forma		36,881		42,365		37,763
Diluted earnings per share
	As reported	$	1.53	$	1.83	$	1.62
	Pro forma		1.51		1.82		1.62

The weighted-average remaining contractual life of the options outstanding at December 31, 2001 was 8.15 years. The weighted average Black-Scholes value of options granted under the stock option plan during 2001, 2000 and 1999 was $3.17, $2.95 and $2.11. The 2001 value was estimated using an expected life of eight years, 5.2% dividend yield, volatility of 18.8% and risk-free interest rate of 5.1%.

14. Earnings Per Share

Basic earnings per share is computed on the basis of the weighted average number of common shares outstanding. Diluted 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 2001, 2000 and 1999 were as follows:

		2001	2000	1999
	Basic computation	24,390,184	23,140,615	23,093,702
Dilutive effect of
	Stock options	19,364	13,770	14,000
	Stock warrants	45,760	183,396	263,704

	Diluted computation	24,455,308	23,337,781	23,371,403

Certain outstanding antidilutive options and warrants have been excluded from the earnings per share calculations. These options and warrants total 1,221,876 shares, 697,976 shares and 386,852 shares in 2001, 2000 and 1999.

15. Commitments and Contingencies

The Corporation and its subsidiaries are parties to various pending proceedings and lawsuits, but in the judgment of management, after consultation with counsel for the Corporation, the nature of such proceedings and suits and the amounts involved do not depart from the routine litigation and proceedings incident to the kinds of businesses conducted by the Corporation, and management believes that such proceedings will not result in any material adverse impact on the Corporation's financial position or results of operations.

F-26

The Corporation is subject to numerous state and federal environmental regulations. The Clean Air Act Amendments of 1990 (the Act) stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. The Corporation believes it can comply with such sulfur dioxide emission requirements at its generating plants and that it is in compliance with all presently applicable environmental protection requirements and regulations. The Corporation is also subject to other environmental statutes and regulations including matters related to former manufactured gas plant sites. No administrative or judicial proceedings involving the Corporation are now pending or known by the Corporation to be contemplated under present environmental protection requirements.

The Corporation's 1997 and 1998 federal income tax returns and Expanets' 1998 federal income tax return are under audit by the IRS. Certain state income and franchise tax returns are also under audit by various state agencies. Management believes that the final results of these audits will not have a material adverse effect on the Corporation's financial position or results of operations.

16. Capital Stock

In December 1996, the Corporation's Board of Directors declared, pursuant to a shareholders' rights plan, a dividend distribution of one Right on each outstanding share of the Corporation's 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 the Corporation's common stock or commences a tender or exchange offer that would result in ownership of 15% or more. In the event the Corporation is acquired in a merger or other business combination transaction or 50% or more of its 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 the Corporation's option at any time until any Acquiring Person has acquired 15% or more of the Corporation's common stock.

In October 2001 the Corporation 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. The Corporation also issued 33,480 shares of common stock in 2001 under a restricted stock plan with a fair value at date of issuance of $0.7 million. The stock vests over a four-year period and compensation expense is recognized ratably over the vesting period. Compensation expense for 2001 of $0.2 million has been recognized.

The Corporation is authorized to issue 1,000,000 shares of $100 par cumulative preferred stock. As of December 31, 2001 and 2000, there were 37,500 shares outstanding of which 26,000 were 4¹/2% Series and 11,500 were 6¹/2% Series. The provisions of the 6¹/2% Series stock contain a five-year put option exercisable by the holders of the securities and a 10-year redemption option exercisable by the Corporation. In any event, redemption will occur at par value. The 4¹/2% Series may be redeemed in whole or in part at the option of the Board of Directors at any time upon at least 30 days notice at $110.00 per share plus accrued dividends. In the event of involuntary dissolution, all Corporation preferred stock outstanding would have a preferential interest of $100 per share, plus accumulated dividends, before any distribution to common shareholders.

The Corporation is 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.

F-27

Treasury stock held by the Corporation represents shares held by the Corporation's deferred compensation plan (see Note 9). 155,943 shares reflected at cost were held at December 31, 2001.

17. Corporation Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

Series	Par Value		Shares	2001		2000
				(in thousands)
8.125%	$	25	1,300,000	$	32,500	$	32,500
7.2%	$	25	2,200,000		55,000		55,000
8.25%	$	25	4,000,000		100,000		—

			7,500,000	$	187,500	$	87,500

The Corporation has established three wholly owned, special-purpose business trusts, NWPS Capital Financing I, NorthWestern Capital Financing I, and NorthWestern Capital Financing II, to issue common and preferred securities and hold Subordinated Debentures that the Corporation issues. 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 the Corporation's other liabilities and rank equally with the guarantees related to the other trusts. The Corporation guarantees payment of the dividends on the preferred securities only if the Corporation has made the required interest payments on the Subordinated Debentures held by the trusts. In addition, the Corporation owns all of the common securities of each trust, equivalent to approximately 3% of the capital of each trust. Five years from the date of each issuance, the Corporation has the option of redeeming some or all of the Subordinated Debentures at 100% of their principal amount plus any accrued interest to the date of redemption. All of the Subordinated Debentures have a 30-year maturity period.

18. Events Subsequent to December 31, 2001

On January 18, 2002, CornerStone announced that, as a result of its financial performance in the December 2001 quarter, it would not be in compliance with certain covenants of its $50.0 million Bank Credit Facility. Discussions with the lenders of this Facility led to an amendment that allows continued access to funding under the Facility. However, the amendment eliminates the ability of CornerStone to make further Minimum Quarterly Distributions during the term of the Facility. Pursuant to the Partnership Agreement, the suspension of distributions under the defined Minimum Quarterly Distribution will be subject to arrearage privileges, so that no distribution will be made to the Subordinated Unitholders until the arrearages have been paid to the Common Unitholders. In addition, CornerStone announced that it had retained Credit Suisse First Boston Corporation to pursue the possible sale or merger of the Partnership. This action will be considered in conjunction with the Corporation's required adoption of SFAS No. 142,Goodwill and Other Intangible Assets, and SFAS No. 144,Impairment or Disposal of Long-Lived Assets, effective January 1, 2002. Substantially all of the Corporation's nearly $40.0 million net carrying value in CornerStone was taken as a noncash charge during the first quarter of 2002.

Under the provisions of the December 2001 trust preferred securities offering, additional shares were issued on January 15, 2002. The Corporation also issued $111.0 million in 8.1% trust preferred securities through NorthWestern Capital Financing III, a special-purpose wholly owned business trust (4.4 million shares with $25 par value.) The securities were issued under terms identical to those identified in Note 17,Corporation Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts. The proceeds were used for debt repayment and general corporate purposes.

F-28

18. Subsequent Events (Continued)

Under a credit agreement executed January 14, 2002, the Corporation entered into a credit facility for the acquisition of The Montana Power Company's (NYSE:TAA) energy distribution and transmission business. The facility is comprised of a $720.0 million term loan commitment and a $280.0 million revolving credit commitment. The facility terminates 364 days subsequent to the acquisition closing date and bears interest at a variable rate tied to a certain Eurodollar index or prime rate plus a variable margin, which can range from zero to 2.75%. Proceeds from the $720.0 million term loan commitment and $19.0 million of the swingline commitment were used for the acquisition purchase price, related acquisition fees and repayment of $102.3 million of outstanding principal, interest and fees under the current credit facility (see Note 5) which was subsequently terminated.

On February 15, 2002, the Corporation completed the acquisition of The Montana Power Company's energy distribution and transmission business for $602.0 million in cash and the assumption of $488.0 million in existing Montana Power Company debt and mandatorily redeemable preferred securities of subsidiary trusts. As a result of the acquisition, the Corporation will be the provider of natural gas and electricity to more than 590,000 customers in Montana, South Dakota and Nebraska and the capacity to provide service to wider regions of the country. For accounting convenience, due to the burden of a mid-month closing, both parties have agreed to an effective date for the sale of January 31, 2002.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of December 31, 2001. The Corporation is in the process of obtaining third-party valuations of certain intangible assets; thus, the allocation of the purchase price is subject to refinement, generally within one year of the date of acquisition and in the interim, has been allocated to goodwill. Final allocations will separate between goodwill, intangible assets subject to amortization and those that are not, useful lives and tax deductibility.

	(in thousands)
Current assets	$	219,830
Property, plant and equipment		1,111,034
Goodwill & other intangibles		7,418
Other		155,688

Total assets acquired		1,493,970

Current liabilities		168,465
Long-term debt		442,680
QUIPS		41,879
Other		300,995

Total liabilities assumed		954,019

Net assets acquired	$	539,951

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

	2001
	(Unaudited)
Revenues	$	4,895,885
Net income		74,437
Diluted earnings per share		1.68

F-29

19. Segment and Related Information

The Corporation's four principal business segments are its electric, natural gas, communications and HVAC. The "All Other" segment includes the results of service and other nonenergy-related operations, activities and assets of the corporate office, as well as any reconciling or eliminating amounts.

The accounting policies of the operating segments are the same as those described in the summary of significant accounting policies 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 the discontinued operations of CornerStone, are as follows:

2001	Total Electric and Natural Gas			Communications			HVAC			All Other			Total
Operating revenues	$	251,208		$	1,032,033		$	423,803		$	16,934		$	1,723,978
Cost of sales		142,112			648,036			267,978			11,230			1,069,356

Gross margin		109,096			383,997			155,825			5,704			654,622
Selling, general, and administrative		42,284			431,477			145,954			22,664			642,379
Depreciation		16,428			13,518			9,148			1,942			41,036
Amortization of goodwill and other intangibles		—			35,647			7,245			269			43,161
Restructuring charge		4,499			5,906			7,239			7,272			24,916

Operating income (loss)		45,885			(102,551	)		(13,761	)		(26,443	)		(96,870	)
Interest expense		(8,692	)		(17,330	)		(3,835	)		(19,391	)		(49,248	)
Investment income and other		306			683			204			6,830			8,023

Income (loss) before taxes and minority interests		37,499			(119,198	)		(17,392	)		(39,004	)		(138,095	)
Benefit (provision) for taxes		(11,857	)		32,190			3,830			18,307			42,470

Income (loss) before minority interests	$	25,642		$	(87,008	)	$	(13,562	)	$	(20,697	)	$	(95,625	)

Total assets	$	369,915		$	775,186		$	386,249		$	226,491		$	1,757,841

Maintenance capital expenditures	$	12,818		$	18,957		$	8,521		$	1,204		$	41,500

2000	Total Electric and Natural Gas			Communications			HVAC			Other All			Totals
Operating revenues	$	181,309		$	1,104,034		$	408,829		$	15,302		$	1,709,474
Cost of sales		88,156			740,553			260,975			10,800			1,100,484

Gross margin		93,153			363,481			147,854			4,502			608,990
Selling, general, and administrative		39,211			350,926			129,447			16,853			536,437
Depreciation		15,919			7,614			7,901			1,328			32,762
Amortization of goodwill and other intangibles		—			29,552			5,891			38			35,481

Operating income (loss)		38,023			(24,611	)		4,615			(13,717	)		4,310
Interest expense		(7,760	)		(4,019	)		(4,877	)		(21,326	)		(37,982	)
Investment income and other		(194	)		508			401			8,266			8,981

Income (loss) before taxes and minority interests		30,069			(28,122	)		139			(26,777	)		24,691
Benefit (provision) for taxes		(9,819	)		8,323			(2,404	)		10,367			6,467

Income (loss) before minority interests	$	20,250		$	(19,799	)	$	(2,265	)	$	(16,410	)	$	(18,224	)

Total assets	$	368,308		$	729,063		$	378,711		$	125,178		$	1,601,260

Maintenance capital expenditures	$	10,810		$	10,434		$	7,366		$	378		$	28,988

F-30

1999	Total Elextric and Natural Gas			Communications			HVAC			All Other			Total
Operating revenues	$	152,166		$	294,878		$	293,736		$	17,160		$	757,940
Cost of sales		65,511			168,888			182,190			12,462			429,051

Gross margin		86,655			125,990			111,546			4,698			328,889
Selling, general, and administrative		37,016			102,507			96,723			14,612			250,858
Depreciation		14,920			3,257			4,425			413			23,015
Amortization of goodwill and other intangibles		—			7,211			4,243			31			11,485

Operating income (loss)		34,719			13,015			6,155			(10,358	)		43,531
Interest expense		(8,790	)		(1,384	)		(1,210	)		(9,594	)		(20,978	)
Investment income and other		366			(1,016	)		691			9,759			9,800

Income (loss) before taxes and minority interests		26,295			10,615			5,636			(10,193	)		32,353
Benefit (provision) for taxes		(8,816	)		(7,129	)		(3,532	)		6,332			(13,145	)

Income (loss) before minority interests	$	17,479		$	3,486		$	2,104		$	(3,861	)	$	19,208

Total assets	$	364,673		$	324,489		$	279,140		$	101,973		$	1,070,275

Maintenance capital expenditures	$	12,813		$	3,589		$	7,763		$	699		$	24,864

	2001				2000				1999
	Electric		Natural Gas		Electric		Natural Gas		Electric		Natural Gas
Operating revenues	$	106,995	$	144,213	$	86,575	$	94,734	$	83,943	$	68,223
Cost of sales		23,052		119,060		16,782		71,374		18,456		47,055

Gross margin		83,943		25,153		69,793		23,360		65,487		21,168
Selling, general and administrative		27,734		14,550		25,397		13,814		24,722		12,294
Depreciation		13,193		3,235		12,663		3,256		12,006		2,914
Restructuring charge		3,329		1,170		—		—		—		—

Operating income	$	39,687	$	6,198	$	31,733	$	6,290	$	28,759	$	5,960

F-31

20. Quarterly Financial Data (Unaudited)

2001	First			Second			Third			Fourth
	(in thousands except per share amounts)
Operating revenues	$	477,592		$	476,846		$	398,705		$	370,835
Gross margin	$	155,144		$	188,838		$	165,597		$	145,043
Operating income (loss)*	$	(37,102	)	$	(3,235	)	$	(12,134	)	$	(19,479	)
Net income*	$	18,389		$	10,780		$	10,272		$	5,091
Average common shares outstanding		23,433			23,669			23,706			26,724
Basic earnings per average common share*+	$	.71		$	.38		$	.36		$	.12
Diluted earnings per average common share*+	$	.70		$	.38		$	.36		$	.12
Dividends per share	$	.2975		$	.2975		$	.2975		$	.3175
Stock price:
High	$	25.65		$	26.75		$	23.10		$	22.35
Low	$	21.63		$	21.75		$	20.90		$	18.25
Quarter-end close	$	24.50		$	22.40		$	22.00		$	21.05
2000

Operating revenues	$	221,359		$	506,046		$	517,244		$	464,825
Gross margin	$	88,960		$	176,244		$	182,045		$	161,741
Operating income (loss)	$	5,712		$	14,506		$	6,706		$	(22,615)
Net income	$	16,239		$	7,702		$	9,947		$	15,665
Average common shares outstanding		23,109			23,117			23,119			23,216
Basic earnings per average common share	$	.63		$	.26		$	.36		$	.60
Diluted earnings per average common share	$	.62		$	.26		$	.35		$	.60
Dividends per share	$	.2775		$	.2775		$	.2775		$	.2975
Stock price:
High	$	23.25		$	23.94		$	23.94		$	23.75
Low	$	20.63		$	21.00		$	19.13		$	19.31
Quarter-end close	$	20.63		$	23.13		$	19.50		$	23.13

*: Includes effect of a fourth quarter pretax restructuring charge of $24.9 million, or an impact of $12.1 million to net income and $.50 earnings per average common share after taxes and minority interest allocations.
+: The 2001 quarterly basic and diluted earnings per average common shares do not total to the 2001 annual basic and diluted earnings per average common shares due to the effect of common stock issuances during the year.

F-32

FIVE-YEAR FINANCIAL SUMMARY**

	2001			2000			1999			1998			1997
	(in thousands except per share and shareholders data)
Financial Results
Operating revenues	$	1,723,978		$	1,709,474		$	757,940		$	419,452		$	175,032
Gross margins		654,622			608,990			328,889			198,419			92,292
Operating expenses		751,492			604,681			285,358			154,184			56,900
Operating income		(96,870	)		4,309			43,531			44,235			35,392
Interest expense		(49,248	)		(37,982	)		(20,978	)		(15,546	)		(12,496	)
Investment income and other		8,023			8,981			9,800			5,700			11,564
Income (loss) before income taxes and minority interests		(138,095	)		(24,692	)		32,353			34,389			34,460
Benefit (provision) for income taxes		42,470			6,467			(13,145	)		(10,223	)		(9,828	)
Income before minority interests		(95,625	)		(18,225	)		19,208			24,166			24,632
Minority interests		141,448			67,821			24,788			5,315			—
Discontinued operations, net of taxes and minority interests		(1,291	)		(43	)		667			910			1,632
Net income	$	44,532		$	49,553		$	44,663		$	30,391		$	26,264
Common Stock Data
Basic earnings per share*+	$	1.54		$	1.85		$	1.64		$	1.45		$	1.31
Diluted earnings per share*+	$	1.53		$	1.83		$	1.62		$	1.44		$	1.31
Basic earnings per share from continuing operations	$	1.59		$	1.85		$	1.61		$	1.40		$	1.22
Diluted earnings per share from continuing operations	$	1.58		$	1.83		$	1.59		$	1.39		$	1.22
Average shares outstanding*:
Basic		24,390			23,141			23,094			18,660			17,843
Diluted		24,455			23,338			23,372			18,816			17,843
Dividends paid per common share*	$	1.210		$	1.130		$	1.050		$	.985		$	.933
Annual dividend rate at year end*	$	1.27		$	1.19		$	1.11		$	1.03		$	.97
Book value per share at year end*	$	16.25		$	13.79		$	13.01		$	12.26		$	9.34
Common stock price range*:
High	$	26.750		$	23.937		$	27.125		$	27.375		$	23.500
Low	$	18.250		$	19.125		$	20.625		$	20.250		$	16.938
Close	$	21.050		$	23.125		$	22.000		$	26.438		$	23.000
Price earnings ratio		13.8x			12.6x			13.6x			18.4x			17.6x
Dividend payout ratio
(from ongoing operations)+		76.6	%		61.7	%		66.0	%		70.9	%		76.5	%
Return on average common equity		10.5	%		13.8	%		13.0	%		12.1	%		14.2	%
Common shareholders at year end		10,358			10,371			10,475			10,116			8,845
Financial Position (as of December 31)
Total assets	$	2,634,735		$	2,898,070		$	1,956,761		$	1,728,474		$	1,106,123
Working capital		(296,580	)		40,314			100,193			57,739			11,844
Long-term debt, including nonrecourse debt excluding current portion		411,349			583,708			340,978			259,373			161,000
Total debt (including subsidiaries)		767,794			632,915			378,532			275,927			166,570
Shareholders' equity		396,578			319,549			300,371			282,134			166,603
Other equity		221,317			284,117			208,224			199,158			36,250
Total equity	$	617,895		$	603,666		$	508,595		$	481,292		$	202,853

*: Adjusted for the two-for-one stock split in May 1997.
+: $2.04 Basic earnings per share; $2.03 Diluted earnings per share; and 59.6% Dividend payout ratio, exclusive of 2001 restructuring charge.
**: Excludes CornerStone Propane Partners, L.P., which is treated as a discontinued operation.

F-33

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EXPLANATORY NOTE
REPORT CONTENTS
Part I
Part II
FIVE-YEAR FINANCIAL SUMMARY
Part IV
SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS NORTHWESTERN CORPORATION AND SUBSIDIARIES
Part V
SIGNATURES
INDEX TO FINANCIAL STATEMENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
NORTHWESTERN CORPORATION CONSOLIDATED STATEMENTS OF INCOME
NORTHWESTERN CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
NORTHWESTERN CORPORATION CONSOLIDATED BALANCE SHEETS
NORTHWESTERN CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FIVE-YEAR FINANCIAL SUMMARY

NorthWestern (NWE) 10-K/A2001 FY Annual report (amended)