NORTHWESTERN CORP - 10-K Annual Report

NorthWestern Corporation, doing business as Northwestern Energy, is one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 617,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923. In addition, on February 15, 2002, we acquired electricity and natural gas transmission and distribution assets and natural gas storage assets in Montana.

In 2002, our financial condition was significantly and negatively affected by the poor performance of our nonenergy businesses, in combination with our significant indebtedness. In early 2003, we unsuccessfully attempted to refinance, reduce and extend the maturities of our debt. On September 14, 2003 (the Petition Date), we filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). On October 19, 2004, the Bankruptcy Court entered an order confirming our Second Amended and Restated Plan of Reorganization (Plan) dated as of August 18, 2004 and the Plan became effective on November 1, 2004. “Predecessor Company” refers to us prior to emergence from bankruptcy (operations from January 1, 2002 through October 31, 2004). “Successor Company” refers to us after emergence from bankruptcy (operations from November 1, 2004 through December 31, 2004).

ENERGY BUSINESSES

Our utility operations are regulated primarily by the MPSC, the South Dakota Public Utilities Commission or SDPUC, the Nebraska Public Service Commission, or NPSC, and the Federal Energy Regulatory Commission, or FERC. We operate our business in five reporting segments:

· regulated electric utility operations;

· unregulated electric operations;

· regulated natural gas utility operations;

· unregulated natural gas operations;

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

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

We were incorporated in Delaware in November 1923. Our principal office is located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104 and our telephone number is (605) 978-2908. We maintain an internet site at http://www.northwesternenergy.com which contains information concerning us and our subsidiaries. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities and Exchange Act of 1934, as amended, along with our annual report to shareholders and other information related to us is available, free of charge, on this site as soon as reasonably practicable after we electronically file those documents with, or otherwise furnish them to, the Securities and Exchange Commission (SEC). Our internet Website and those of our subsidiaries and the information contained therein or connected thereto are not intended to be incorporated into this Annual Report on Form 10-K and should not be considered a part of this Annual Report on Form 10-K.

Electric Utility Operations

Services, Service Areas and Customers

Montana

Our Montana regulated electric utility business consists of an extensive electric transmission and distribution network. Our Montana service territory covers approximately 107,600 square miles, representing approximately 73% of Montana’s land area, as of December 31, 2004, and includes approximately 786,000 people according to the 2000 census. We also transmit electricity for nonregulated entities owning generation facilities, other utilities and power marketers in Montana. In 2004, by category, residential, commercial and industrial, and other sales accounted for approximately 32%, 47%, and 21% of our Montana electric utility revenue, respectively.

Our Montana electric transmission system consists of approximately 7,000 miles of transmission lines, ranging from 50 to 500 kilovolts, 260 circuit segments and 125,000 transmission poles with associated transformation and terminal facilities as of December 31, 2004, and extends throughout the western two-thirds of Montana from Colstrip in the east to Thompson Falls in the west. Our 230 kilovolt and 161 kilovolt facilities form the backbone of our Montana transmission system. Lower voltage systems, which range from 50 kilovolts to 115 kilovolts, provide for local area service needs. We also jointly own a 500 kilovolt transmission system that is part of the Colstrip Transmission System, which transfers Colstrip generation to markets within the state and west of Montana. The system has interconnections with five major nonaffiliated transmission systems located in the Western Electricity Coordinating Council area, as well as one interconnection to a system that connects with the Mid-Continent Area Power Pool region. With these interconnections, we transmit power to and from diverse interstate transmission systems, including those operated by Avista Corporation; Idaho Power Company, a division of Idacorp, Inc.; PacifiCorp; the Bonneville Power Administration; and the Western Area Power Administration.

As of December 31, 2004, we delivered electricity to approximately 310,000 customers in 187 communities and their surrounding rural areas in Montana, including Yellowstone National Park. We also delivered electricity to five rural electric cooperatives in western Montana, six rural electric cooperatives in southern Montana, and four rural electric cooperatives in central Montana as of December 31, 2004. Our Montana electric distribution system consisted of approximately 20,100 miles of overhead and underground distribution lines and approximately 335 transmission and distribution substations as of December 31, 2004.

South Dakota

We operate our regulated electric utility business in South Dakota as a vertically integrated generation, transmission and distribution utility. We serve an area in South Dakota comprised of 25 counties with a combined population of approximately 99,500 people according to the 2000 census. We provided retail electricity to more than 58,200 customers in 110 communities in South Dakota as of December 31, 2004. In 2004, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 36%, 49%, 12% and 3% of our South Dakota electric utility revenue, respectively.

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

depending on a number of factors, including the availability of excess short-term generation and the ability to sell excess power to other utilities in the power pool.

Our transmission and distribution network in South Dakota consists of approximately 3,100 miles of overhead and underground transmission and distribution lines across South Dakota as well as 120 substations as of December 31, 2004. We have interconnection and pooling arrangements with the transmission facilities of Otter Tail Power Company, a division of Otter Tail Corporation; Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.; Xcel Energy Inc.; and the Western Area Power Administration. We have emergency interconnections with the transmission facilities of East River Electric Cooperative, Inc. and West Central Electric Cooperative. These interconnection and pooling arrangements enable us to arrange purchases or sales of substantial quantities of electric power and energy with other pool members and to participate in the efficiency benefits of pool arrangements.

Competition and Demand

Although Montana customers have a choice with regard to electricity suppliers, we do not currently face material competition in the transmission and distribution of electricity within our Montana service territory. Direct competition does not presently exist within our South Dakota service territory for the supply and delivery of electricity, except with regard to certain new large load customers. The SDPUC, pursuant to the South Dakota Public Utilities Act, assigned the South Dakota service territory to us effective March 1976. Pursuant to that law, we have the exclusive right, other than as previously noted, to provide fully bundled services to all present and future electric customers within our assigned territory for so long as the service provided is adequate. There have been no allegations of inadequate service since assignment in 1976. The assignment of a service territory is perpetual under current South Dakota law.

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

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

In our Montana service territory, the total control area peak demand was approximately 1,521 megawatts, the average daily load was approximately 1,104 megawatts, and more than 8.9 million kilowatt hours were supplied to choice and default supply customers during the year ended December 31, 2004. In our South Dakota service territory, peak demand was approximately 277 megawatts, the average daily load was approximately 136 megawatts, and more than 1.1 million megawatt hours were supplied during the year ended December 31, 2004.

Electricity Supply

Montana

Pursuant to Montana law, we are obligated to provide default supply electric service to those customers who have not chosen or are unable to choose their electricity supplier. In this role, we purchase substantially all of the capacity and energy requirements for the default supply from third parties. We currently have power purchase agreements with PPL Montana for 300 megawatts of firm base-load and 150 megawatts of unit-contingent on peak energy through June 30, 2007. We also purchase power from 13 “qualifying facility” contracts that The Montana Power Company was required to enter into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 megawatts of winter peak capacity. We have secured additional contracts from Thompson River Co-gen, LLC for up to 14 megawatts of base-load coal/waste-coal supply and Tiber Montana for 5 megawatts of seasonal baseload hydro supply. These purchases account for approximately 72% of our customer load requirements on average. The remaining customer load requirements are met with market purchases. In January 2004, we submitted an Electric Default Supply Resource Procurement Plan to the MPSC, which fully details the resource requirements, analysis and identified resources to best meet current and future default supply load requirements, while mitigating market price risk. These contracted and proposed resources include conservation, baseload, gas fired dispatchable, wind and the post 2007 baseload resources. In addition, we have entered into short-term fixed price energy purchases to fulfill the default obligation and provide rate stability. For more information about our obligations as a result of deregulation in Montana during the statutory transition period, see “Utility Regulation—Montana.”

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

Consistent with the Resource Procurement Plan, in July 2004, we issued a Montana electric default supply request for proposal (RFP) for baseload, dispatchable, wind and other electric supply resources. Several resources were selected for contract negotiation and a number of these contracts were presented to the MPSC for advanced approval in a filing made on February 7, 2005. Our Colstrip Unit 4 division submitted an offer in the RFP to supply a certain amount of energy to the default supply. After being short-listed, the Colstrip Unit 4 Division and the default supply group commenced discussions regarding the ultimate terms of the supply arrangement. As a result of these discussions, the Colstrip Unit 4 Division agreed to offer the default supply 90 megawatts of unit contingent, baseload energy for a term of 11.5 years, commencing on July 1, 2007, at an average price of $35.80 per megawatt hour. Further procurement activities will continue, focusing on replacement of significant baseload contracts that expire in June 2007.

In addition to our Colstrip Unit 4 division, our affiliate, Montana Megawatts I, LLC (MMI), the owner of a partially constructed, 260 megawatt, natural gas-fired, combined-cycle electric generation facility, submitted numerous bids in response to the dispatchable component of the RFP. In November 2004, the default supply group notified MMI that one of its bids had been placed on the short list of offered products. After further discussions between MMI and the default supply group, MMI agreed to supply the default supply with approximately 240 megawatts of capacity from its Great Falls location for a term of 20 years (commencing no earlier than January 2007) at an all in cost per megawatt that was lower than the short-listed price. This resource is being processed in accordance with the affiliate transaction rules established by the MPSC. Upon completion of the affiliate transaction review, final acceptance by the default supply group, and approval of our internal energy supply board we will amend our February 7, 2005

advanced approval filing to present this affiliate transaction to the MPSC for their consideration. We can provide no assurance that this affiliate supply arrangement will be approved by the MPSC.

Prior to submission of its bids in the July 2004 RFP, MMI had been in active settlement negotiations with the MPSC, MCC, FERC staff and a FERC appointed settlement judge in an attempt to resolve documented concerns by the MPSC and MCC regarding a cost-based power sales agreement between us and MMI, which had been conditionally accepted as filed by the FERC in its October 17, 2003 order. In light of the pending MMI bids submitted in response to the RFP, the parties involved in the FERC matter agreed to defer any further negotiation until we make a decision with respect to the dispatchable component of the RFP. Assuming completion of a power sales agreement incorporating the economic terms of the MMI bid selected by us in the RFP, we would anticipate that MMI would amend its FERC filing to incorporate this negotiated power sales agreement into the ultimate FERC settlement.

South Dakota

Most of the electricity that we supply to customers in South Dakota is generated by power plants that we own jointly with unaffiliated parties. In addition, we have several wholly owned peaking/standby generating units that are installed at nine locations throughout our service territory. Details of our generating facilities are described further in the chart below. Each of the jointly owned plants is subject to a joint management structure. Except as otherwise noted, we are entitled to a proportionate share of the electricity generated in our jointly owned plants and are responsible for a proportionate share of the operating expenses, based upon our ownership interest. Most of the power allocated to us from these facilities is distributed to our South Dakota customers, although in 2004, approximately 19% of the power was sold in the wholesale market. Our facilities had a total net summer peaking capacity in 2004 of approximately 311 megawatts.

Name and Location of Plant	Fuel Source	Our Ownership Interest			Our Share of 2004 Peak Summer Demonstrated Capacity	% of Total 2004 Peak Summer Demonstrated Capacity
Big Stone Plant, located near Big Stone City in northeastern South Dakota	Sub-bituminous coal		23.4	%	106.14 megawatts		34.1	%
Coyote I Electric Generating Station, located near Beulah, North Dakota	Lignite coal		10.0	%	42.70 megawatts		13.7	%
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa	Sub-bituminous coal		8.7	%	55.91 megawatts		18.0	%
Miscellaneous combustion turbine units and small diesel units (used only during peak periods)	Combination of fuel oil and natural gas		100.0	%	106.58 megawatts		34.2	%
Total Capacity					311.33 megawatts		100.0	%

We have an agreement with MidAmerican Energy Company to supply firm capacity energy as follows during the years 2004-2006: 32 megawatts in 2004; 36 megawatts in 2005; and 40 megawatts in 2006. In addition, we are a member of the Midcontinent Area Power Pool, which is an area power pool arrangement consisting of utilities and power suppliers having transmission interconnections located in a nine-state area in the North Central region of the United States and in two Canadian provinces. The terms and conditions of the Midcontinent Area Power Pool agreement and transactions between Midcontinent Area Power Pool members are subject to the jurisdiction of the FERC.

The 2004 peak demand in our South Dakota service areas was approximately 277 megawatts, and the 2004 average daily load in South Dakota was approximately 136 megawatts. The 2004 Midcontinent Area Power Pool accredited capacity including the required 15% reserve margins was approximately 298 megawatts. We believe we have adequate supplies through our share of generation from jointly owned plants, existing supply contracts, Midcontinent Area Power Pool power swap availability, and capacity for sale in the current market to meet our power supply needs during the next few years.

We have a resource plan that includes estimates of customer usage and programs to provide for economic, reliable and timely supplies of energy. We continue to update our load forecast to identify the future electric energy needs of our customers, and we evaluate additional generating capacity requirements on an ongoing basis. This forecast shows customer peak demand growing modestly, which will result in the need to add peaking capacity in the future. However, we have adequate base-load generation capacity to meet customer supply needs in the foreseeable future.

Electricity Generation Costs

Coal was used to generate approximately 96% of the electricity utilized for South Dakota operations for the year ended December 31, 2004. Our natural gas and fuel oil peaking units provided the balance of generating capacity. We have no interests in nuclear generating plants. The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. Continuing upward pressure on coal prices, could result in modest increases in costs to our customers due to mechanisms to recover fuel adjustments in our rates. The average cost by type of fuel burned is shown below for the periods indicated:

	Cost per Million BTU for the Year Ended December 31,						Percent of 2004 Megawatt
Fuel Type	2004		2003		2002		Hours Generated
Sub-bituminous-Big Stone	$	1.47	$	1.34	$	1.24		50.76	%
Lignite-Coyote*	.77		.79		.66			20.78
Sub-bituminous-Neal	.90		.77		.80			28.4
Natural Gas	6.29		6.68		6.68			0.03
Oil	7.64		2.04		2.04			0.03

* Includes pollution control reagent.

During the year ended December 31, 2004, the average delivered cost per ton of fuel for our base-load plants was $23.45 at Big Stone, $10.73 at Coyote and $15.58 at Neal. The average cost by type of fuel burned and delivered cost per ton of fuel varies between generation facilities due to differences in transportation costs and owner purchasing power for coal supply. Changes in our fuel costs are passed on to customers through the operation of the fuel adjustment clause in our South Dakota tariffs. For a discussion of federal regulations regarding the use of coal to produce electricity, see “Utility Regulation—Environmental.” Also see “Risk Factors—Changes in commodity prices may increase our cost of producing and distributing electricity and distributing natural gas or decrease the amount we receive from selling electricity and natural gas, adversely affecting our financial performance and condition” included in Item 7 hereof.

The Big Stone facility currently burns sub-bituminous coal from the Powder River Basin supplied under contracts that continue through the end of 2007. The Coyote facility has a contract for the delivery of lignite coal that expires in 2016 and provides for an adequate fuel supply for Coyote’s estimated economic life. Neal receives sub-bituminous coal from the Powder River Basin 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 2004, approximately 3.0% of the fuel consumption at Big Stone was derived from alternative fuels.

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

We must pay fees to third parties to transmit the power generated at our Big Stone and Neal plants to our South Dakota transmission system. We have a 10-year agreement, expiring in 2011, with the Western Area Power Administration for transmission services, including transmission of electricity from Big Stone 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 number of our transmission assets that are integrated into the Western Area Power Authority’s system. In 2004, our costs for services under this contract totaled approximately $4.33 million. Our tariffs in South Dakota generally allow us to pass costs with respect to power purchased, including transmission costs from other suppliers, to our customers.

Unregulated Electric Operations

We lease a 30% share of Colstrip Unit 4, a 750 megawatt gross-capacity coal-fired power plant located in southeastern Montana. The initial term of the lease expires on December 31, 2010. In January 2005, we exercised our option to extend the lease term through December 31, 2018. This extension of the lease term is necessary to enable our Colstrip Unit 4 division to fulfill its offered 11.5 year supply arrangement with the Montana default supply. By extending the lease term, our annual lease payment remains at $32.2 million through 2010 and decreases to $14.5 million for the remainder of the lease.

A long-term coal supply contract with Western Energy Company provides the coal necessary to run the Colstrip facility. We sell our leased share of Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to Duke Energy Trading and Marketing (Duke) and to Puget Sound Energy under agreements expiring December 20, 2010. On January 23, 2004, during the period we operated under Chapter 11 protection, we entered into Amendment #2 to the Duke contract, which modified the pricing terms of the power sales arrangement to our benefit. In light of the exercise of the option to extend the term of the Colstrip 4 lease, we will have approximately 130 megawatts of merchant baseload coal capacity as of December 21, 2010. Due to the baseload nature of this capacity and the fact that the northwestern region of the United States is projected to be “short” of baseload capacity in 2010, we do not believe that we have a material financial risk arising from this merchant capacity.

Our unregulated electric operations also include the operations of the Milltown Dam, a two megawatt run of river hydroelectric generation facility located at the confluence of the Clark Fork and Blackfoot Rivers, near Missoula, Montana. The FERC-licensed Milltown Dam is owned and operated by our subsidiary, CFB, which is an exempt wholesale generator under the Federal Power Act. Energy generated from the Milltown facility is sold into the wholesale power market. No power from this facility is sold to the Montana default supply.

Natural Gas Utility Operations

Services, Service Areas and Customers

Our regulated natural gas utility operations purchase, transport, distribute and store natural gas for approximately 249,000 commercial and residential customers in Montana, South Dakota and Nebraska as

of December 31, 2004. Natural gas service generally includes fully bundled services consisting of natural gas supply and interstate pipeline transmission services and distribution services to our customers, although certain large commercial and industrial customers, as well as wholesale customers, may buy the natural gas commodity from another provider and utilize our utility’s transportation and distribution service.

Montana

We distribute natural gas to nearly 166,000 customers located in 105 Montana communities as of December 31, 2004. The MPSC does not assign service territories in Montana. However, we have nonexclusive municipal franchises to purchase, transport, distribute and store natural gas in the Montana communities we serve. The terms of the franchises vary by community, but most are for 30 to 50 years. During the next five years, two of our municipal franchises, which accounts for approximately 5,900 customers, are scheduled to expire. Our policy is to seek renewal of a franchise in the last year of its term. We also serve several smaller distribution companies that provide service to approximately 28,000 customers as of December 31, 2004. Our natural gas distribution system consists of approximately 3,600 miles of underground distribution pipelines as of December 31, 2004. We also transmit natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. We transported natural gas volumes of approximately 50 billion cubic feet in the year ended December 31, 2004. Our peak capacity was approximately 300 million cubic feet per day during the year ended December 31, 2004. Our Montana natural gas transmission system consisted of more than 2,000 miles of pipeline, which vary in diameter from two inches to 20 inches, and served more than 130 city gate stations as of December 31, 2004. We have connections in Montana with five major, nonaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, Encana and Havre Pipeline. Seven compressor sites provide more than 42,000 horsepower, capable of moving approximately 300 million cubic feet per day during the year ended December 31, 2004. In addition, we own and operate a pipeline border crossing through our wholly owned subsidiary, Canadian-Montana Pipe Line Corporation. We own and operate three working natural gas storage fields in Montana with aggregate working gas capacity of approximately 16.2 billion cubic feet and maximum aggregate daily deliverability of approximately 185 million cubic feet. We own a fourth storage field that is being depleted at approximately 0.03 million cubic feet per day with approximately 65 million cubic feet of remaining reserves as of December 31, 2004.

South Dakota and Nebraska

We provide natural gas to approximately 82,900 customers in 59 South Dakota communities and four Nebraska communities as of December 31, 2004. The state regulatory agencies in South Dakota and Nebraska do not assign service territories. We have nonexclusive municipal franchises to purchase, transport, distribute and store natural gas in the South Dakota and Nebraska communities we serve. The maximum term permitted under Nebraska law for these franchises is 25 years while the maximum term permitted under South Dakota law is 20 years. Our policy is to seek renewal of a franchise in the last year of its term. During the next five years, four of our South Dakota and Nebraska municipal franchises, which account for approximately 37,600 customers, are scheduled to expire. We have never been denied the renewal of any of these franchises. Included in the three franchises mentioned above is the City of Kearney, Nebraska. The City Council of Kearney has approved an indefinite extension of the current franchise until a new franchise ordinance can be adopted. Discussions are currently underway to finalize the grant of the franchise ordinance. We have approximately 2,100 miles of distribution gas mains in South Dakota and Nebraska as of December 31, 2004. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska, and in South Dakota provide natural gas sales to a number of large volume customers delivered through the distribution system of an unaffiliated natural gas utility company.

Competition and Demand

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

In South Dakota and Nebraska, we are subject to competition for natural gas supply. In addition, competition currently exists for commodity sales to large volume customers and for delivery in the form of system by-pass, alternative fuel sources such as propane and fuel oil and, in some cases, duplicate providers. We do not face material competition from alternative natural gas supply companies in the communities in which we serve in South Dakota and Nebraska. We are currently the largest provider of natural gas in our South Dakota service territory based on MMBTU sold. In South Dakota, we also transport natural gas for two gas-marketing firms currently serving 160 customers through our distribution systems. In Nebraska, we transport natural gas for two customers, whose supply is contracted from another gas company. We delivered approximately 6.1 million MMBTU of third-party transportation volume on our South Dakota distribution system and approximately 1.72 million MMBTU of third-party transportation volume on our Nebraska distribution system during 2004.

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 changes in natural gas prices through to our customers.

Natural Gas Supply

Like most utilities, our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts, natural gas storage services contracts and short-term market purchases. Our portfolio approach to natural gas supply enables us to maintain a diversified supply of natural gas sufficient to meet our supply requirements. We benefit from direct access to suppliers in the major natural gas producing regions in the United States, primarily the Rockies (Colorado), Mid-Continent, Panhandle (Texas/Oklahoma), Montana, and Alberta, Canada. These suppliers also provide us with market insight, which assists us in making procurement decisions.

In Montana, our natural gas supply requirements for the year ended December 31, 2004, were approximately 21.0 million MMBTU. We have contracted with several major producers and marketers with varying contract durations for natural gas supply in Montana.

Our South Dakota natural gas supply requirements for the year ended December 31, 2004, were approximately 5.1 million MMBTU. We have contracted with Tenaska Marketing Ventures, Inc. in South Dakota to manage transportation, storage and procurement of supply in order to minimize cost and price volatility to our customers.

Our Nebraska natural gas supply requirements for the year ended December 31, 2004, were approximately 5.5 million MMBTU. Our Nebraska natural gas supply, storage and pipeline requirements are fulfilled primarily through a third-party contract with ONEOK Energy Marketing and Trading, LP.

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

Unregulated Natural Gas Operations

Our subsidiary, NorthWestern Services Corporation (NSC), markets gas supply services to large volume customers, and operates, through its subsidiary, 87.5 miles of intrastate natural gas pipeline located in eastern South Dakota, which provides gas supply and distribution service to six customers. In addition, NSC also provides supply to 173 other primarily high volume customers through its pipeline capacity or release capacity of NorthWestern’s regulated gas operations and other utilities. NSC transported natural gas volumes of approximately 14.8 billion cubic feet in the year ended December 31, 2004. The peak capacity was approximately 46.2 million cubic feet per day during the year ended December 31, 2004.

In South Dakota, 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 for the large volume customers NSC serves. Natural gas is a commodity that is subject to market price fluctuations.

Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts, natural gas storage services contracts and short-term market purchases. Our natural gas supply requirements for the year ended December 31, 2004, were approximately 15.3 billion cubic feet. We have contracted with various suppliers to manage transportation, and procurement of supply in order to minimize cost and price volatility to our customers.

Employees

As of December 31, 2004, we had 1,341 employees. Of these, our Montana operations had 1,007 employees, 394 of whom were covered by collective bargaining agreements involving five unions. In addition, our South Dakota and Nebraska operations had 334 employees, 193 of whom were covered by the System Council U-26 of the IBEW. We consider our relations with employees to be good.

Utility Regulation

Electric Operations

Our utility operations are subject to various federal, state and local laws and regulations affecting businesses generally, such as laws and regulations concerning service areas, tariffs, issuances of securities, employment, occupational health and safety, protection of the environment and other matters.

Federal

We are a “public utility” within the meaning of the Federal Power Act. Accordingly, we are subject to the jurisdiction of, and regulation by, the FERC with respect to the issuance of securities, the transmission of electric energy in interstate commerce and the setting of wholesale electric rates. As such, we are

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

In April 1996, the FERC issued Order No. 888 and Order No. 889 requiring utilities to allow open use of their transmission systems by other utilities and power marketers. We and other jurisdictional utilities filed open access transmission tariffs, or OATTs, with the FERC in compliance with Order No. 888. NorthWestern Public Service and The Montana Power Company, the previous owner of our Montana operations, 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. We are a successor to The Montana Power Company’s OATTs.

In Montana, we sell transmission service across our system under terms, conditions and rates defined in our OATT, which became effective in July 1996. We are required to provide retail transmission service in Montana under tariffs for customers still receiving “bundled” service and under the OATT for “choice” customers.

In South Dakota, the FERC has approved our request for waiver of the requirements of FERC Order No. 889 as it relates to the “Standards of Conduct,” exempting us as a small public utility. Without the waiver, the “Standards of Conduct” would have required us to physically separate our transmission operations and reliability functions from our marketing and merchant functions.

In its Order No. 888, FERC first advanced the notion of independent operation of the transmission grid, and FERC continued to advance such policy change in its Order No. 2000 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. While FERC has stopped short of requiring that jurisdictional transmission owners participate in RTOs, it continues to encourage participation in such entities.

The previous owner of our Montana operations was a co-sponsor with several other transmission owners in the Pacific Northwest of a filing at the FERC that proposed to form RTO West. Since that initial filing, we have continued to participate with other transmission owners in the region in the pursuit of independent regional transmission management. The independent entity, now known as Grid West, would be a nonprofit organization with an independent board that would act as the independent system operator for the aggregated transmission systems of participating transmission owners. If Grid West is implemented and we participate, then we would execute a transmission operating agreement with the organization prior to startup of the operation. We do not anticipate that the transmission operating agreement would include any of our transmission assets other than those used in our Montana operations. The organization would not be permitted to own transmission assets pursuant to its charter, so the transmission operating agreement would not convey ownership of the assets to them but would grant them the right to operate the assets consistent with the obligation to provide services pursuant to applicable tariffs. NorthWestern Energy and other participating transmission owners would likely retain the right and obligation to maintain the facilities that Grid West has authority to operate pursuant to the transmission operating agreements. Participation in the organization would create a new commercial arrangement for the transmission of the energy we distribute in Montana, but we do not anticipate any material change in the size or timing of the

transmission-related revenue stream as a result of participation. At this time, it is uncertain when or if Grid West will begin operations.

With respect to our South Dakota transmission operations, in October 2000 we filed our Order No. 2000 Compliance Filing with the FERC detailing options we are pursuing in order to participate in an RTO. Our South Dakota transmission operations are adjacent to the Midwest Independent System Operator’s (MISO) system and are part of the Western Area Power Administration’s (WAPA) Control Area. The Coyote and Big Stone power plants, in which we are a joint owner, are connected directly to the MISO system, and we have ownership rights in the transmission lines from these plants to its distribution system. We do not intend, at this time, to participate in the MISO markets that are expected to begin operation April 1, 2005, but rather continue to utilize WAPA to handle our scheduling requirements. We have resisted the assignment of MISO costs to us (which we do not expect to be material) related to the transmission lines between the power plants and its distributions systems, and the FERC, in an initial order issued in September of 2004, supported that position. We are currently negotiating a settlement agreement with MISO and the other Big Stone and Coyote power plant joint owners related to providing MISO with the information it needs to operate its system, while exempting us from assignment of MISO operational costs.

On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, or the SMD NOPR. In April 2003, FERC issued a white paper related to the SMD NOPR, which reflected some of the comments made to FERC in the NOPR process. This paper proposed certain changes, but did not materially alter the proposed rules.

Because the SMD NOPR was hugely unpopular across vast reaches of the country, in particular the Pacific Northwest, FERC indicated that while it continues to believe that the principles embodied in the SMD NOPR represent prudent wholesale market management, it will no longer formally pursue standard market design nationwide.

On July 24, 2003, FERC issued Order No. 2003 on Standardization of Generation Interconnection Procedures and Agreements. The final rule, effective January 20, 2004, requires public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file standard procedures and a standard agreement for interconnecting generators larger than 20 MW. Subsequent to Order No. 2003, FERC issued related Orders Nos. 2003A and 2003B, which clarified and in some cases modified the original Order No. 2003. FERC believes that Order No. 2003 and its related clarifying Orders will prevent undue discrimination, preserve reliability, increase energy supply, and lower prices for customers by increasing the number and variety of new generators that will compete in the wholesale electricity market. While the Order requires that new generators fund the cost of transmission system upgrades needed to integrate their new generation, the generator will receive a credit over 20 years equal to the funding it advances for any transmission upgrades, which ultimately places the burden of the new transmission investment on us. While it is reasonable to assume that regulators will allow recovery of such investment from customers, recovery is not certain. The impact this order will have on our earnings, revenues or prices will depend on the number of new generators that interconnect to our system in the future, the extent of the transmission upgrades required by those generators, and ultimate regulatory treatment of those investments.

On November 25, 2003, FERC issued Order No. 2004 on Standards of Conduct. In Order No. 2004, FERC adopts standards of conduct that apply uniformly to interstate gas pipelines and public utilities (jointly referred to as Transmission Providers) that are currently subject to the gas and electric standards of conduct in Part 161 and Part 37 of FERC’s regulations respectively. The new standards of conduct will govern the relationship between regulated Transmission Providers and their Energy Affiliates, and they will eliminate the loop hole in the current regulations that do not cover a Transmission Provider’s

relationship with Energy Affiliates that are not marketers of merchant affiliates. We are a Transmission Provider because we are a public utility currently subject to Part 37 of FERC’s regulations. On April 9, 2004, we submitted a compliance filing under Order No. 2004 requesting the FERC to clarify and confirm that our Montana natural gas system operations do not qualify as an “Energy Affiliate” of our electric transmission operations or, in the alternative, grant us a limited waiver of the independent functioning requirements of sections 358.2 and 358.4 of the FERC’s regulations. The request for a limited waiver would allow us to (1) operate our interstate electric transmission and Montana’s intrastate natural gas distribution (and associated transmission, storage) systems in a common control center with employees trained in both areas but operating in only one discipline on any given shift, and (2) train our scheduling employees on both electric and gas systems to ensure adequate staffing during emergencies and employee vacations. In response, a September 2004 Order from FERC noted that our gas utility businesses may well qualify for an exemption under section 353(d)(6)(v), but requested additional information. We submitted a compliance filing in October 2004 in response to the FERC’s request for additional information and the FERC has not yet responded. In the meantime, we have completed training of required employees and posted on our OASIS all of the requirements for compliance with the Order.

It is possible that compliance with Order No. 2004 may require some level of reorganization of our operations. Although we cannot predict with certainty the impact Order No. 2004 may have on our earnings, revenues or prices, management believes that in the aggregate, our earnings and revenues would not be materially affected.

Our subsidiary, CFB operates the Milltown Dam, a two megawatt hydroelectric dam at the confluence of the Clark Fork and Blackfoot Rivers, under a license granted by the FERC. CFB received an extension of its FERC license to operate the dam until 2009, and is currently seeking to extend that license until 2010. Prior to CFB filing for the extension, however, CFB filed an application to amend its FERC operating license to allow for the commencement of Stage 1 of the EPA’s proposed plan for the remediation of the Milltown Reservoir superfund site. Stage 1 activities anticipated the permanent drawdown of the Milltown Reservoir and the construction of: (i) the Clark Fork River bypass channel, (ii) a railroad spur to facilitate loading of contaminated sediments to be removed from the reservoir, and (iii) certain equipment access roads. All such construction activity was to take place in FERC jurisdictional areas. On January 19, 2005, the FERC issued an order dismissing CFB’s application, and issuing a notice of intent to accept surrender of CFB’s operating license. Based on certain incorrect assumptions made by the FERC (particularly with respect to the existence of a completed and executed consent decree for the Milltown Reservoir superfund site as of the date of the order), the FERC transferred its jurisdiction over the Milltown facility to the EPA and concluded that, based on certain actions to take place during the Stage 1 activities, that such actions demonstrate CFB’s intent to surrender its operating license. Moreover, based upon the operation of Section 121(e) of CERCLA, CFB need not file a formal surrender application with the FERC. Due to the FERC’s reliance upon certain incorrect assumptions, all relevant parties to the Milltown superfund consent decree negotiations concluded that the order created certain unacceptable risks due, in large part, to the fact that a consent decree is not fully negotiated to address the rights and obligations of the various parties with respect to implementation of the Milltown remedial action and restoration plan. As a result, EPA, the State of Montana, the Atlantic Richfield Company and CFB all filed comments with the FERC on February 18, 2005, requesting that the FERC modify its order to continue jurisdiction over the Milltown facility until entry of a final consent decree.

Historically the FERC has demonstrated flexibility in granting extensions to the CFB due, in large part, to the operator’s inability to formulate future plans regarding the Milltown Dam. Generally, under FERC rules, notice of intent to renew a license must be filed five years prior to its expiration. Accordingly, CFB gave the FERC its notice to seek renewal of the license in 2004. In the event the FERC license was terminated, the FERC may require that the dam be removed. If CFB does not receive the license extension, then it might be required to relinquish the license, cease operating the dam and remove the

structures as early as 2009. Based on estimates received from our environmental consultants, management believes that the cost of such removal would be approximately $11.4 million and has been recorded in our financial statements. While the above extension practice has been followed by CFB for many years, the January 19, 2005 order moots CFB’s current extension request. Thus, absent the FERC agreeing to modify its order as requested by CFB and the relevant parties to the Milltown consent decree negotiations, CFB would lose its operating license for the Milltown facility after 45 days from the date of the FERC order. In this event, CFB would immediately appeal the FERC’s decision and take whatever action is necessary to preserve its operating license for the Milltown facility.

One of the principal legislative initiatives of the current administration is the adoption of comprehensive federal energy legislation. During 2004, the comprehensive bill lacked two votes in the Senate to pass. The energy bill, as previously proposed, would repeal the Public Utility Holding Company Act of 1935 (PUHCA), create incentives for the construction of transmission infrastructure, encourage but not mandate standardized competitive markets and expand the authority of the FERC to include overseeing the reliability of the bulk power system. We cannot predict whether comprehensive energy legislation will be adopted and, if adopted, the final form of that legislation. We would expect that comprehensive energy legislation would, if adopted, significantly affect the electric utility industry and its businesses.

Montana

Our Montana operations are subject to the jurisdiction of the MPSC with respect to electric service territorial issues, rates, terms and conditions of service, accounting records and other aspects of its operations. As a public utility, we are also subject to MPSC jurisdiction when we issue, assume, or guarantee securities, or when we create liens on our Montana properties. As such, we are required to submit annual filings of certain financial information on the MPSC Annual Report of Electric, Natural Gas, and Propane Utilities.

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

On January 31, 2002, the MPSC approved a stipulation among The Montana Power Company, us and a number of other parties, which, among other things, conclusively established the pretax net present value of the retail transition costs relating to qualifying facilities contracts recoverable in retail rates. Because the recovery stream as finalized by the stipulation is less than the total payments due under the out-of-market power purchase contracts, the difference must be mitigated or covered from other revenue sources. Qualifying Facilities Contracts, or QFs, require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our gross contractual obligation related to the QFs is approximately $1.7 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.3 billion through 2029. Upon emergence from bankruptcy, we adopted fresh-start reporting and computed the fair value of the liability to be approximately $143.8 million based on the net present value (using a 7.75% discount factor) of the difference between our obligations under the QFs and the related amount recoverable. At December 31, 2004, the liability was $143.4 million. Although we believe that we have opportunities to mitigate the impact of these differences through improved management of our obligations under these contracts and by negotiating buyouts of certain of these contracts, we cannot assure you that our actions will be successful.

Montana’s Electric Utility Restructuring Act enabled larger customers in Montana to choose their supplier of commodity electricity beginning on July 1, 1998, and provided that all other Montana customers would be able to choose their electric supplier during a transition period through June 30, 2007. Under this legislation, during this transition period, we were designated to serve as the “default supplier” for customers who have not chosen an alternate supplier. The Montana Restructuring Act provided for the full recovery of costs incurred in procuring default supply contracts during this transition period. In its 2001 session, the Montana Legislature passed House Bill 474, which, among other things, reaffirmed full cost recovery for the default supplier by mandating that the MPSC use an electric cost recovery mechanism providing for full recovery of prudently incurred electric energy supply costs and extended the transition period through June 30, 2027. In November 2002, Referendum 117 was passed, repealing HB 474 and reinstating a transition period ending on June 30, 2007. Two new electric energy bills, HB 509 and SB 247, were passed by the 2003 Montana Legislature. Collectively, these two 2003 bills establish us as the permanent default supplier, extend the transition period to June 30, 2027, require smaller customers to remain default supply customers through the transition period, and establish a specific set of requirements and procedures that guide power supply procurements and their cost recovery. Compliance with these procurement procedures should mitigate the risk of nonrecovery of our costs of acquiring electric supply.

On October 29, 2001, The Montana Power Company filed with the MPSC its initial default supply portfolio, containing a mix of long and short-term contracts from new and existing power suppliers and generators. On April 25, 2002, the MPSC approved our proposed “cost recovery mechanism” in the form filed. On June 21, 2002, the MPSC issued a final order approving contracts meeting approximately 60% of the default supply winter peak load and approximately 73% of the annual energy requirements, principally covered by PPL Montana and QF supply contracts. On January 23, 2004, NorthWestern filed with the MPSC its first biannual Electric Default Supply Resource Procurement Plan, which fulfills the requirements established by law and describes the analysis and planning we are performing on behalf of electric default supply customers to acquire a balanced, cost-effective portfolio of resources. The immediate resource needs are for the variable portion of the load. We presented a dispatchable generation contract to the MPSC, which was approved in 2004, that helps to meet these variable requirements. As discussed above, on February 7, 2005 we made a filing with the MPSC, seeking advanced approval of a wind and small baseload supply contract based upon offers received during our July 2004 RFP process. The MPSC is anticipating ruling on the proposed contract by March 31, 2005.

On June 16, 2003, we filed our annual electric supply cost tracker request with the MPSC for the 12-month period ended June 30, 2003. On July 15, 2003, an interim order was approved by MPSC for the projected electric supply cost. On June 1, 2004, we filed our annual electric supply cost tracker request with the MPSC for any unrecovered actual electric supply costs for the 24-month period ended June 30, 2004, and for projected costs for the 12-month period ended June 30, 2005. On July 28, 2004 an interim order was approved by MPSC for the projected electric supply cost.

On November 17, 2004 we filed with the MPSC for an automatic rate adjustment of $0.9 million under a Montana statute allowing the recovery of increased state and local taxes and fees. On December 29, 2004 an interim order was issued by the MPSC for $0.5 million.

For further discussion of this and related supply risks, 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 SDPUC jurisdiction with respect to electric service territorial issues, rates, terms and conditions of service, accounting records and other aspects of our operations. Under the South Dakota Public Utilities Act, a requested rate increase may be implemented 30 days after the date of its filing unless its effectiveness is suspended by the SDPUC and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the SDPUC. Our electric rate schedules provide that we may pass along to all classes of customers qualified increases or decreases in costs related to fuel used in electric generation, purchased power, energy delivery costs and ad valorem taxes.

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

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

Natural Gas Operations

Federal

FERC Order No. 636 requires that all companies with interstate natural gas pipelines separate natural gas supply and production services from interstate transportation service and underground storage services. The effect of the order was that natural gas distribution companies, such as NorthWestern, and individual customers purchase natural gas directly from producers, third parties and various gas-marketing entities and transport it through interstate pipelines. We have established transportation rates on our transmission and distribution systems to allow customers to have supply choices. Our transportation tariffs have been designed to make us economically indifferent as to whether we sell and transport natural gas or merely deliver it for the customer.

Our natural gas transportation pipelines are generally not subject to the jurisdiction of the FERC, although we are subject to state regulation. We conduct limited interstate transportation in Montana that is subject to FERC jurisdiction, but the FERC has allowed the MPSC to set the rates for this interstate service.

Montana

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

Rates for our Montana natural gas supply are set by the MPSC. We use a monthly gas tracking mechanism in Montana for the recovery of gas supply costs, which we prepare and file monthly with the MPSC. The filing sets gas cost rates based on estimated gas loads and gas costs for the upcoming tracking period and adjusts for any differences in the previous tracking year’s estimates to actual cost information.

We filed an annual gas cost tracker request in Montana in December 2001 for actual gas costs for the 12-month period ended October 31, 2001, and for projected costs for the 12-month period ended October 31, 2002. Our December 2001 request was finalized by order of the MPSC on October 10, 2002.

On November 1, 2002, we filed an annual gas cost tracker request for actual gas costs for the 12-month period ended October 31, 2002, and for projected costs for the eight-month period ended June 30, 2003. In our 2002 filing, we proposed to change the tracking year to July 1 through June 30 and therefore estimated our gas costs from November 1, 2002 through June 30, 2003. That request was finalized by order of the MPSC on July 3, 2003, with the exception of disallowing $6.2 million of our purchased gas costs as having been imprudently incurred. We filed a motion for reconsideration regarding the disallowance of purchased gas cost with the MPSC on July 14, 2003, which was denied. We filed suit in Montana state court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. At this time, this matter has been suspended pending settlement discussions.

On June 2, 2003, we filed an annual gas cost tracker request with the MPSC for the projected gas costs for the 12-month period ending June 30, 2004. The MPSC granted an interim order on July 3, 2003, for the projected gas cost adjusted for 4,200 MDKT at a fixed price of $3.50 as opposed to the market price submitted in the original filing, which was at a higher price. The interim disallowance on 4,200 MDKT at market price resulted in the undercollection of $4.6 million for the period July 1, 2003 through June 30, 2004.

On May 28, 2004, we filed an annual gas cost tracker request with the MPSC for actual gas costs for the twelve month period ended June 30, 2004, and for projected costs for the twelve month period ended June 30, 2005. On July 8, 2004 an interim order was approved by the MSPC for the projected gas cost. On December 6, 2004, we entered into a stipulation with the Montana Consumer Counsel, subject to approval by the MPSC. This stipulation settled recovery of gas costs for the 2003 and 2004 annual gas cost trackers, including recovery of the prior $4.6 million disallowance, plus interest. The MPSC conducted a hearing on this stipulation on March 10, 2005 but no action was taken.

South Dakota

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

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

Nebraska

Our natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated in the State of Nebraska by the NPSC. High volume customers are not subject to such regulation but can file complaints if they allege discriminatory treatment. Under the State Natural Gas Regulation Act, effective May 30, 2003, for a regulated natural gas utility to propose a change in rates to its regulated customers, it is required to file an application for a rate increase with the NPSC and with the communities in which it serves customers. The utility may negotiate with those communities for a settlement with regard to the rate change, or it may proceed to have the NPSC review the filing and make a determination. While the utility and the communities are negotiating a settlement, the utility can commence charging the requested rate, as interim rates subject to refund, 60 days after the filing of the increase request. If the utility and the communities are unable to reach a settlement, then the matter is

transferred to the NPSC for its review and further proceedings. The interim rates become final and no longer subject to refund if the NPSC has not taken final action within 210 days after the matter is referred to the NPSC.

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

Seasonality and Cyclicality

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

Environmental

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

We are committed to remaining in compliance with all state and federal environmental laws and regulations and taking reasonable precautions to prevent any incidents that would violate any of these rules. We did not incur any material environmental expenditures in 2004. However, 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.

The Clean Air Act Amendments of 1990, which prescribe limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants, required reductions in sulfur dioxide emissions at our Big Stone plant beginning in the year 2000. We currently satisfy this requirement through the purchase of sub-bituminous coal, which contains lower sulfur content. In 2000, the wall-fired boiler at our Neal 4 plant and the cyclone boilers located at our Big Stone and Coyote plants became subject to nitrogen oxide emission limitations. To satisfy these limits, the Neal 4 and Big Stone facilities purchase and burn sub-bituminous coal from the Powder River Basin, and the Coyote facility purchases and burns lignite coal. Low nitrogen oxide burners have been identified as additional possible control technology; however, installation of such burners has not yet been required. The Clean Air Act also contains a requirement for

future studies to determine what, if any, limitations and controls should be imposed on coal-fired boilers to control emissions of certain air toxics, including mercury. Because of the uncertain nature of the air toxic emission limits and the potential for development of more stringent emission standards in general, we cannot reasonably determine the additional costs we may incur under the Clean Air Act. Legislation has been introduced in the Congress to amend the Clean Air Act, including legislation that implements the current administration’s “Clear Skies” proposal, or would otherwise affect the regulatory programs applicable to emissions of sulfur oxide, nitrogen oxide, mercury, and possibly carbon dioxide. While EPA supports the legislative proposal, the Agency also proposed several regulatory actions which, if passed, will impact our operations regardless of Congressional action. Included in these actions is the Clean Air Mercury Rule for controlling mercury emissions from power plants, which was proposed in January 2004 and supplemented in March 2004. This proposal, like all regulatory actions, is subject to the normal administrative processes, and we cannot make any prediction about whether the proposals will pass, or the final terms of this or any other action if they were to pass.

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

We have met or exceeded the removal and disposal requirements for all equipment containing polychlorinated biphenyls, or PCBs, as required by state and federal regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

The Comprehensive Environmental Response Compensation and Liability Act, or CERCLA, and some of its state counterparts require that we remove or mitigate adverse environmental effects resulting from the disposal or release of certain substances at sites that we own or previously owned or operated, or at sites where these substances were disposed. During 2003, we engaged the services of a third-party environmental consulting firm to perform a comprehensive evaluation of our historical and current utility operations. Based upon the results of this evaluation, we increased our environmental reserve by $7.4 million in the fourth quarter of 2003. Based upon information available to our consultants at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation, however, may be subject to change as a result of the following uncertainties:

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

· Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

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

Two formerly operated manufactured gas plants located in Aberdeen and Mitchell, South Dakota, have been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System, or CERCLIS, list as contaminated with coal tar residue. We are currently investigating these sites pursuant to work plans approved by the EPA and the South Dakota Department of Environment and Natural Resources. At this time, we know that no material remediation is necessary at the Mitchell location. However, we anticipate that remediation will likely be necessary at the Aberdeen site in the future. At present, we cannot estimate with a reasonable degree of certainty the total costs of any cleanup at these South Dakota sites. However, based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and our belief that we will be able to recoup prudently incurred costs in rates, we do not expect cleanup costs at these sites to be material.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. In August 2002, the NDEQ conducted site-screening investigations at these sites for alleged soil and groundwater contamination. During 2004, the NDEQ conducted Phase 1 Environmental Site Assessments of the Kearney and Grand Island locations, using funding provided by the Targeted Brownfields Assessment Program. The NDEQ has now made recommendations for Phase 2 investigations of soil and groundwater at these two locations. The Phase 2 work will likely commence during early summer of 2005. At present, we cannot estimate with a reasonable degree of certainty whether any cleanup will be required at the Kearney and Grand Island locations. However, based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and the potential to recoup some portion of prudently incurred remediation costs in rates, we do not expect cleanup costs at these locations to be material.

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

Toxic heavy metals in the silts resting in Milltown Reservoir, which sits behind Milltown Dam, caused the EPA to identify Milltown Reservoir on its Superfund National Priority List. Atlantic Richfield, as successor to the Anaconda Company, was named as the party with responsibility for completing the remedial investigation and feasibility studies and conducting site cleanup, under the EPA’s direction. The Montana Power Company did not undertake any direct responsibility in that regard, in light of a statutory exemption from liability under CERCLA provided to the holder of the Milltown Dam license. By virtue of its acquisition of The Montana Power Company’s electric and natural gas transmission and distribution business and the Milltown Dam, CFB succeeded to similar protection under this statutory exemption. Atlantic Richfield, however, has argued that the owner of the Milltown Dam should be considered a PRP and threatened to challenge CFB’s exempt status. Atlantic Richfield and The Montana Power Company entered into a confidential settlement agreement to limit The Montana Power Company’s and now CFB’s potential liability under such a challenge and limit costs and ongoing operating expenditures, provided that the EPA selects a remedy that leaves the dam and sediments in place in its final Record of Decision.

In April 2003, the EPA announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed the removal of a material quantity of contaminated sediments residing in the Milltown Reservoir, in combination with the removal of the Milltown Dam and powerhouse. In light of this announcement, we commenced negotiations with Atlantic Richfield to prevent a challenge from Atlantic Richfield to our statutorily exempt status under CERCLA as a potentially responsible party. On September 10, 2003, we executed a confidential settlement agreement with Atlantic Richfield that, among other things, capped our maximum contribution towards remediation of the Milltown Reservoir superfund site. A motion to approve the settlement agreement with Atlantic Richfield was filed with the Bankruptcy Court on October 17, 2003. On April 7, 2004, we entered into a stipulation (Stipulation) with Atlantic Richfield, the EPA, the Department of the Interior, the State of Montana, and the Confederated Salish and Kootenai Tribes (collectively the Government Parties), which is intended to resolve both our liability with Atlantic Richfield in general accordance with the previously negotiated settlement agreement and establish a framework to resolve our liability with the Government Parties for their claims, including natural resource restoration claims, against NorthWestern and CFB as they relate to remediation of the Milltown Reservoir site. The Stipulation caps NorthWestern’s and CFB’s collective liability to Atlantic Richfield and the Government Parties at $11.4 million. On June 22, 2004, the Bankruptcy Court approved the Stipulation and the funding of the Atlantic Richfield settlement, as modified by the Stipulation. The amount of the stipulated liability has been fully accrued in the accompanying financial statements. Pursuant to the Stipulation, commencing in August 2004 and each month thereafter, we will pay $500,000 alternately into two escrow accounts, one for the State of Montana and one for Atlantic Richfield, until the total agreed amount is funded. As of December 31, 2004 we have funded $2.5 million. No interest will accrue on the unpaid balance due, and the escrow accounts will remain funded until a final, nonappealable consent decree is entered by the United States District Court. If, however, a consent decree (i) is not executed by the relevant parties, (ii) is not approved by the United States District Court, or (iii) does not become fully effective, then all funds in the escrow accounts will continue to be held in trust pending further Bankruptcy Court order. The Stipulation incorporates appropriate releases and indemnifications from Atlantic Richfield under the previously negotiated settlement agreement. There can be no assurance that the settlement set forth in the Stipulation will become effective, as the parties to this matter continue to negotiate the terms and conditions of the consent decree. In light of the material environmental risks associated with the catastrophic failure of the Milltown Dam, subsequent to our acquisition of the Montana Power Company, we secured a 10-year, $100 million environmental insurance policy, effective May 31, 2002, to mitigate the risk of future environmental liabilities arising from the structural failure of the Milltown Dam caused by an act of God.

In anticipation of completion of the consent decree negotiations, CFB filed an application to amend its FERC operating license to allow for the commencement of Stage 1 of the EPA’s proposed plan for the remediation of the Milltown Reservoir superfund site. Stage 1 activities anticipated the permanent drawdown of the Milltown Reservoir and the construction of: (i) the Clark Fork River bypass channel, (ii) a railroad spur to facilitate loading of contaminated sediments to be removed from the reservoir, and (iii) certain equipment access roads. All such construction activity was to take place within FERC jurisdictional areas. On January 19, 2005, the FERC issued an order dismissing CFB’s application, and issuing a notice of intent to accept surrender of CFB’s operating license. Based on certain incorrect assumptions made by the FERC (particularly with respect to the existence of a completed and executed consent decree for the Milltown Reservoir superfund site as of the date of the order), the FERC transferred its complete jurisdiction over the Milltown facility to the EPA and concluded that, based on certain actions to take place during the Stage 1 activities, that such actions demonstrate CFB’s intent to surrender its operating license. Moreover, based upon the operation of Section 121(e) of CERCLA, the FERC concluded that CFB need not file a formal license surrender application. Due to the FERC’s reliance upon certain incorrect assumptions, all relevant parties to the Milltown superfund consent decree negotiations concluded that the order created certain unacceptable risks due, in large part, to the fact that

a consent decree addressing the rights and obligations of the various parties with respect to implementation of the Milltown remedial action and restoration plan has not been fully negotiated and approved by the federal district court in Montana. As a result, EPA, the State of Montana, the Atlantic Richfield Company and CFB all filed comments with the FERC on February 18, 2005, requesting that the FERC modify its order to continue jurisdiction over the Milltown facility until entry of a final consent decree.

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

The Montana Power Company voluntarily cleaned up two sites in Butte and Helena, Montana where it formerly operated manufactured gas plants and had investigated a third in Missoula, Montana at the time of our acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company. The investigation conducted at the Missoula site did not require entry into the MDEQ voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena, Montana sites, however, were placed into the MDEQ’s voluntary remediation program for cleanup due to the existence of exceedences in groundwater of regulated pollutants. We believe that natural attenuation should address the problems at the Butte and Missoula sites. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation is necessary to prevent certain contaminants from migrating offsite. Based upon the results of a pilot remediation program implemented at the Helena site during 2004, we will install a remediation system at this location during 2005 that will promote the aerobic degradation of certain targeted contaminants. In light of this planned remediation activity, continued monitoring of groundwater at this site is necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty what the costs of additional cleanup will be for such groundwater remediation at Helena, or whether additional cleanup will be required at the Butte and Missoula sites. However, based upon the information available to date, our current environmental liability reserves and applicable insurance coverage, we do not expect cleanup costs at these sites to be material.

In April 1998, The Montana Power Company identified and reported a release of hydrocarbons during the replacement of a dispensing unit associated with an underground storage tank located at its Helena Operating Center. Impacted soils were removed and groundwater monitoring wells were installed. With the acquisition of the Montana Power Company, we succeeded to the liability associated with the site. To date, hydrocarbons remain detectable at low levels in groundwater and soil vapor extraction efforts are underway to remove the contaminants. We do not expect the outstanding cleanup costs to be material.

As described above, The Montana Power Company retained certain environmental liabilities in connection with its sale of assets to PPL Montana. Under the terms of our acquisition of the electric and natural gas transmission and distribution business of The Montana Power Company, we assumed the first $50 million of NorthWestern Energy LLC’s preclosing environmental liabilities, including these retained environmental liabilities. Touch America Holdings, Inc. assumed the next $25 million in costs. NorthWestern Energy LLC and Touch America Holdings, Inc. agreed to equally split costs that fall between $75 and $150 million. In light of the bankruptcy filing by Touch America, we do not believe Touch America will be able to satisfy its contractual indemnification obligation.

Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. However, we believe that we accrue an appropriate amount of costs and estimate reasonably foreseeable potential costs related to such environmental regulation and cleanup requirements. As of December 31, 2004, we have a reserve of approximately $45.3 million to cover all estimated environmental liabilities. We anticipate that as environmental costs become fixed and determinable we will seek insurance coverage and/or rate recovery, therefore we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

ITEM 2. PROPERTIES

NorthWestern’s executive offices are located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104, where we lease approximately 27,350 square feet of office space, pursuant to a lease that expires on June 30, 2005. We intend to exercise the automatic renewal provision of the lease agreement to extend the term for two additional years. This extension provision allows for automatic renewal in two year increments for up to eight years, and we have notified the lessor of our intent to exercise this option for the two-year period beginning July 1, 2005.

Our principal operating office for our South Dakota and Nebraska operations is owned and located at 600 Market Street W., Huron, South Dakota 57350. Substantially all of our South Dakota and Nebraska facilities are owned. Our principal operating office for our Montana operations is owned and located at 40 East Broadway Street, Butte, Montana 59701. We own or lease other offices throughout the state of Montana, including a 20,000 square foot facility in Butte, Montana, where we provide call center customer support services and conduct customer billing and other functions.

ITEM 3. LEGAL PROCEEDINGS

As a result of the Chapter 11 filing for the period from September 14, 2003 through November 1, 2004, attempts by third parties to collect, secure or enforce remedies with respect to most prepetition claims against us were subject to the automatic stay provisions of Section 362(a) of Chapter 11.

On October 19, 2004 the Bankruptcy Court entered a written order confirming our plan of reorganization. On October 25, 2004 Magten Asset Management Corporation (Magten) filed a notice of appeal of such order seeking, among other things, a reversal of the confirmation order. In connection with this appeal, Magten filed motions with the Bankruptcy Court and the United States District Court for the District of Delaware seeking a stay of the enforcement of the confirmation order to prevent our plan of reorganization from becoming effective. On October 25, 2004 the Bankruptcy Court denied Magten’s motion for a stay, and on October 29, 2004, the Delaware District Court denied Magten’s motion for a stay. With no stay imposed, our plan of reorganization became effective November 1, 2004. On December 31, 2004 a notice was filed that our plan of reorganization has been substantially consummated. In March 2005, we filed a motion to dismiss the appeal on equitable mootness grounds. While we cannot currently predict the impact or resolution of Magten’s appeal of the confirmation order, we intend to vigorously defend against the appeal.

On May 4, 2004, Netexit and its subsidiaries filed for bankruptcy protection under chapter 11 of the U.S. Bankruptcy Code. A creditors committee has been formed which is composed of creditors who had pending lawsuits and claims against Netexit at the time of filing for bankruptcy. Netexit and its subsidiaries filed a liquidating plan of reorganization on February 28, 2005 and a hearing on the disclosure statement is scheduled for April 5, 2005. The creditors committee has sent NorthWestern and Netexit a notice that it will be seeking bankruptcy court approval to file an avoidance or subordination claim against NorthWestern if Netexit and its subsidiaries do not. We intend to vigorously defend against the creditors committee claim if filed in Netexit’s bankruptcy case, but we cannot currently predict the impact or rsolution of such creditors committee action on NorthWestern’s claim in Netexit’s bankruptcy case.

We, and certain of our present and former officers and directors, were named as defendants in numerous complaints purporting to be class actions which were filed in the United States District Court for the District of South Dakota, Southern Division, alleging violations of Sections 11, 12 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. In June 2003, the complaints were consolidated in the United States District Court for the District of South Dakota and given the caption In Re NorthWestern Corporation Securities Litigation, Case No. 03-4049, and Carpenters Pension Trust for Southern California, Oppenheim Investment Management, LLC, and Richard C. Slump were named as co-lead plaintiffs (the “Lead Plaintiffs”). In July 2003, the Lead Plaintiffs filed a consolidated amended class action complaint naming NorthWestern, NorthWestern Capital Financing II and III, Blue Dot, Expanets, certain of our present and former officers and directors, along with a number of investment banks that participated in the securities offerings. The amended complaint alleges that the defendants misrepresented and omitted material facts concerning the business operations and financial performance of NorthWestern, Expanets, Blue Dot and CornerStone, overstated NorthWestern’s revenues and earnings by, among other things, maintaining insufficient reserves for accounts receivable at Expanets, failing to disclose billing problems and lapses and data conversion problems, failing to make full disclosures of problems (including the billing and data conversion issues) arising from the implementation of Expanets’ EXPERT system, concealing losses at Expanets and Blue Dot by improperly allocating losses to minority interest shareholders, maintaining insufficient internal controls, and profiting from improper related-party transactions. We, and certain of our present and former officers and directors, were also named as defendants in two complaints purporting to be class actions which were filed in the United States District Court for the Southern District of New York, entitled Sanford & Beatrice Golman Family Trust, et al. v. NorthWestern Corp., et al., Case No. 03CV3223, and Arthur Laufer v. Merle Lewis, et al., Case No. 03CV3716, which were brought on behalf of the purchasers of our 7.20%, 8.25%, and 8.10% trust preferred securities which were offered and sold pursuant to our registration statement on Form S-3 filed on July 12, 1999. The plaintiffs’ claims are based on similar allegations of material misrepresentations and omissions of fact relating to the registration statement in violation of Sections 11 and 12 of the Securities Act of 1933, and they seek unspecified compensatory damages, rescission and attorneys’, accountants’ and experts’ fees. In July 2003, Arthur Laufer v. Merle Lewis, et al. was transferred to the District of South Dakota and consolidated with the consolidated actions pending in that court. In September 2003, Sanford & Beatrice Golman Family Trust, et al. v. NorthWestern Corp., et al. was also transferred to the District of South Dakota and consolidated with the consolidated actions. In February 2004, the Golman Family Trust action was also consolidated with the actions pending in that court. The actions have been stayed as to NorthWestern Corporation due to its bankruptcy filing. In October 2003, Expanets, Blue Dot, and certain of NorthWestern’s present and former officers and directors filed motions to dismiss the consolidated amended class action complaint for failure to state a claim, which are currently pending in the District of South Dakota.

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

2003, the Bankruptcy Court entered an order preliminarily enjoining the plaintiffs in In Re NorthWestern Corporation Derivative Litigation from prosecuting the litigation against NorthWestern, its subsidiaries and its current and former officers and directors until further order of the Bankruptcy Court. On February 15, 2005, the Bankruptcy Court vacated its preliminary injunction order. The federal court has been advised of the Bankruptcy Court’s order.

On February 7, 2004, the parties to the above consolidated securities class actions and consolidated derivative litigation, together with certain other affected persons and parties, reached a tentative settlement of the litigation. On April 19, 2004, the parties and other affected persons signed a memorandum of understanding (MOU) which memorialized the tentative settlement. On June 16, 2004, the parties and other affected persons signed a settlement agreement memorializing the tentative settlement and addressing various issues necessary for federal court approval. We obtained approval of the MOU in the NorthWestern and Netexit bankruptcy cases on October 7, 2004 and September 15, 2004, respectively. Prior to those approvals from the Bankruptcy Court in both the NorthWestern and Netexit bankruptcy cases, the federal court in Sioux Falls granted preliminary approval of the settlement agreement pending a fairness hearing on December 13, 2004. On January 14, 2004 the federal court finally approved the settlement In Re NorthWestern Securities Litigation and no timely appeals have been filed. The federal court delayed its final approval on In Re NorthWestern Derivative Litigation pending bankruptcy court dismissal of its stay of the derivative litigation. Among the terms of the settlement, we, Expanets, Blue Dot and other parties and persons are released from all claims to these cases, a settlement fund in the amount of $41 million (of which approximately $37 million would be contributed by our directors and officers liability insurance carriers, and $4 million would be contributed from other persons and parties) is established, and the plaintiffs have a $20 million liquidated securities claim against Netexit. Claims by our current and former officers and directors for indemnification for these proceedings will be channeled into the Directors and Officers Trust under the Plan.

On October 26, 2004 Magten filed a notice of appeal of the Bankruptcy Court’s approval of the MOU. Magten’s appeal of the confirmation order and the order approving the MOU have been consolidated. In March 2005 we moved to dismiss both appeals on equitable mootness grounds. While we cannot currently predict the impact or resolution of the appeals and our motion to dismiss, we intend to vigorously prosecute our dismissal motion and defend against the appeals as noted.

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern, NorthWestern Communications Solutions, Expanets and Blue Dot. This development followed the SEC’s requests for information made in connection with the previously disclosed SEC informal inquiry into questions regarding the restatements and other accounting and financial reporting matters. Since December 2003, we have periodically received and continue to receive subpoenas from the SEC requesting documents and testimony from employees regarding these matters. The SEC investigation will continue and any claims alleging violations of federal securities laws made by the SEC will not be extinguished pursuant to our plan of reorganization. In addition, certain of our directors and several employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the Federal Bureau of Investigation (FBI) concerning certain of the allegations made in the class action securities and derivative litigation matters. We have not been advised that NorthWestern is the subject of any FBI investigation. We understand that the FBI and the Internal Revenue Service (IRS) have contacted former employees of ours or our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters. We are cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are contacted in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, for which we can provide no

assurance, we may face sanctions, including, but not limited to, monetary penalties and injunctive relief and any monetary liability incurred by us may be material to our financial position or results of operations.

In January 2004, two of the QFs—Colstrip Electric Limited Partnership (CELP) and Yellowstone Electric Limited Partnership (YELP)—initiated adversary proceedings against NorthWestern in our Chapter 11 proceedings. In the CELP adversary proceeding, CELP seeks additional payment for capacity contracted to be provided to NorthWestern under its existing power purchase agreement. In addition, we intervened in a FERC proceeding, which places at issue the QF status of CELP. A FERC judge initially has ruled that CELP is a QF; we filed an appeal with the FERC on October 12, 2004 and the FERC’s response is pending. In the YELP adversary proceeding, YELP seeks a determination of when and who has the right to determine the scheduling of maintenance on the power facility. We have obtained approval in our bankruptcy case for assumption of an amended agreement with YELP and a settlement with YELP which resolves prepetition claims, lowers the overall energy cost and eliminates the distinction in the previous agreement between summer and winter pricing. We intend to vigorously defend against the CELP adversary proceedings. In the opinion of management, the amount of ultimate liability with respect to the CELP adversary proceedings will not materially affect our financial position or results of operations.

On April 16, 2004 Magten and Law Debenture Trust Company of New York (Law Debenture) initiated an adversary proceeding, the QUIPs Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets of CFB to us. In essence, Magten and Law Debenture are asserting that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because such transfer left CFB insolvent and unable to pay certain claims. The plaintiffs also assert that they are creditors of CFB as a result of Magten owning a portion of the Series A 8.5% Quarterly Income Preferred Securities for which Law Debenture serves as the Indenture Trustee. By its adversary proceeding, the plaintiffs seek, among other things, the avoidance of the transfer of assets, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets and the return of such assets to CFB. In August 2004, the Bankruptcy Court granted in part, but denied in part our motion to dismiss the QUIPs Litigation. (In addition to the adversary proceeding filed by Magten and Law Debenture, the plaintiffs in the class action lawsuit entitled McGreevey, et al v. Montana Power Company, et al received approval in our bankruptcy case to initiate similar adversary proceedings. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed below, they would not file such proceeding.) On April 19, 2004, Magten also filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for breaches of fiduciary duties by such officers. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. On February 9, 2005 we agreed to settlement terms with Magten and Law Debenture to release all claims, including Magten and Law Debenture’s fraudulent conveyance action pending against each other for Magten and Law Debenture receiving the distribution of new common stock and warrants from Class 8(b) in the same amounts as if they had voted to accept the Plan and a distribution from Class 9 of new common stock in the amount of approximately $17.4 million. Prior to seeking approval from the Bankruptcy Court, certain major shareholders and the Plan Committee objected to the settlement on both its economic terms and asserting that the structure of the settlement violated the Plan. After reviewing the objections and undertaking our own analysis of the potential Plan violation, we informed Magten and Law Debenture as well as the Plan Committee and the objecting major shareholders that we would not proceed with the settlement. Magten and Law Debenture filed a motion with our Bankruptcy Court seeking approval of the settlement. A hearing was held on such motion on March 8, 2005. The Bankruptcy Court took the matter under advisement and entered an order denying the motion filed by Magten and Law Debenture on March 10, 2005. At this time, we cannot predict the impact of the resolution of any of these lawsuits or reasonably estimate a range of possible loss, which could be material. The resolution of these lawsuits could harm our business and have a material adverse impact on our financial condition. We intend to

vigorously defend against the adversary proceeding and any subsequently filed similar litigation. The plaintiffs’ claims with respect to the QUIPs Litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we established with respect to the Class 9 disputed claims reserve under the plan of reorganization.

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al, now pending in U.S. District Court in Montana. The lawsuit, which was filed by former shareholders of The Montana Power Company (most of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of the Montana Power Company), claims that the disposition of various generating and energy-related assets by The Montana Power Company were void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern is named as a defendant due to the fact that we purchased Montana Power LLC, which plaintiffs claim is a successor to the Montana Power Company.

On November 6, 2003, the Bankruptcy Court approved a stipulation between NorthWestern and the plaintiffs in McGreevey, et al. v. The Montana Power Company, et al. The stipulation provides that litigation, as against NorthWestern, CFB, The Montana Power Company, Montana Power LLC and Jack Haffey, shall be temporarily stayed for 180 days from the date of the stipulation. The stay has been extended. Pursuant to the stipulation and after providing notice to NorthWestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. On July 10, 2004, we and the other insureds under the applicable directors and officers liability insurance policies along with the plaintiffs in the McGreevey case, plaintiffs in the In Re Touch America Holdings, Inc. Securities Litigation and the Touch America Creditors Committee reached a tentative settlement through mediation. Among the terms of the tentative settlement, we, CFB and other parties will be released from all claims in this case, the plaintiffs in McGreevey will dismiss their claims against the third party purchasers of the generation assets and non-regulated energy assets of Montana Power Company including PPL Montana, and a settlement fund in the amount of $67 million (all of which will be contributed by the former Montana Power Company directors and officers liability insurance carriers) will be established. The settlement is subject to the occurrence of several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding, and approval of the proposed settlement by the Federal District Court for the District of Montana, where the class actions are pending. We cannot predict the ultimate outcome of this litigation in the event that the settlement is not approved, or does not take effect for any other reason. If for any reason the settlement is not approved, then we intend to vigorously defend against this lawsuit. If we are unsuccessful in defending against this class action lawsuit, the plaintiffs’ litigation claims would be subordinated to our other debt under our Plan, and such claims would be treated as securities, or Class 14, claims under our plan of reorganization, and would be entitled to no recovery against NorthWestern under our Plan. Claims by our current and former officers and directors (and the former officers and directors of The Montana Power Company) for indemnification for these proceedings would be channeled into the Directors and Officers Trust established by the Plan. The plaintiffs could elect to proceed directly against CFB and the assets owned by such entity, which as of December 31, 2004 were not material to our operations or financial position. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition.

In NorthWestern Corporation vs. PPL Montana, LLC vs. NorthWestern Corporation and Clark Fork and Blackfoot, LLC, No. CV-02-94-BU-SHE, (D. MT), we are pursuing claims against PPL Montana, LLC (PPL) due to its refusal to purchase the Colstrip transmission assets under the Asset Purchase Agreement (APA) executed by and between The Montana Power Company (MPC) and PP&L Global, Inc. (PPL Global). NorthWestern claims PPL (PPL Global’s successor-in-interest under the APA) is required to purchase the Colstrip transmission assets for $97.1 million. PPL has also asserted a number of counterclaims against NorthWestern and CFB based in large part upon PPL’s claim that MPC and/or NorthWestern Energy breached two Wholesale Transition Service Agreements and certain indemnification obligations under the APA in the approximate amount of $120 million. PPL also filed a proof of claim and an amended proof of claim against NorthWestern’s bankruptcy estate, which asserts substantially the same claims as the PPL counterclaim. PPL moved the Bankruptcy Court for relief from the automatic stay to pursue its counterclaims. NorthWestern objected to PPL’s motion to lift the automatic stay and has also filed a motion to transfer the venue of the entire litigation to the United States District Court for the District of Delaware. On March 19, 2004 the federal court in Montana denied our motion to transfer the entire case. Thereafter, our Bankruptcy Court transferred all the claims for resolution to the federal court in Montana. We intend to vigorously defend against the PPL claims in federal court as well as vigorously prosecute our claims against PPL. We cannot currently predict the impact or resolution of the claims or this litigation or reasonably estimate a range of possible loss on the counterclaims, which could be material to the disputed claims reserve. PPL’s counterclaims with respect to this litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we established with respect to the Class 9 disputed claims reserve under the plan of reorganization.

We are also one of several defendants in a class action lawsuit entitled In Re Touch America ERISA Litigation, which is currently pending in U.S. District Court in Montana. The lawsuit was filed by participants in the former Montana Power Company retirement savings plan and alleges that there was a breach of fiduciary duty in connection with the employee stock ownership aspects of the plan. The court has recently entered orders indefinitely staying the ERISA litigation because of Touch America Holdings Inc.’s bankruptcy filing. We intend to vigorously defend against these lawsuits. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition. We believe that in the event of a judgment against us in this litigation, we will be able to make claims against The Montana Power Company’s fiduciary insurance policy. Any judgment against us in excess of policy limits would be treated as unsecured general, or Class 9, claims and would be satisfied out of the share reserve that we have established.

although it alleges facts relating to NorthWestern’s conduct. Certain of our former officers and directors are named as defendants in the amended consolidated complaint. The plaintiffs seek compensatory damages, prejudgment and postjudgment interest and costs, injunctive relief, and other relief. On November 6, 2003, the Bankruptcy Court entered an order approving a stipulation between NorthWestern and plaintiffs in this litigation. The stipulation provides that litigation as against NorthWestern shall be temporarily stayed for 180 days from the date of the stipulation. The stay has been extended. Pursuant to the stipulation and after providing notice to NorthWestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. On March 2, 2004, the plaintiffs filed a corrected consolidated amended complaint against CornerStone and the individual defendants, which also did not name NorthWestern. In June 2004, CornerStone Propane Partners, LP along with its subsidiaries and affiliates filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. As a result of that filing this case is now stayed against CornerStone Propane Partners and other named subsidiaries and affiliates. If we are named in the lawsuit, we intend to vigorously defend any claims asserted against us by these lawsuits. To the extent such claims are prepetition claims, such claims would be extinguished under the confirmation order. If the claims are not extinguished, the plaintiffs’ claims with respect to this litigation would be treated as securities, or Class 14, claims and would be entitled to no recovery under the plan of reorganization. Any claims in this litigation for indemnification from our officers and directors, would be channeled into the Directors and Officers Trust to the extent that they are indemnification claims.

We were named in a complaint filed against us, CornerStone Propane GP, Inc., CornerStone Propane Partners LP and other defendants in a lawsuit entitled Leonard S. Mewhinney, Jr. v. NorthWestern Corporation, et al. in the circuit court of the city of St. Louis, state of Missouri. The complaint alleges that the plaintiff purchased units of Cornerstone Propane Partners, LP between March 13, 1998 and November 29, 2001 and that NorthWestern owned and controlled all or the majority of stock or other indicia of ownership of Cornerstone Propane, GP, Inc. and all other entities that were the general partners of Cornerstone Propane Partners, LP. According to the plaintiff, NorthWestern, Cornerstone Propane GP, Inc., Coast Gas, Inc. and Cornerstone Propane Partners, LP breached fiduciary duties to the plaintiff by engaging in certain misconduct, including mismanaging Cornerstone Propane Partners, LP and transferring its assets for less than market value and other activities. The complaint further alleges that the defendants fraudulently failed to disclose material information regarding the value of units of Cornerstone Propane Partners, LP and violated the Florida Securities Act in connection with the sale of such units. The plaintiff seeks compensatory damages, punitive damages and costs. The complaint was amended to add a state class action claim. All defendants filed a petition to remove the case to the federal court in St. Louis, Missouri, but the federal court granted plaintiff’s motion to remand. The case has now been stayed against NorthWestern and CornerStone due to their bankruptcy filings. Any claim arising from this lawsuit has been channeled to the Directors and Officers Trust under the confirmation order.

Certain of our present and former officers and directors, and CornerStone Propane Partners, LP, as a nominal defendant, are among other defendants named in two derivative actions commenced in the Superior Court for the State of California, County of Santa Cruz, entitled Adelaide Andrews v. Keith G. Baxter, et al., Case No. CV146662 and Ralph Tyndall v. Keith G. Baxter, et al., Case No. CV146661. These derivative lawsuits allege that the defendants breached various fiduciary duties based upon the same general set of alleged facts and circumstances as the federal unitholder suits. The plaintiffs seek unspecified compensatory damages, treble damages pursuant to the California Corporations Code, injunctive relief, restitution, disgorgement, costs, and other relief. The case has now been stayed against CornerStone due to its bankruptcy filing. Claims by our current and former officers and directors for indemnification with respect to these proceedings would be channeled into the Directors and Officers Trust under the terms of the Plan.

On April 30, 2003, Mr. Richard Hylland, our former President and Chief Operating Officer, filed a demand for arbitration of contract claims under his employment agreement, as well as tort claims for

defamation, infliction of emotional distress and tortious interference and a claim for punitive damages. Mr. Hylland is seeking relief in the amount of $25 million, plus interest, attorney’s fees, costs, and punitive damages. Mr. Hylland has also filed claims in our bankruptcy case similar to the claims in his arbitration demand. We dispute Mr. Hylland’s claims and intend to vigorously defend the arbitration and object to Mr. Hylland’s claims in our bankruptcy case. On May 6, 2003, based on the recommendations of the Special Committee of the NorthWestern Board of Directors formed to evaluate Mr. Hylland’s performance and conduct in connection with the management of NorthWestern and its subsidiaries, the Board determined that Mr. Hylland’s performance and conduct as President and Chief Operating Officer warranted termination under his employment contract. This arbitration will proceed under the terms of the order confirming the Plan, and we have obtained a timetable from the arbitrator. Mr. Hylland’s claims with respect to this proceeding would be treated as unsecured general, or Class 9, claims and would be satisfied out of the share reserve that we have established.

On August 12, 2003, the Montana Consumer Counsel (MCC) filed a Petition for Investigation, Adoption of Additional Regulatory Controls and Related Relief with the Montana Public Service Commission (MPSC). On August 22, 2003, the MPSC issued an order initiating an investigation of NorthWestern Energy relating to, among others, finances, corporate structure, capital structure, cash management practices and affiliated transactions. The relief sought includes adoption of new regulatory controls that would specifically apply to NorthWestern, including additional reporting, cost allocation and financing rules and requirements, and examination of affiliate transactions necessary to ensure that we are not operating our energy division, and will not in the future operate, in a manner that would prejudice our ability to furnish reasonably adequate service and facilities at reasonable and just charges as required under Montana law. We have entered into a settlement of this matter with the MPSC and MCC, which was approved by the Bankruptcy Court on July 15, 2004, and thereafter by the MPSC, and this proceeding will be closed except for the ongoing review and consideration of recommendations related to an infrastructure audit conducted by a consultant. We are currently reviewing these recommendations and have not yet determined the estimated financial impact they may have on our results of operations. As part of the settlement, we agreed to pay approximately $2.8 million of professional fees incurred by the MPSC, the MCC and the Montana Attorney General in connection with our bankruptcy filing. These fees were paid upon emergence from bankruptcy.

Expanets and NorthWestern have been named defendants in two complaints filed with the Supreme Court of the State of New York, County of Bronx, alleging violations of New York’s prevailing wage laws, breach of contract, unjust enrichment, willful failure to pay wages, race, ethnicity, national origin and/or age discrimination and retaliation. In the complaint entitled Felix Adames et al. v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, Bronx County, Index No. 8664-04, which has not yet been served upon Expanets, 14 former employees of Expanets seek damages in the amount of $27,750,000, plus interest, penalties, punitive damages, costs, and attorney’s fees. In the complaint entitled Wayne Belnavis and David Daniels v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, Bronx County, Index No. 8729-04, two former employees of Expanets seek damages in the amount of $12,500,000, plus interest, penalties, punitive damages, costs, and attorney’s fees. Avaya Inc. has sent NorthWestern and subsidiaries a notice seeking indemnification and defense for these lawsuits under the asset purchase agreement. We have responded by accepting in part and rejecting in part the indemnification request. As a result of the Netexit bankruptcy, the cases were removed to federal court in New York and Netexit was dismissed from the lawsuit. NorthWestern and Avaya were dismissed as defendants by the plaintiffs. These claims against Netexit will be subject to the claims process of the Netexit bankruptcy proceeding. We intend to vigorously defend against the allegations made in these claims. We cannot currently predict the impact or resolution of these claims or reasonably estimate a range of possible loss.

Netexit is also subject to an investigation by the New York City Comptroller’s Office over the same prevailing wage allegations set forth in the Adames and Belnavis lawsuits. The Comptroller’s Office scheduled a hearing before the Office of Administrative Trials and Hearings, which hearing is now stayed pending the Bankruptcy Court’s decision on its rule to show cause why the Comptroller’s Office should not be held in contempt of court. The Comptroller’s Office also filed claims in the Netexit bankruptcy and will be subject to the claims process in the bankruptcy case. Avaya Inc. has sent NorthWestern and subsidiaries a notice seeking indemnification and defense for these lawsuits under the asset purchase agreement. We have responded by accepting in part and rejecting in part the indemnification request. We intend to vigorously defend against the allegations made in these claims. We cannot currently predict the impact or resolution of these claims or reasonably estimate a range of possible loss.

On March 17, 2004, certain minority shareholders of Expanets filed a lawsuit against Avaya Inc., Expanets, NorthWestern Growth Corporation, and Merle Lewis, Dick Hylland and Dan Newell entitled Cohen et al. v Avaya Inc., et al. in U.S. District Court in Sioux Falls, South Dakota contending that (i) the defendants fraudulently induced the shareholders to sell their businesses to Expanets during 1998 and 1999 in exchange for Expanets stock which would have value only if Expanets went public, when in fact no IPO was intended, and (ii) the defendants and NorthWestern (a) hid the true financial condition of NorthWestern, NorthWestern Growth and Expanets, (b) permitted internal controls to lapse, (c) failed to document loans by NorthWestern to Expanets, and (d) allowed the individual defendants to realize millions of dollars in bonus payments at the expense of Expanets and its minority shareholders. The lawsuit alleges federal and state securities laws violations and breaches for fiduciary duties. The plaintiffs have recently filed an amended complaint that reflects one less plaintiff and a clarification on the damages that they seek. In addition, Avaya Inc. has sent NorthWestern a notice seeking indemnification and defense for this lawsuit under the terms of the asset purchase agreement. We have responded by accepting in part and rejecting in part the indemnification request. The case has now been stayed against Expanets due to its bankruptcy filing. The defendants, including NorthWestern Growth Corporation, have filed motions to dismiss, which are pending and we have filed a formal objection to the claim the defendants filed in the bankruptcy case. Claims by our former officers and directors for indemnification for these proceedings would be channeled in to the Directors and Officers Trust established pursuant to NorthWestern’s Plan. The plaintiff’s litigation claims against Netexit would be subordinated to NorthWestern’s debt and claims of general unsecured creditors in the Netexit bankruptcy, and therefore such claims would not be entitled to recovery. NorthWestern Growth Corporation intends to vigorously defend against this lawsuit. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material.

Relative to Colstrip Unit 4’s long-term coal supply contract with Western Energy Company, Mineral Management Service of the United States Department of Interior issued orders to Western Energy Company (WECO) in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 and 4. The orders assert that additional royalties are owed as a result of WECO not paying royalties under a coal transportation agreement from 1991 through 2001. WECO has appealed these orders and we are monitoring the process. WECO has asserted that any potential judgment would be considered a pass-through cost under the coal supply agreement. Based on our review, we do not believe any potential judgment would qualify as a pass-through cost under the terms of the coal supply agreement. Neither the outcome of this matter nor the associated costs can be predicted at this time.

believe that the natural gas procurement activities in question were not imprudent we filed suit in district court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. At this time, this matter has been suspended pending settlement discussions with the MPSC.

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

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

No matters were submitted to a vote of our security holders during the quarter ended December 31, 2004.

Part II

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

In connection with the consummation of the Plan of Reorganization (Plan) on November 1, 2004 all shares of our old common stock were canceled and 35,500,000 shares of new common stock of NorthWestern Corporation, and 4,620,333 warrants to purchase shares of common stock were issued pursuant to the Plan to the holders of certain classes of claims. In addition, 114,158 restricted shares issued to employees were vested on November 1, 2004. Our new common stock, which is traded under the ticker symbol NWEC, is listed on the NASDAQ National Market System. The following table sets forth the high and low bid prices for our common stock for the two-month period from November 1, 2004 through December 31, 2004. The quotations set forth below reflect interdealer prices, without retail mark-up, mark-downs, or commissions and may not represent actual transactions:

QUARTERLY COMMON STOCK DATA

	Prices				Cash Dividends
	High		Low		Paid
2004—
November 1, 2004—December 31, 2004	$	28.00	$	24.82		$	—

On March 10, 2005, the last reported sale price on the NASDAQ for our common stock was $28.12.

Holders

As of March 8, 2005, there were 62 common shareholders of record of 31,471,045 outstanding shares of our common stock. An additional 4,139,981 shares were held in reserve by our transfer agent for claims dispute resolution.

Dividends

NorthWestern's Board of Directors has approved a quarterly cash dividend on our common stock of $0.22 per share. The new dividend is payable on March 31, 2005, to shareholders of record as of March 24, 2005. Cash dividends are declared by our Board of Directors. The Board of Directors reviews the dividend quarterly and establishes the dividend rate based upon such factors as our earnings, financial condition, capital requirements, debt covenant requirements and/or other relevant conditions. Although we expect to continue to declare and pay cash dividends on our common stock in the future, we cannot assure that dividends will be paid in the future or that, if paid, the dividends will be paid in the same amount as declared in the first quarter of 2005.

Securities Authorized for Issuance under Equity Compensation Plans

The following table presents summary information about our equity compensation plans, including our employee incentive plan. The table presents the following data on plans approved by shareholders and plans not so approved, all as of the close of business on December 31, 2004:

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

(ii) the weighted average exercise price of those outstanding stock options, warrants and rights; and

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

For additional information regarding our stock option plans and the accounting effects of our stock-based compensation, please see Notes 4 and 17 to our Financial Statements included in Item 8 herein.

Plan category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
(a)

Weighted average
exercise price of
outstanding options,
warrants and rights
(b)

Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))(1)
(c)

Equity compensation plans approved by security holders

None

N/A

Equity compensation plans not approved by security holders

New Incentive Plan(1)

—

2,265,957

Special Recognition Grants(2)

228,315

N/A

None

Total

228,315

2,265,957

(1) Upon emergence from bankruptcy, the New Incentive Plan, which is described more fully in Item 11 herein, was established pursuant to the plan of reorganization, which set aside shares for the new Board of Directors to establish and administer the New Incentive Plan.

(2) Pursuant to Article 9.3(b) of our plan of reorganization, 228,315 shares of reserved New Common Stock were allocated and delivered to certain officers and other management employees as restricted stock through Special Recognition Grants (Grants). The Grants, representing 228,315 restricted shares, were awarded to participating employees at emergence from bankruptcy to provide an immediate stake in NorthWestern and linkage to shareholder interests. For additional information please see Item 11 herein.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data has been derived from our consolidated financial statements and should be read in conjunction with the consolidated financial statements and notes thereto and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other financial data included elsewhere in this report. The historical results are not necessarily indicative of results to be expected for any future period. During 2003, we committed to a plan to sell or liquidate our interest in Expanets and Blue Dot and accounted for our interest in these subsidiaries as discontinued operations. In 2002, we disposed of our interest in CornerStone and accounted for the disposal as discontinued operations. Accordingly, the financial data below has been restated for fiscal years 2000 through 2002.

FIVE-YEAR FINANCIAL SUMMARY

	Successor Company			Predecessor Company
	November 1- December 31,			January 1- October 31,		Year Ended December 31,
	2004			2004(1)		2003			2002			2001		2000
Financial Results (in thousands, except per share data)
Operating revenues	$	205,952		$	833,037	$	1,012,515		$	783,744		$	255,151	$	188,390
Income (loss) from continuing operations	(6,520		)	548,889		(71,582		)	(9,356		)	4,175		3,349
Basic earnings (loss) per share from continuing operations(2)	(0.18		)
Diluted earnings (loss) per share from continuing operations(2)	(0.18		)
Dividends paid per common share	—
Financial Position
Total assets	$	2,413,516		$	2,524,964	$	2,456,849		$	2,785,061		$	2,641,685	$	2,898,070
Long-term debt, including current portion	836,946			910,154		1,784,237			1,668,431			583,651		514,347
Preferred stock not subject to mandatory redemption	—			—		—			—			3,750		3,750
Preferred stock subject to mandatory redemption	—			—		365,550			370,250			187,500		87,500
Ratio of earnings to fixed charges(3)	—			8.5		—			—			—		—

(1) Income (loss) from continuing operations includes reorganization items. The financial position information is that of the Successor Company as of October 31, 2004.

(2) Per share results have not been presented for the Predecessor Company as all shares were cancelled upon emergence.

(3) The fixed charges exceeded earnings, as defined by this ratio, by $11.5 million for the two-months ended December 31, 2004, and $86.6 million, $77.8 million, $9.5 million and $4.1 million for the years ended December 31, 2003, 2002, 2001 and 2000, respectively.

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

The following discussion and analysis should be read in conjunction with “Item 6 Selected Financial Data” and our consolidated financial statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our industry segments, see Note 23 of “Notes to Consolidated Financial Statements” of our consolidated financial statements, which are included in Item 8 herein. For information regarding our revenues, profits/losses and assets, see our consolidated financial statements included in Item 8 hereof.

OVERVIEW

Between September 14, 2003 and November 1, 2004, we operated as a debtor-in-possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code. In accordance with SOP 90-7, we applied the principles of fresh-start reporting as of the close of business on October 31, 2004. “Predecessor Company” refers to us prior to emergence from bankruptcy (operations from January 1, 2002 through October 31, 2004). “Successor Company” refers to us after emergence from bankruptcy (operations from November 1, 2004 through December 31, 2004). Due to the application of fresh-start reporting, the Consolidated Financial Statements have not been prepared on a consistent basis with, and therefore generally are not comparable to those of the Predecessor Company and have been presented separately.

Plan of Reorganization

The Bankruptcy Court entered a written order confirming our Plan on October 19, 2004, and it became effective on November 1, 2004. The consummation of the Plan resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors. In general, the terms of our Plan provided for the following:

· Holders of our senior unsecured notes (Class 7 claimants) received 28.3 million shares of new common stock in exchange for $898.3 million in allowed claims;

· Holders of TOPrS (Class 8(a) claimants) received 2.3 million shares of new common stock and warrants for an additional 4.4 million shares of common stock in exchange for $321.1 million in allowed claims. The warrants may be exercised for a period of three years from the effective date;

· Holders of QUIPs (Class 8(b) claimants), were allowed to select either of the following: (i) receive a pro rata share of 0.5 million shares of new common stock, plus warrants with the same terms as the warrants distributed to the TOPrS, in exchange for their claims, including any litigation claims, or (ii) continue the litigation against us generally referred to as the QUIPs Litigation and receive a distribution based on a Class 9 claim, if any, based only upon final resolution of the QUIPs Litigation;

· We established a reserve of approximately 4.4 million shares of common stock from the shares allocated to holders of our trade vendor claims in excess of $20,000 (Class 9 claimants) and holders of senior unsecured notes. The shares held in this reserve will be distributed pro rata to holders of allowed trade vendor and general unsecured claims in excess of $20,000, and may be used to resolve various outstanding litigation matters, such as the QUIPs Litigation, certain litigation with PPL Montana and other unliquidated litigation claims;

· Secured debt was not impaired and has been assumed; and

· Common stock existing prior to November 1, 2004 was cancelled, with no distributions to prior shareholders.

As noted above, a portion of the common shares issued upon emergence were set aside to fund a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the Plan. Under the terms of the Plan, to the extent such claims are resolved post-emergence, the claimants will receive shares from the reserve on the same basis as if the claim had been settled upon emergence, therefore the allowed claim will be reduced to the same recovery percentage as other creditors in the same class. If excess shares remain in the reserve after satisfaction of all obligations, such amounts would be reallocated prorata to the Class 7 and 9 claimants. We have surrendered control over the common stock provided and the shares reserve is administered by our transfer agent, therefore we recognized the issuance of the common stock upon emergence.

We filed several motions to terminate various nonqualified benefit plans with estimated allowed claims of approximately $17 million. All liabilities associated with these plans have been removed from our balance sheet based on our expectation that these claims will be settled by releasing shares from the reserve established for Class 9 claimants. While we expect the Bankruptcy Court to approve termination of these plans, the status is currently uncertain. If the Bankruptcy Court were to require us to reinstate these plans in the future, then we would have to reestablish the liabilities on our balance sheet and recognize a loss in the Successor Company operations.

Fresh-Start Reporting

In connection with our emergence from Chapter 11, we reflected the terms of the Plan in our consolidated financial statements as of the close of business on October 31, 2004, applying fresh-start reporting under SOP 90-7. Upon applying fresh-start reporting, a new reporting entity (the Successor Company) is deemed to be created and the recorded amounts of assets and liabilities are adjusted to reflect their estimated fair values. The reported historical financial statements of the Predecessor Company for periods ended prior to November 1, 2004 generally are not comparable to those of the Successor Company. Reorganization Items as shown in our results of operations reflects the impact of continuing costs incurred related to our reorganization since we filed for protection under Chapter 11 and the impact of the fresh-start reporting adjustments.

To facilitate the calculation of the enterprise value of the Successor Company as defined in SOP 90-7, we developed a set of financial projections and engaged an independent financial advisor to assist in the determination. The enterprise value was determined using various valuation methods including, (i) reviewing historical financial information (ii) comparing us and our projected performance to the market values of comparable companies, (iii) performing industry precedent transaction analysis, and (iv) considering certain economic and industry information relevant to the operating business. The estimated enterprise value is highly dependent upon achieving the future financial results set forth in the projections and is necessarily based on a variety of estimates and assumptions which, though considered reasonable by management, may not be realized and are inherently subject to significant business and economic uncertainties and contingencies, many of which are beyond our control. The resulting enterprise value was calculated using a 7% discount rate to be within an approximate range of $1.415 billion to

$1.585 billion. We selected the midpoint value of the range, $1.5 billion, as the reorganization value. This value is consistent with the Voting Creditors and Bankruptcy Court approval of our Plan.

Recent Financing Transaction

On November 1, 2004, concurrent with our emergence from bankruptcy, we entered into a new $225 million credit facility. The credit facility consists of a $125 million, five-year revolving tranche and a $100 million, seven-year term tranche. The revolving tranche replaced our Debtor In Possession (DIP) Facility and is available to us for general corporate purposes and for the issuance of letters of credit. Concurrently with the establishment of the new credit facility, we issued $225 million of our 5.875% senior secured notes due November 1, 2014. Borrowings under the term portion of the new credit facility, together with the net proceeds of the notes offering and available cash, were used to repay our $390 million senior secured term loan facility.

Status of Noncore Asset Sales Efforts

Under the terms of a settlement agreement reached with CornerStone, we received a $15 million allowed secured claim in CornerStone’s bankruptcy proceedings. In December 2004, we sold our secured claim against CornerStone and received $15 million in cash. As of December 31, 2004, we have no remaining interest in or receivables from CornerStone.

In December 2004 we received $10 million from Blue Dot in partial satisfaction of its dividends payable on preferred stock. In addition, an insurance company returned approximately $9 million to us that they had been holding as collateral for performance bonds and other obligations of Blue Dot and Netexit.

In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. Netexit currently holds approximately $65 million in cash, which is included in current assets of discontinued operations on our consolidated financial statements. Claims aggregating approximately $212 million (excluding equity related claims of approximately $94 million) have been filed against Netexit. NorthWestern’s unsecured debt claims represent $185.2 million of this amount. Netexit filed a proposed liquidating plan of reorganization in February 2005 which provides for a distribution to unsecured creditors of approximately 25% of their allowed claim. If this distribution occurs, then we could receive $40-$50 million upon the ultimate effective date of Netexit’s liquidating plan of reorganization on account of claims filed by NorthWestern against Netexit. However, there are many factors beyond our control which could affect the timing and amount of any distribution on NorthWestern’s Netexit claims including our ability to obtain the support of Netexit’s official committee of unsecured creditors for Netexit’s liquidating plan of reorganization. Netexit may incur significant additional expenses related to the bankruptcy filing and may incur additional losses related to the resolution of open claims. Additionally, Netexit’s creditors committee has indicated that NorthWestern’s claims against Netexit may be subject to avoidance under operative provisions of the Bankruptcy Code. We intend to vigorously defend against any efforts to invalidate or subordinate our claims against Netexit, but we cannot currently predict the resolution of any litigation with respect to the validity of NorthWestern’s claims against Netexit. Pending the resolution of open claims by Netexit creditors, the proceeds from the sale remain at Netexit and distributions to NorthWestern could be delayed until the effective date of Netexit’s liquidating plan of reorganization.

We are also attempting to sell our interest in Montana Megawatts I, LLC, or MMI, our indirect wholly-owned subsidiary that owns the Montana First Megawatts generation project, a partially constructed, 260 megawatt, natural gas-fired, combined-cycle electric generation facility located in Great Falls, Montana. On February 17, 2005, our subsidiary, NorthWestern Generation I, LLC, the sole member of MMI, entered into a non-binding letter of intent to sell all of the member interest of MMI to a

non-affiliated third party. Under the terms of the letter of intent, MMI will sell all generation assets. The net effect of this arrangement is that the buyer will acquire MMI and all remaining nongeneration assets held by the entity. Any sale will be subject to board approval.

In anticipation of the letter of intent to sell MMI, we entered into an exclusive arrangement with a major electric generation equipment broker to market MMI’s generation assets. We anticipate that a sale of this equipment will be completed on or before June 30, 2005. Any sale will be subject to board approval. Based upon an evaluation of the generation equipment market by our equipment broker, we recorded a $10 million impairment charge to reduce the assets to their estimated realizable value in December 2004.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s discussion and analysis of financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions, including those related to goodwill, qualifying facilities liabilities, impairment of long-lived assets and revenue recognition, among others. Actual results could differ from those estimates.

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

Fresh Start Reporting

Upon applying fresh-start reporting, a new reporting entity (the Successor Company) is deemed to be created and the recorded amounts of assets and liabilities are adjusted to reflect their estimated fair values. The enterprise value was determined using various valuation methods including, (i) reviewing historical financial information (ii) comparing us and our projected performance to the market values of comparable companies, (iii) performing industry precedent transaction analysis, and (iv) considering certain economic and industry information relevant to the operating business. The estimated enterprise value is highly dependent upon achieving the future financial results set forth in the projections and is necessarily based on a variety of estimates and assumptions which, though considered reasonable by management, may not be realized and are inherently subject to significant business and economic uncertainties and contingencies, many of which are beyond our control.

Goodwill

We believe that the accounting estimate related to determining the fair value of goodwill, and thus any impairment, is a “critical accounting estimate” because: (i) it is highly susceptible to change from period to period since it requires company management to make cash flow assumptions about future revenues, operating costs and discount rates over an indefinite life; and (ii) recognizing an impairment has had a significant impact on the assets reported on our balance sheet and our operating results. Management’s assumptions about future sales margins and volumes require significant judgment because actual margins and volumes have fluctuated in the past and are expected to continue to do so. In estimating future margins, we use our internal budgets.

Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets, was issued during 2001 and is effective for all fiscal years beginning after December 15, 2001. According to the guidance set forth in SFAS No. 142, we are required to evaluate our goodwill and indefinite-lived

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

Qualifying Facilities Liability

Certain Qualifying Facilities, or QFs, require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. As of December 31, 2004, our gross contractual obligation related to the QFs is approximately $1.7 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable though rates authorized by the MPSC, totaling approximately $1.3 billion though 2029. Upon adoption of fresh-start reporting, we recomputed the fair value of the liability to be approximately $143.8 million based on the net present value of the difference between our obligations under the QFs and the related amount recoverable. At December 31, 2004, the liability was $143.4 million. The determination of the discount rate used to establish this liability was a significant assumption. We determined the appropriate discount rate to be 7.75%, in accordance with Statement of Financial Accounting Concepts No. 7, Using Cash Flow Information and Present Value in Accounting Measures. We believe that 7.75% approximates the rate we could have negotiated with an independent lender for a similar transaction under comparable terms and conditions as of the fresh-start reporting date. In computing the liability, we have also had to make various estimates in relation to contract costs, capacity utilization, and recoverable amounts. Actual utilization and regulatory changes may significantly impact our results of operations.

Long-lived Assets

We evaluate our property, plant and equipment for impairment whenever indicators of impairment exist. SFAS No. 144 requires that if the sum of the undiscounted cash flows from a company’s asset, without interest charges, is less than the carrying value of the asset, impairment must be recognized in the financial statements. If an asset is deemed to be impaired, then the amount of the impairment loss recognized represents the excess of the asset’s carrying value as compared to its estimated fair value, based on management’s assumptions and projections.

During the fourth quarter of 2004, we recorded an additional impairment charge of $10.0 million due to further decline in the estimated realizable value of our investment in our Montana First Megawatts project. We had recorded impairment charges of $12.4 million and $35.7 million in previous years.

Revenue Recognition

Revenues are recognized differently depending on the various jurisdictions. For our South Dakota and Nebraska operations, as prescribed by the respective regulatory authorities, electric and natural gas utility revenues are based on billings rendered to customers. For our Montana operations, as prescribed by the MPSC, operating revenues are recorded monthly on the basis of consumption or services rendered. Customers are billed on a monthly cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electric and natural gas services delivered to the customers but not yet billed at month-end.

Regulatory Assets and Liabilities

Our regulated operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts

recoverable for natural gas and default electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. If any part of our operations become no longer subject to the provisions of SFAS No. 71, the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities would need to be evaluated. In addition, we would need to determine if there was any impairment to the carrying costs of deregulated plant and inventory assets.

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

Pension and Postretirement Benefit Plans

Our reported costs of providing pension and other postretirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and other postretirement benefit costs, for example, are impacted by actual employee demographics (including age and compensation levels), the level of contributions we make to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of the plans may also impact current and future pension and other postretirement benefit costs. Pension and other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the postretirement benefit obligation and postretirement costs.

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

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

Income Taxes

We have realized approximately $558 million of cancellation of indebtedness (COD) income. For tax purposes, we are not required to include any COD income in our taxable income when we emerge, however we will be required to reduce certain tax attributes up to the amount of COD income. As a general rule, tax attributes are reduced in the following order: (a) net operating losses (NOLs), (b) most tax credits, (c) capital loss carryovers, (d) tax basis in assets, and (e) foreign tax credits. Under a certain tax code election, we are considering reducing a combination of attributes, consisting of tax basis in depreciable assets and NOLs. While we have made assumptions related to the reduction of these attributes, the ultimate amounts of each reduction will not be determined until we finalize our tax return for 2004, which will be filed by September 15, 2005. Changes in our assumptions related to these attribute reductions could materially impact the tax basis of our depreciable assets and the amount of NOLs available to utilize against future income. Additionally, under our plan of reorganization, there has been an “ownership change” as defined under Internal Revenue Code Section 382 in connection with our emergence from bankruptcy, which provides an annual limit on the ability to utilize our NOLs. Based on this limitation and our current assumptions, we estimate the majority of our NOLs will be utilized. Upon the adoption of fresh-start reporting, we have removed substantially all of the valuation allowance against our deferred tax assets because, based on our current projections, we believe it is more likely than not that these assets will be realized. While we believe our assumptions are reasonable, changes to these assumptions could materially impact our results.

Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. Management has established a liability based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, management evaluates the liability in light of any additional information and adjusts the balance as necessary to reflect the best estimate of the future outcomes. We believe our established liability is appropriate for estimated exposures, however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our consolidated statement of operations and provision for income taxes.

RESULTS OF OPERATIONS

The following is a summary of our results of operations in 2004, 2003, and 2002. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment. The results of operations for the year ended December 31, 2002, include the results of our Montana operations since February 1, 2002, the effective date of the acquisition.

OVERALL CONSOLIDATED RESULTS

As noted above, the adoption of fresh-start reporting has impacted the comparability of our financial statements. As the impact to our statement of operations is limited to the Reorganization Items line detail, we have combined the Successor Company’s results from November 1, 2004 through December 31, 2004 with the results of the Predecessor Company from January 1, 2004 through October 31, 2004 for comparison and analysis purposes. The following table reflects the unaudited combined data for the audited Successor Company and the audited Predecessor Company periods (in thousands):

	Successor Company				Predecessor Company				Unaudited Successor and Predecessor Combined				Predecessor Company
	November 1-				January 1-				Year Ended
	December 31,				October 31,				December 31,				December 31,				December 31,
	2004				2004				2004				2003				2002
OPERATING REVENUES		$	205,952			$	833,037			$	1,038,989			$	1,012,515			$	783,744
COST OF SALES		116,775				447,054				563,829				535,667				341,526
GROSS MARGIN		89,177				385,983				475,160				476,848				442,218
OPERATING EXPENSES
Operating, general and administrative		35,958				185,782				221,740				239,716				213,309
Property and other taxes		10,766				54,369				65,135				67,542				54,909
Depreciation		12,174				60,674				72,848				70,252				63,240
Amortization of intangibles		—				—				—				—				19
Reorganization items		437				(533,063		)		(532,626		)		8,266				—
Impairment on assets held for sale		10,000				—				10,000				12,399				35,729
TOTAL OPERATING EXPENSES		69,335				(232,238		)		(162,903		)		398,175				367,206
OPERATING INCOME		19,842				618,221				638,063				78,673				75,012
Interest Expense		(11,021		)		(72,822		)		(83,843		)		(147,626		)		(98,010		)
Gain (Loss) on Debt Extinguishment		(21,310		)		—				(21,310		)		3,300				(20,688		)
Investment Income and Other		1,039				2,121				3,160				(5,977		)		(5,481		)
Income (Loss) From Continuing Operations Before Income Taxes		(11,450		)		547,520				536,070				(71,630		)		(49,167		)
Benefit for Income Taxes		4,930				1,369				6,299				48				39,811
Income (Loss) From Continuing Operations		(6,520		)		548,889				542,369				(71,582		)		(9,356		)
Discontinued Operations, Net of Taxes and Minority Interests		(424		)		2,488				2,064				(42,143		)		(854,586		)
Net Income (Loss)		(6,944		)		551,377				544,433				(113,725		)		(863,942		)
Minority Interests on Preferred Securities of Subsidiary Trusts		—				—				—				(14,945		)		(28,610		)
Dividends and Redemption Premium on Preferred Stock		—				—				—				—				(391		)
Earnings (Losses) on Common Stock		$	(6,944	)		$	551,377			$	544,433			$	(128,670	)		$	(892,943	)

Year Ended December 31, 2004 (Unaudited Combined) Compared with Year Ended December 31, 2003

Consolidated revenues in 2004 were $1.0 billion, an increase of $26.5 million, or 2.6%, over 2003. The increase in our regulated business is primarily due to higher supply costs offset by a decrease in sales for resale. The increase in supply costs includes an increase in our regulated gas revenues of $36.9 million and an increase in our regulated electric revenues of $17.5 million. The regulated revenue increase due to supply costs was more than offset by a $47.1 million decrease in sales for resale revenue. In addition, our unregulated gas segment revenues increased $36.3 million from a 29.3% increase in sales, and our unregulated electric revenues increased $18.8 million due primarily to a renegotiated power purchase agreement with a wholesale customer. Offsetting this increase was a $30.7 million increase in intersegment eliminations primarily due to increased sales by our unregulated electric segment to our regulated electric segment.

Consolidated cost of sales in 2004 was $563.8 million, an increase of $28.2 million, or 5.3%, over 2003. Consistent with revenue, the increase in our regulated business was primarily due to higher supply costs offset by a decrease in sales for resale. The increase in supply costs includes an increase of $27.6 million in our regulated gas segment and a $31.5 million increase in our regulated electric segment. The regulated cost increase was more than offset by a $47.1 million decrease in sales for resale costs. In addition our unregulated gas costs increased $39.6 million from higher sales volumes and our unregulated electric supply costs increased $7.2 million. Partially offsetting this increase was a $30.6 million increase in intersegment eliminations.

Consolidated gross margin in 2004 was $475.2 million, as compared to $476.8 million in 2003. Margins as a percentage of revenues decreased to 45.7% for 2004, from 47.1% for 2003. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers. Margins in our regulated electric segment decreased $15.2 million primarily due to out of market costs associated with QF contracts, which increased approximately $10.8 million in 2004 as compared to 2003. This was offset by our unregulated electric segment margins, which increased $14.7 million primarily due to a renegotiated power purchase agreement with a wholesale customer. In addition, our regulated gas margin improved by $2.4 million due to an increase in transportation revenues and a decrease in disallowed costs, offset by a loss on a fixed price sales contract and a decrease in general business margin. Our unregulated gas margin decreased by $3.3 million primarily due to a loss on a fixed price sales contract and higher supply costs.

When comparing our 2004 operating expense with 2003, several material items unrelated to our continuing operations should be considered. The 2004 results include the effects of our bankruptcy reorganization items and an impairment charge. The following table summarizes the impact of the items noted above (in millions):

	Unaudited 2004				2003		Change		Change %
Reorganization Items		$	(532.6	)	$	8.3	$540.9			N/A
Impairment on assets held for sale		10.0			12.4		2.4			19.4	%
Continuing Operations
Operating, administrative and general		221.7			239.7		18.0			7.5
Property and other taxes		65.1			67.5		2.4			3.6
Depreciation		72.9			70.3		(2.6	)		(3.7	)
Total Operating Expenses		$	(162.9	)	$	398.2

Reorganization items associated with our emergence from bankruptcy includes the following:

· $558.1 million gain from the cancellation of indebtedness through fresh-start reporting;

· $13.9 million gain on the discharge of other liabilities through fresh-start reporting; partially offset by

· $39.3 million in professional fees and expenses, offset by interest earned. The comparable 2003 reorganization items of $8.3 million represents professional fees and expenses incurred after our bankruptcy filing.

The asset impairment charges of $10.0 million and $12.4 million in 2004 and 2003, respectively, related to a decline in the estimated realizable value of our Montana First Megawatts generation assets.

Consolidated operating, general and administrative expenses related to our continuing operations decreased $18.0 million, or 7.5%, from the prior year. Since filing for bankruptcy on September 14, 2003, we present reorganization professional fees and expenses separately from operating, general and administrative expenses on the income statement. While all reorganization related expenses during 2004 are presented separately on the income statement, there were approximately $6.1 million for legal and other professional fees included in operating, general and administrative expenses during 2003 due to our efforts to restructure the company prior to filing for bankruptcy. Additionally, 2003 included an $8.4 million increase to our environmental reserves based on the results of a third-party evaluation. Beginning in 2005 we expect our operating, general and administrative expenses to decrease by approximately $10.0 million annually due to the extension of our operating lease for the Colstrip Unit 4 generation facility. In addition, depreciation of leasehold improvements will also decrease by approximately $1.0 million in 2005 due to this lease extension. However, we expect these reductions to be offset by approximately $10.0 million of increased annual pension expense based on our current funding estimates over the next five years.

Consolidated operating income in 2004 was $638.1 million, as compared to $78.7 million in 2003. This change was primarily due to the reorganization items noted above.

Consolidated interest expense in 2004 was $83.8 million, a decrease of $63.8 million, or 43.2%, from 2003. These decreases were primarily attributable to our cessation of recording of interest expense on our unsecured debt due to our bankruptcy filing, as well as an October 2003 amendment reducing the interest rate of our prepetition senior secured term loan. We anticipate further reductions in interest expense during 2005 due to our financing transaction on November 1, 2004, which replaced our $390 million senior secured term loan with lower interest rate debt.

Consolidated loss on extinguishment of debt in 2004 was $21.3 million, compared to a gain of $3.3 million in 2003. This loss was the result of writing off financing costs associated with our senior secured term loan that we replaced on November 1, 2004. The $3.3 million gain in 2003 related to the sale of One Call Locators, Ltd., for which we accepted trust preferred obligated securities of NorthWestern as partial consideration.

Consolidated investment and other income increased $9.1 million from 2003, primarily due to a prior year impairment charge to reduce a note receivable to an estimated recoverable amount.

Consolidated earnings on common stock in 2004 were $544.4 million, as compared to losses of $128.7 million in 2003. This improvement is primarily related to the reorganization items discussed above. Also contributing to the increase was improved results from discontinued operations of $44.2 million, a decrease of $14.9 million from interest expense on preferred securities of subsidiary trusts due to our bankruptcy filing, and a tax benefit of $6.3 million.

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

Consolidated revenues in 2003 were $1.0 billion, an increase of $228.8 million, or 29.2%, over 2002. The January 2003 results of our Montana operations contributed approximately $68.6 million of this increase. The remaining $160.2 million increase was primarily due to a $74.6 million increase in revenue recovered for purchased power supply costs and a $9.3 million increase in transmission and distribution revenue from our regulated electric utility segment, a $57.3 million increase in revenue recovered for purchased gas costs from our regulated natural gas segment, and a $29.0 million increase in unregulated gas revenues due to a 10.0% increase in volumes at a 5.8% higher average price. Partially offsetting this increase was a $9.4 million increase in intersegment eliminations.

Consolidated costs of sales in 2003 were $535.7 million, an increase of $194.1 million, or 56.8%, over 2002. The January 2003 results of our Montana operations contributed approximately $33.5 million of this increase. The remaining $160.6 million increase was primarily due to a $73.8 million increase in purchased power supply costs from our regulated electric segment, a $65.7 million increase in purchased gas costs from our regulated natural gas segment including $8.0 million of disallowed gas costs as a result of a July 3, 2003 interim order from the MPSC, and a $28.3 million increase in unregulated gas supply costs from higher sales. Purchased power supply costs, which are typically recovered in rates, increased as a result of new power supply agreements effective July 1, 2002. Partially offsetting this increase was a $9.2 million increase in intersegment eliminations.

Consolidated gross margin in 2003 was $476.8 million, an increase of $34.6 million, or 7.8%, over the 2002 gross margin of $442.2 million. The January 2003 results of our Montana operations contributed $35.1 million of this increase. In addition, the increased regulated electric transmission and distribution revenues were offset by an $8.0 million write-off as a result of a July 3, 2003, interim order from the MPSC disallowing the recovery of certain gas supply costs. Margins as a percentage of revenues, after excluding the January 2003 results of our Montana operations, decreased to 46.8% for 2003, from 56.4% for 2002. Gross margin as a percentage of revenue is impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

Consolidated operating, general and administrative expenses for 2003 were $239.7 million, an increase of $26.4 million, or 12.4%, over 2002. The January 2003 results of our Montana operations contributed approximately $11.5 million of this increase. Also contributing were increased legal and other professional fees related to our reorganization efforts prior to our bankruptcy filing of approximately $6.1 million and an increase in our environmental reserve of $8.4 million based on the results of a third-party evaluation.

Consolidated property and other taxes for 2003 were $67.5 million, an increase of $12.6 million over 2002. The January 2003 results of our Montana operations contributed approximately $4.4 million of this increase. Depreciation for 2003 was $70.3 million, an increase of $7.0 million over 2002. The January 2003 results of our Montana operations contributed approximately $4.6 million of this increase. The remaining increases represent higher property values and increased property, plant and equipment.

Consolidated reorganization items of $8.3 million in 2003 consist of professional fees related to our reorganization efforts incurred after our bankruptcy filing.

Consolidated impairments on assets held for sale were $12.4 million in 2003, as compared to $35.7 million in 2002. These charges are related to declines in the estimated realizable value of our Montana First Megawatts generation assets.

Consolidated operating income in 2003 was $78.7 million, an increase of $3.7 million, or 4.9%, as compared to $75.0 million in 2002. The January 2003 results of our Montana operations contributed approximately $14.5 million of this increase, offset by higher operating expenses discussed above.

Consolidated interest expense was $147.6 million, an increase of $49.6 million, or 50.6% from $98.0 million in 2002 due primarily to a $390 million senior secured term loan entered into in February 2003.

Consolidated gain on debt extinguishment was $3.3 million as compared to a loss of $20.7 million in 2002. The 2003 gain was related to the sale of One Call Locators, Ltd., while the 2002 loss was related to a debt refinancing transaction.

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

Factors Affecting Results of Continuing Operations

Our revenues may fluctuate substantially with changes in supply costs, which are typically collected in rates from customers. Revenues are also impacted by customer usage, which is primarily affected by weather, growth, and mix of customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Weather

Weather affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand, while mild winters reduce demand. The weather’s effect is measured using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily actual temperature is less than the baseline. The following is a table of our heating degree-days variance percent by service territory:

	2004 as compared to:		2003 as compared to:
	Prior Year	Historic Average	Prior Year	Historic Average
Montana	Remained flat	3% warmer	7% warmer		5% warmer
South Dakota	7% warmer	11% warmer	Remained flat		4% warmer
Nebraska	3% warmer	9% warmer	3% warmer		7% warmer

Customer Growth

The following is a table of our regulated general business average customer counts by service territory:

	Regulated Electric					Regulated Natural Gas
	Montana		South Dakota & Nebraska			Montana		South Dakota & Nebraska
2004	308,553			58,122		163,511			81,597
2003	303,166			57,752		160,351			81,235
Change	5,387			370		3,160			362
Percent Change	1.8	%		0.6	%	2.0	%		0.4	%
2003	303,166			57,752		160,351			81,235
2002	297,676			57,406		157,059			81,247
Change	5,490			346		3,292			(12	)
Percent Change	1.8	%		0.6	%	2.1	%		0.0	%

REGULATED OPERATIONS

REGULATED ELECTRIC UTILITY SEGMENT

Year Ended December 31, 2004 (Unaudited Combined) Compared with Year Ended December 31, 2003

	Results (in millions)												Volumes—MWH (in thousands)
	2004			2003			Change			Change %			2004	2003	Change		Change %
Electric supply revenue	$	248.0		$	230.5		$	17.5			7.6	%
Transmission & distribution revenue	267.3			267.3			—				—
Rate schedule revenue	515.3			497.8			17.5				3.5		9,228	8,901		327		3.7	%
Sales for resale	—			47.1			(47.1		)		(100.0	)
Transmission	38.6			43.6			(5.0		)		(11.5	)
Wholesale	12.1			8.0			4.1				51.3		402	304		98		32.2
Miscellaneous	5.9			5.1			0.8				15.7
Total Revenues	571.9			601.6			(29.7		)		(4.9	)	9,630	9,205		425		4.6	%
Supply costs	255.8			224.3			31.5				14.0
Sales for resale costs	—			47.1			(47.1		)		(100.0	)
Other cost of sales	16.8			15.7			1.1				7.0
Total Cost of Sales	272.6			287.1			(14.5		)		(5.1	)
Gross Margin	$	299.3		$	314.5		$	(15.2	)		(4.8	)%
% GM/Rev	52.3		%	52.3		%

Rate Schedule Revenue

Rate schedule revenue consists of revenue earned from customers receiving supply, transmission, and distribution of electricity. Customers who have not chosen other commodity suppliers are billed fully bundled rates for supplying, transmitting, and distributing electricity. Customers that have chosen other commodity suppliers are billed for moving their electricity across our lines and their distribution revenues are reflected as rate schedule revenue, while their transmission revenues are reflected as transmission revenue.

Electric supply revenue increased $17.5 million, or 7.6% in 2004. This increase consisted of $8.8 million related to increased supply costs and an $8.7 million increase in volumes. The volume increase was entirely attributable to large industrial customers. While transmission and distribution revenue remained flat, a decrease in volumes used by our residential customers was largely offset by a $2.8 million increase in demand charges, which are charges for the largest amount of electricity used during a specific brief period of time.

Sales for Resale

Revenue from sales for resale decreased $47.1 million because of a change in accounting for contracts that do not physically deliver. We no longer reflect electric sales for resale, as revenues are netted against cost of sales.

Transmission Revenue

Transmission revenue consists of revenue earned for transmitting energy across our lines for customers who select other suppliers and for off-system, or open access, customers. Transmission revenues in Montana can fluctuate substantially from year to year based on market conditions in surrounding states. For example, if energy costs are substantially higher in California than in states to our east, suppliers may

realize more profit by transmitting electricity across our lines, than by buying electricity in California. We refer to these differences as price differentials. A renegotiated transmission contract and the absence of price differentials in the market caused the $5.0 million, or 11.5%, decrease in transmission revenue.

Wholesale Revenues

Wholesale revenues are derived from our joint ownership in generation facilities. Excess power not used by our South Dakota customers is sold in the wholesale market. These revenues increased $4.1 million, or 51.3%, because of a 32.3% increase in volumes sold in the secondary markets at 15.8% higher average prices. We had more energy available to sell in the secondary markets because of increased plant availability with less downtime for repairs and maintenance.

Gross Margin

Gross margin in 2004 decreased $15.2 million, or 4.8%, primarily due to increases in out of market costs of approximately $10.8 million associated with our QF contracts. These costs can differ substantially from year to year depending on the actual output of the QF’s as compared to the estimates we used in recording our QF liability. We recognized $1.8 million of expense associated with QF out of market costs in 2004, as actual output exceeded our estimate. We recognized a gain of approximately $9.0 million in 2003 as actual QF output was much lower than our estimate. We anticipate output by the QFs will be at similar levels as 2004 for the foreseeable future. The decrease in transmission revenue also contributed to the gross margin decrease.

Margin as a percentage of revenue was 52.3% for 2004 and 2003, respectively. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

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

	Results (in millions)												Volumes—MWH (in thousands)
	2003			2002			Change			Change %			2003	2002	Change			Change %
Electric supply revenues	$	230.5		$	166.6		$	63.9			38.3	%
Transmission & distribution revenue	267.3			240.8			26.5				11.0
Rate schedule revenue	497.8			407.4			90.4				22.2		8,901	7,929		972			12.3	%
Sales for resale	47.1			15.3			31.8				207.8
Transmission	43.6			41.2			2.4				5.8
Wholesale sales for resale	8.0			7.4			0.6				8.1		304	348		(44	)		(12.6	)
Miscellaneous	5.1			5.3			(0.2		)		(3.8	)
Total Revenues	601.6			476.6			125.0				37.0		9,205	8,277		928			11.2	%
Supply costs	224.3			161.5			62.8				38.9
Sales for resale costs	47.1			15.3			31.8				207.8
Other cost of sales	15.7			13.0			2.7				20.8
Total Cost of Sales	287.1			189.8			97.3				51.3
Gross Margin	$	314.5		$	286.8		$	27.7			9.7	%
% GM/Rev	52.3		%	60.2		%

Rate Schedule Revenue

Electric supply revenue increased $63.9 million, or 38.3% in 2003. The January 2003 results of our Montana operations contributed approximately $17.9 million of this increase. The remaining $46.0 million increase consisted of $38.3 million due to increased supply costs and a $7.7 million increase in volumes.

Transmission and distribution revenue increased $26.5 million, or 11.0% from 2002. The January 2003 results of our Montana operations contributed approximately $17.2 million of this increase. The remaining $9.3 million increase was primarily caused by a 12.3% increase in volumes crossing all customer classifications and a $1.9 million increase in demand charges, which are charges for the largest amount of electricity used during a specific brief period of time.

Sales for Resale

Revenue from sales for resale increased $31.8 million because of an increase in sales of excess purchased power in the secondary markets. As the sales of excess purchased power are also reflected in cost of sales, there is no gross margin impact.

Transmission Revenue

The January 2003 results of the Montana operations was the primary reason for the $2.4 million increase in transmission revenue.

Wholesale Revenues

Wholesale revenues increased $0.6 million, or 8.1%, because of 22.0% higher average prices in the secondary markets partially offset by a 12.6% decrease in volumes. We had less energy available to sell in the secondary markets because of increased downtime for repairs and maintenance in 2003 as compared to 2002.

Gross Margin

Gross margin in 2003 was $314.5 million, an increase of $27.7 million, or 9.7%, over the 2002 gross margin of $286.7 million. The January 2003 results of our Montana operations contributed $20.2 million of this increase. The remaining increase of $7.5 million was primarily due to the higher transmission and distribution revenue.

Margin as a percentage of revenue decreased to 52.3% for 2003, from 60.2% for 2002. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

REGULATED NATURAL GAS UTILITY SEGMENT

Year Ended December 31, 2004 (Unaudited Combined) Compared with Year Ended December 31, 2003

	Results (in millions)												Volumes—MMbtu (in thousands)
	2004			2003			Change			Change %			2004	2003	Change			Change %
Gas supply revenue	$	171.2		$	141.5		$	29.7			21.0	%
Transportation, distribution & storage revenue	96.5			96.0			0.5				0.5
Rate schedule revenue	267.7			237.5			30.2				12.7		28,886	29,699		(813	)		(2.7	)%
Sales for resale	25.8			23.6			2.2				9.3
Transportation	16.9			14.5			2.4				16.6
Miscellaneous	1.3			3.5			(2.2		)		(62.9	)
Total Revenues	311.7			279.1			32.6				11.7		28,886	29,699		(813	)		(2.7	)%
Supply costs	177.4			149.8			27.6				18.4
Sales for resale costs	25.8			23.6			2.2				9.3
Other cost of sales	2.0			1.6			0.4				25.0
Total Cost of Sales	205.2			175.0			30.2				17.3
Gross Margin	$	106.5		$	104.1		$	2.4			2.3	%
% GM/Rev	34.2		%	37.3		%

Rate Schedule Revenue

Rate schedule revenue consists of revenue earned from customers receiving supply, transportation, and distribution of natural gas. Customers who have not chosen other commodity suppliers are billed fully bundled rates for supplying, transporting, and distributing natural gas. Customers that have chosen other commodity suppliers are billed for moving their natural gas through our pipelines and their distribution revenues are reflected as rate schedule revenue, while their transportation revenues are reflected as transportation revenue.

Gas supply revenues increased $29.7 million, or 21.0% in 2004. This increase consisted of $34.5 million due to increased supply costs partially offset by a $4.8 million, or 2.7% decrease in volumes. Transmission, distribution and storage revenue from 2003 remained relatively flat.

Sales for Resale

Revenue from sales for resale increased $2.2 million, or 9.3%, due to sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.

Transportation Revenue

Gross Margin

Gross margin increased $2.4 million, or 2.3%, primarily due to the $2.4 million increase in transportation revenue. Other items reducing gross margin were a $2.8 million loss on a fixed price sales contract and a decrease in general business margin of $2.3 million. These were offset by a decrease in

disallowed gas costs of $5.2 million as we wrote off $2.8 million in gas costs disallowed by the MPSC in 2004 as compared to $8.0 million in 2003.

On July 3, 2003 the MPSC issued orders disallowing the recovery of certain gas supply costs for the 2003 and 2004 tracker years. The MPSC also rejected a motion for reconsideration filed by us on July 14, 2003. We filed suit in Montana state court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. A tracker year runs from July to June, and because of the MPSC orders, we were disallowed recovery of $6.2 million and $4.6 million for the 2003 and 2004 tracker years, respectively. We are currently involved in negotiations with the MPSC over the disallowed gas costs during 2003 and 2004 in an attempt to recover a portion of these costs.

Margin as a percentage of revenue decreased to 34.2% for 2004, from 37.3% for 2003. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.

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

	Results (in millions)												Volumes MMbtu (in thousands)
	2003			2002			Change			Change %			2003	2002	Change	Change %
Gas supply revenues	$	141.5		$	97.8		$	43.7			44.7	%
Transportation, distribution & storage revenue	96.0			86.6			9.4				10.9
Rate schedule revenue	237.5			184.4			53.1				28.8		29,699	26,915	2,784		10.3	%
Sales for resale	23.6			0.8			22.8				2850.0
Transportation	14.5			15.0			(0.5		)		(3.3	)
Miscellaneous	3.5			1.7			1.8				105.9
Total Revenues	279.1			201.9			77.2				38.2		29,699	26,915	2,784		10.3	%
Supply costs	149.8			97.6			52.2				53.5
Sales for resale costs	23.6			0.8			22.8				2850.0
Other cost of sales	1.6			1.4			0.2				14.3
Total Cost of Sales	175.0			99.8			75.2				75.4
Gross Margin	$	104.1		$	102.1		$	2.0			2.0	%
% GM/Rev	37.3		%	50.6		%

Rate Schedule Revenue

Gas supply revenue increased $43.7 million, or 44.7%, with the January 2003 results of our Montana operations contributing approximately $9.2 million of the increase. The remaining increase consisted of $35.6 million due to increased supply costs partially offset by a $1.1 million decrease in volumes.

Transportation, distribution and storage revenue increased $9.4 million, or 10.9%, almost entirely due to the January 2003 results of our Montana operations.

Sales for Resale

Revenue from sales for resale increased $22.8 million due to sales of excess purchased gas in the secondary markets. As the sales for resale are also reflected in cost of sales, there is no gross margin impact.

Transportation Revenue

Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation revenue decreased $0.5 million, or 3.3%. The January 2003 results of our Montana operations contributed an increase of approximately $1.0 million. Offsetting this was a decrease for the remainder of the year in volumes transported for others.

Gross Margin

Gross margin in 2003 was $104.1 million, an increase of $2.0 million over the 2002 gross margin of $102.1 million. The January 2003 results of our Montana operations contributed an increase of $10.9 million. This was offset by a decrease of $8.9 million primarily due to the MPSC’s disallowance of gas supply costs.

Margin as a percentage of revenue decreased to 37.3% for 2003, from 50.6% for 2002. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they have only impact gross margin amounts if they cannot be passed through to customers.

UNREGULATED OPERATIONS

UNREGULATED ELECTRIC UTILITY SEGMENT

Our unregulated electric segment reflects the operations of our Colstrip Unit 4 division and CFB’s results arising from the ownership and operation of the two megawatt Milltown Dam hydroelectric facility.

Year Ended December 31, 2004 (Unaudited Combined) Compared with Year Ended December 31, 2003

Results (in millions)

Volumes—MWH (in thousands)

2004

2003

Change

Change %

2004

2003

Change

Change %

Total Revenues

88.7

69.9

18.8

26.9

1,794

1,701

5.5%

Supply costs

23.7

16.5

7.2

43.6

Wheeling costs

3.2

6.3

(3.1

)

(49.2

)

Total Cost of Sales

26.9

22.8

4.1

18.0

Gross Margin

61.8

47.1

14.7

31.2

% GM/Rev

69.6

67.4

Revenue

Unregulated electric revenue increased $18.8 million, or 26.9%, due primarily to a renegotiated power purchase agreement (PPA) that Colstrip Unit 4 has with a wholesale customer. Under the PPA, we buyback energy at a below-market fixed price and sell it to another wholesale customer under a favorable fixed price sales contract.

Gross Margin

Gross margin increased $14.7 million, or 31.2%, primarily due to the renegotiated PPA partially offset by a 43.6% increase in supply costs. We also incurred less wheeling costs as a result of the PPA.

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

Results (in millions)

Volumes—MWH (in thousands)

2003

2002

Change

Change %

2003

2002

Change

Change %

Total Revenues

69.9

62.7

7.2

11.5

1,701

1,494

207

13.9

Supply costs

16.5

13.8

2.7

19.6

Wheeling costs

6.3

5.9

0.4

6.8

Total Cost of Sales

22.8

19.7

3.1

15.7

Gross Margin

47.1

43.0

4.1

9.5

% GM/Rev

67.4

68.5

Revenue

Unregulated electric revenue increased $7.2 million, or 11.5%. The January 2003 results of our Montana operations contributed an increase of approximately $6.2 million with the remaining increase due to a 3.7% increase in volumes. We had more energy to sell due to increased plant availability in 2003 with less down time for repairs and maintenance.

Gross Margin

Gross margin increased $4.1 million, or 9.5%, primarily due to the higher volumes.

UNREGULATED NATURAL GAS SEGMENT

Our unregulated natural gas segment reflects the operations of our subsidiary, NSC, which markets gas supply services to large volume customers and, through its subsidiary, operates a pipeline that provides gas supply and distribution services. In addition, this segment also reflects the results of our unregulated Montana retail propane operations.

Year Ended December 31, 2004 (Unaudited Combined) Compared with Year Ended December 31, 2003

Results (in millions)

Volumes—MMbtu (in thousands)

2004

2003

Change

Change %

2004

2003

Change

Change %

Total Revenue

137.0

100.7

36.3

36.0

19,978

15,450

4,528

29.3

Supply costs

128.2

88.6

39.6

44.7

Gross Margin

8.8

12.1

(3.3

)

(27.3

% GM/Rev

6.4

12.0

Revenue

Unregulated natural gas revenue increased $36.3 million, or 36.0%, due primarily to a $29.7 million, or 29.3%, increase in volumes and a $7.2 million, or 7.6%, increase in average price.

Gross Margin

Gross margin decreased $3.3 million, or 27.3%, primarily due to higher supply costs as compared to 2003 and a $2.3 million loss recorded on out of market fixed price sales contracts.

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

Results (in millions)

Volumes—MMbtu (in thousands)

2003

2002

Change

Change %

2003

2002

Change

Change %

Total Revenues

100.7

71.3

29.4

41.2

15,450

14,600

850

5.8

Supply costs

88.6

60.3

28.3

46.9

Gross Margin

12.1

11.0

1.1

10.0

% GM/Rev

12.0

15.4

Revenue

Unregulated natural gas revenue increased $29.4 million, or 41.2%, due to a $5.2 million, or 5.8% increase in volumes and a $24.3 million, or 37.6% increase in average price.

Gross Margin

Gross margin increased $1.1 million, or 10.0%, primarily due to the higher volumes.

ALL OTHER OPERATIONS

All Other operations primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments, and any eliminating amounts. The miscellaneous service activities principally include product sales and maintenance contracts in areas such as home monitoring devices and appliances.

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Revenues for the segment in 2004 were $2.3 million compared to $3.0 million in 2003. Gross margin in 2004 was $0.6 million compared to $0.7 million in 2003.

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

Revenues for the segment in 2003 were $3.0 million compared to $3.1 million in 2002. Gross margin in 2003 was $0.7 million compared to $0.6 million in 2002.

DISCONTINUED OPERATIONS

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

DISCONTINUED COMMUNICATIONS SEGMENT OPERATIONS

On November 25, 2003, we sold substantially all the assets and business of Expanets, Inc. to Avaya, Inc. (Avaya) and retained certain specified liabilities. Thereafter, Expanets, Inc. was renamed Netexit, Inc. On February 24, 2004, Avaya submitted its proposed final calculation of the post-closing working capital adjustment required under the sale agreements claiming that Avaya should retain $44.6 million in held-back proceeds plus an additional $4.2 million. Netexit disputed this calculation. As a result of negotiations between Netexit and Avaya, the parties entered into a settlement on April 27, 2004 resulting in additional cash proceeds of $17.5 million paid by Avaya to Netexit. We recorded a gain related to this settlement of $11.5 million in the second quarter of 2004.

current assets of discontinued operations on our consolidated financial statements. Claims aggregating approximately $212 million (excluding equity related claims of approximately $94 million) have been filed against Netexit. NorthWestern’s unsecured debt claims represent $185.2 million of this amount. Netexit filed a proposed liquidating plan of reorganization in February 2005 which provides for a distribution to unsecured creditors of approximately 25% of their allowed claim. If this distribution occurs, then we could receive $40-$50 million upon the ultimate effective date of Netexit’s liquidating plan of reorganization on account of claims filed by NorthWestern against Netexit. However, there are many factors beyond our control which could affect the timing and amount of any distribution on NorthWestern’s Netexit claims including our ability to obtain the support of Netexit’s official committee of unsecured creditors for Netexit’s liquidating plan of reorganization. Netexit may incur significant additional expenses related to the bankruptcy filing and may incur additional losses related to the resolution of open claims. Additionally, Netexit’s creditors committee has indicated that NorthWestern’s claims against Netexit may be subject to avoidance under operative provisions of the Bankruptcy Code. We intend to vigorously defend against any efforts to invalidate or subordinate our claims against Netexit, but we cannot currently predict the resolution of any litigation with respect to the validity of NorthWestern’s claims against Netexit. Pending the resolution of open claims by Netexit creditors, the proceeds from the sale remain at Netexit and distributions to NorthWestern could be delayed until the effective date of Netexit’s liquidating plan of reorganization.

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

	Successor Company				Predecessor Company
	Period Ended								Year Ended December 31,
	November 1- December 31,				January 1- October 31,
	2004				2004				2003			2002
Revenues		$	—			$	—		$	541,211		$	710,452
Income (Loss) before income taxes and minority interests		$	(78	)		$	(8,893	)	$	1,360		$	(422,802	)
Gain (loss) on disposal		—				11,500			(49,250		)	—
Minority interests		—				—			—			11,152
Income tax provision		—				—			—			(22,780		)
Income (Loss) from discontinued operations, net of income taxes and minority interests		$	(78	)		$	2,607		$	(47,890	)	$	(434,430	)

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

DISCONTINUED HVAC SEGMENT OPERATIONS

As of December 31, 2004, Blue Dot had one remaining business. In December 2004, Blue Dot paid us $10 million in cash in partial satisfaction of its dividends payable on preferred stock.

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

	Successor Company				Predecessor Company
	Period Ended								Year Ended December 31,
	November 1- December 31,				January 1- October 31,
	2004				2004				2003			2002
Revenues		$	724			$	28,209		$	400,679			$	471,824
Loss before income taxes and minority interests		$	(248	)		$	(4,282	)	$	(3,356	)		$	(311,674	)
Gain (Loss) on disposal		(98		)		4,163			14,352				—
Minority interests		—				—			—				3,762
Income tax provision		—				—			—				(9,071		)
Income (Loss) from discontinued operations, net of income taxes and minority interests		$	(346	)		$	(119	)	$	10,996			$	(316,983	)

LIQUIDITY AND CAPITAL RESOURCES

The consummation of the Plan resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors. In total, as described in more detail in the Overview, 35.5 million shares of new common stock and 4.6 million warrants were issued in exchange for unsecured debt and other unsecured claims.

During 2004, we used existing cash to repay $83.3 million of debt. On November 1, 2004, concurrent with our emergence from bankruptcy, we entered into a new $225 million credit facility. The credit facility consists of a $125 million, five-year revolving tranche and a $100 million, seven-year term tranche. The revolving tranche replaced our DIP Facility and is available to us for general corporate purposes and for the issuance of letters of credit. Concurrently with the establishment of the new credit facility, we issued $225 million of our 5.875% senior secured notes due November 1, 2014. Borrowings under the term portion of the new credit facility, together with the net proceeds of the notes offering and available cash, were used to repay our $390 million senior secured term loan facility. As of December 31, 2004 we had $26.0 million in letters of credit and no borrowings outstanding on the revolving tranche.

We anticipate repaying $73.3 million of 2005 debt maturities with cash from operations. We are focused on maintaining a strong liquidity position and strengthening our balance sheet, thereby improving our credit profile. We believe that our cash on hand, operating cash flows, and borrowing capacity (currently approximately $100 million remaining revolver availability), taken as a whole, provide sufficient resources to fund our ongoing operating requirements, 2005 debt maturities, anticipated dividends and estimated future capital expenditures.

In addition, we anticipate receiving approximately $20-$25 million from the sale of MMI’s existing generation equipment.

Credit Ratings

Standard & Poor’s Ratings Group (S&P), Moody’s Investors Service (Moody’s) and Fitch Investors Service (Fitch) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of March 1, 2004 ratings with our agencies are as follows:

	Senior Secured Rating		Issuer Rating		Outlook
S&P		BB		BB-	Positive
Moody’s		Ba1		Ba2	Stable
Fitch		BB+		—	Positive

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us, and impacts our trade credit availability.

Cash Flows

Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas sales and transportation services generally exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows from the electric business during the summer cooling season and external financing, is used to purchase natural gas to place in storage for heating season deliveries, perform necessary maintenance, and make capital improvements in plant.

As noted above, fresh-start reporting has impacted the comparability of our financial statements. As fresh-start reporting had no impact to our cash flows, we have combined the cash flows from the Successor Company with the Predecessor Company for comparison and analysis purposes.

Cash provided by continuing operations totaled $150.9 million during 2004, compared to cash used of $105.7 million in 2003 and cash provided of $125.6 million in 2002. The cash improvement in 2004 was substantially due to significant improvements in working capital and the suspension of interest payments on our unsecured debt during our reorganization. Cash flows from operations decreased significantly during 2003, primarily due to our deteriorating financial condition, reduced vendor credit terms (including requirement of deposits), increased legal and professional fees, and increased interest expense. While we expect to see continued improvements in working capital as we strengthen our financial position and liquidity, these improvements will not be as substantial as those made during 2004.

Cash used by investing activities totaled $54.5 million during 2004, compared to cash provided of $4.9 million during 2003 and cash used of $641.1 million in 2002. Cash used in 2004 was principally due to property additions offset by proceeds from the sale of a note receivable of $15.1 million and dividends received from Blue Dot of $10 million. Cash provided in 2003 was primarily due to proceeds from investment sales offset by property additions. Cash used in 2002 was principally due to the acquisition of our Montana operations, which accounted for approximately $502.8 million.

Cash used in financing activities totaled $94.3 million during 2004 compared to cash provided of $77.6 million during 2003 and $732.6 million in 2002. During 2004 we received proceeds of $100 million from the new senior secured term loan B and $225 million from the issuance of senior secured notes. Proceeds from these issuances and cash on hand were used to repay $398 million of long-term debt. During 2003 we received proceeds of $390.0 million under a new senior secured term loan, which was used to repay $255.0 million on our credit facility. During 2002, we received proceeds of $720.0 million from the issuance of senior notes, which was used to acquire our Montana operations and repay existing debt.

Capital Requirements

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

Year	Amount
2005	$	76,000
2006	71,500
2007	72,000
2008	72,500
2009	73,000

The results of our ongoing review and consideration of recommendations related to an infrastructure audit may impact future capital spending over the next five years. In addition, we continue to discuss the implications of this audit with the MPSC in regards to the funding requirements needed to fully implement the recommendations.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commercial commitments that represent prospective requirements in addition to expense. The following table shows our contractual cash obligations and commercial commitments as of December 31, 2004. See additional discussion in Note 10 to the Consolidated Financial Statements.

	Total			2005		2006		2007		2008		2009		Thereafter
	(in thousands)
Debt:
Senior Secured Term Loan B(1)	$	100,000		$	1,000	$	1,000	$	1,000	$	1,000	$	1,000	$	95,000
South Dakota Mortgage Bonds, 5.875% 7.00% and 7.10%	179,000			60,000		—		—		—		—		119,000
South Dakota Pollution Control Obligations, 5.85% and 5.90%	21,350			—		—		—		—		—		21,350
Montana First Mortgage Bonds, 5.875% 7.00%, 7.30%, 8.25% and 8.95%	316,751			5,386		150,000		365		—		—		161,000
Discount on Montana First Mortgage Bonds	(2,433		)	—		—		—		—		—		(2,433		)
Montana Pollution Control Obligations, 6.125% and 5.90%	170,205			—		—		—		—		—		170,205
Montana Natural Gas Transition Bonds, 6.20%	42,450			4,744		4,712		5,248		5,391		5,862		16,493
Capital leases(2)	9,623			2,250		1,916		1,310		997		177		2,973
	836,946			73,380		157,628		7,923		7,388		7,039		583,588
Future minimum operating lease payments(3)	195,676			33,303		32,995		32,638		32,279		32,235		32,226
Estimated Pension and Other Postretirement Obligations(4)	114,000			25,000		25,000		25,000		25,000		14,000		N/A
Qualifying Facilities(5)	1,698,259			54,347		56,175		58,284		60,537		62,656		1,406,260
Supply and Capacity Contracts(6)	1,180,839			341,168		228,677		154,712		96,160		89,015		271,107
Interest payments on debt	497,796			51,389		46,879		36,220		36,195		36,108		291,005
Total Commitments	$	4,523,516		$	578,587	$	547,354	$	314,777	$	257,559	$	241,053	$	2,584,186

(1) The Senior Secured Term Loan B is secured by $72 million and $28 million of our Montana and South Dakota First Mortgage Bonds issued under our existing mortgage indentures, respectively.

(2) The capital lease obligations are used to finance various equipment purchases. These leases are secured by the equipment under lease, which includes $3.6 million of our Montana assets and $6.0 million of our South Dakota assets.

(3) Our operating leases include a lease agreement for our share of the Colstrip Unit 4 generation facility, which requires payments of $32.2 million annually through 2010. In January 2005, we exercised an option to extend the term of this lease for an additional eight years with annual payments of $14.5 million, which is not reflected in the table above.

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

(5) The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our estimated gross contractual obligation related to the QFs is approximately $1.7 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.3 billion. The obligation and payments reflected on this schedule represent the estimated gross contractual obligation as of December 31, 2004.

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

Defined Benefit Pension and Postretirement Benefit Plans.

Our reported costs of providing pension and other postretirement benefits, as described in Note 16 of “Notes to the Consolidated Financial Statements” contained in Item 8, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and other postretirement benefit costs are impacted by actual employee demographics, including age and compensation levels, the level of contributions we make to the plan, earnings on plan assets, and health care cost trends. Changes made to the provisions of such plans may also impact current and future benefit costs. Benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the postretirement benefit obligation and postretirement costs.

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

At December 31, 2004, our accumulated benefit obligation exceeded plan assets by approximately $127.2 million for our pension plans. In addition, our projected benefit obligation for other postretirement benefit plans exceeded plan assets by $44.1 million. Additional contributions may be required in the near future to meet the requirements of the plan to pay benefits to plan participants. To the extent such additional contributions are reflected in the ratemaking process to determine the rates billed to customers, such amounts will be treated as regulatory assets. Contributions to our pension and other postretirement benefit plans were $17.5 million and $46.8 million for the years ended December 31, 2004 and 2003.

NEW ACCOUNTING STANDARDS

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

RISK FACTORS

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our shares or other securities. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not presently known or that we currently believe to be less significant may also adversely affect us.

Bankruptcy-Related Risks

Parties objecting to confirmation of our plan of reorganization may appeal the order confirming our plan of reorganization.

On October 22, 2004, Magten filed a motion with the Bankruptcy Court seeking a stay of the confirmation order pending resolution of their appeal of such order, which notice of appeal was filed on October 25, 2004. On October 25, 2004, the Bankruptcy Court denied Magten’s motion for a stay. Thereafter, Magten requested that the United States District Court for the District of Delaware impose a stay of the effectiveness of the confirmation order pending resolution of Magten’s appeal. On October 29, 2004, the Delaware District Court denied Magten’s motion for a stay. The appeal has now been docketed with the District Court but a briefing schedule has not been issued. In March 2005 we moved to dismiss Magten’s appeal of the confirmation order on equitable mootness grounds. Although we will vigorously prosecute the motion to dismiss the appeal and defend against the appeal, we cannot currently predict the impact or resolution of Magten’s appeal of the confirmation order.

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

Despite the fact that we have successfully consummated our plan of reorganization and executed our exit financing on November 1, 2004, our Chapter 11 proceedings have negatively impacted us and our future prospects are uncertain. The uncertainty regarding our future prospects may hinder our ongoing business activities and ability to operate, fund and execute our business plan by: (i) impairing relations with existing and potential customers; (ii) negatively impacting our ability to attract, retain and compensate key executives and associates and to retain employees generally; (iii) limiting our ability to obtain trade credit; and (iv) impairing present and future relationships with vendors and service providers.

We have incurred, and expect to continue to incur, significant costs associated with the Chapter 11 proceedings, which may adversely affect our results of operations and cash flows.

We have incurred and will continue to incur significant costs associated with the Chapter 11 proceedings. The amount of these costs, which are being expensed as incurred, are expected to have a significant adverse effect on our results of operations and cash flows. Although our plan of reorganization has been successfully consummated and we have emerged from bankruptcy, we expect to continue to incur significant costs in connection with the steps necessary to close the bankruptcy case which include, among other things, resolution of remaining unsecured claims, administration of the claim reserve, coordination with the Plan Committee and the resolution of the appeal and certain pending litigation. These expenses are also expected to have an adverse effect on our results of operations and cash flows.

Claims that were not discharged in the bankruptcy proceeding, and to the extent certain claimants did not receive proper notice of the claim bar date, such claims could have a material adverse effect on our results of operations and profitability.

Although most claims made against us prior to the date of the bankruptcy filing were satisfied and discharged in accordance with the terms of our plan of reorganization or in connection with settlement agreements that were approved by the Bankruptcy Court prior to consummation of our plan of

reorganization, certain claims, such as environmental claims, that were not discharged or settled may have a material adverse effect on our results of operations and profitability.

Claims made against us prior to the date of the bankruptcy filing might not be discharged if the claimant had no notice of the bankruptcy filing. In addition, in other bankruptcy cases, states have challenged whether their claims could be discharged in a federal bankruptcy proceeding if they never made an appearance in the case. This issue has not been finally settled by the U.S. Supreme Court.

We filed several motions to terminate various nonqualified benefit plans with estimated allowed claims of approximately $17 million. All liabilities associated with these plans have been removed from our balance sheet based on our expectation that these claims will be settled through the shares from the reserve established for Class 9 claimants. While we expect the Bankruptcy Court to approve termination of these plans, the status is currently uncertain. If the Bankruptcy Court were to require us to reinstate these plans in the future, then we would have to reestablish the liabilities on our balance sheet and recognize a loss in the Successor Company operations.

Certain of our prepetition creditors received NorthWestern common stock pursuant to our plan of reorganization and have the ability to influence certain aspects of our business operations.

Under our plan of reorganization, holders of certain claims received distributions of shares of our common stock. Harbert Management Inc., which we refer to as Harbert, is affiliated with or manage funds which, based on the most recent information made available to us, collectively received more than 20% of our new common stock. Harbert could acquire additional claims or shares, or divest claims or shares in the future. Our prepetition senior unsecured noteholders, trade vendors with claims in excess of $20,000 and holders of our trust preferred securities and our quarterly income preferred securities received, collectively, approximately 9% of our new common stock. Other than Harbert, however, we are not aware of any other entity that owns or controls 10% or more of our common stock distributed upon emergence pursuant to our plan of reorganization.

If any holders of a significant number of the shares of our common stock were to act as a group, then such holders could be in a position to control the outcome of actions requiring stockholder approval, such as an amendment to our certificate of incorporation, the authorization of additional shares of capital stock, and any merger, consolidation, or sale of all or substantially all of our assets, and could prevent or cause a change of control of NorthWestern.

Risks Relating to Our Business

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

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al., now pending in federal court in Montana. The lawsuit, which was filed by the

former shareholders of The Montana Power Company (many of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of The Montana Power Company), claims that the disposition of various generating and energy-related assets by The Montana Power Company was void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern is named as a defendant due to the fact that we purchased the Montana Power, LLC, which the plaintiffs claim is a successor to The Montana Power Company. On July 10, 2004, we and the other insureds under the applicable directors and officers liability insurance policies along with the plaintiffs in the McGreevey case, plaintiffs in the In Re Touch America Holdings, Inc. Securities Litigation and the Touch America Creditors Committee reached a tentative settlement as a result of mediation. Among the terms of the tentative settlement, we, our wholly owned subsidiary CFB, and other parties will be released from all claims in this case, the plaintiffs in McGreevey will dismiss their claims against the third party purchasers of the generation assets and non-regulated energy assets of Montana Power Company, including PPL Montana, and a settlement fund in the amount of $67 million (all of which will be contributed by the former Montana Power Company directors and officers liability insurance carriers) will be established. The settlement is subject to the occurrence of several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding and approval of the proposed settlement by the federal District Court for the District of Montana, where the class actions are pending. Plaintiffs in the McGreevey class action have filed a motion for approval of the settlement; no hearing date has been set. If the proposed settlement is not consummated, then we intend to vigorously defend against this lawsuit. The Bankruptcy Court has entered an order permitting the plaintiffs in McGreevey to file a fraudulent conveyance action against us if we are not able to consummate the settlement. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of these lawsuits may harm our business and have a material adverse impact on our financial condition.

We are a defendant in litigation related to our quarterly income preferred securities, which litigation is related to the transfer of certain assets to NorthWestern from our subsidiary, CFB. Certain current and former officers of CFB are defendants in a lawsuit related to the same transfer of assets. Our business could be harmed and there could be a material adverse impact on our financial condition if we do not successfully resolve the lawsuit.

Certain creditors and parties-in-interest have initiated legal action against us related to the transfer of the assets and liabilities comprising our Montana utility operations from CFB to NorthWestern, and seek the removal of such assets from our estate or the imposition of a constructive trust for the benefit of such creditors. This litigation currently is stayed pending termination of the appeal of the order confirming our plan of reorganization filed by Magten. This litigation could adversely affect our business, results of operations, our financial condition and our ability to continue normal operations.

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

In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern and affiliated companies NorthWestern Communications Solutions, Expanets and Blue Dot. This development followed the SEC’s requests for information made in connection with the previously disclosed SEC informal inquiry into questions regarding the restatements and other accounting and financial reporting matters. Since December 2003, we have periodically received and continue to receive subpoenas from the SEC requesting documents and testimony from employees regarding these matters. The SEC investigation will continue,

and while no claims have been filed, any claims alleging violations of federal securities laws made by the SEC may not be discharged pursuant to our plan of reorganization.

In addition, certain of our former directors and several employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the Federal Bureau of Investigation (FBI) concerning certain of the allegations made in the class action securities and derivative litigation matters. We have not been advised that NorthWestern is the subject of any FBI investigation. We understand that the FBI and the Internal Revenue Service (IRS) have contacted former employees of ours or our subsidiaries. As of the date hereof, we are not aware of any other governmental inquiry or investigation related to these matters.

We are cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are contacted in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, then we may face sanctions, including, but not limited to, monetary penalties and injunctive relief and any monetary liability incurred by us may be material to our financial position or results of operations.

We are subject to certain regulations in the State of Montana regarding, among other things, the source of our power supplies and the recovery of costs from our customers associated with purchasing our power supplies. If the MPSC disallows the recovery of the costs incurred in entering into default supply portfolio contracts while we are required to act as the “default supplier,” then we may not be able to fully recover the costs incurred in procuring default supply contracts, which could adversely affect our results of operations and financial condition.

Our electric and natural gas default supply costs are being recovered through an annual cost tracking process pursuant to which rates are based on estimated electricity and natural gas loads and supply 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. The MPSC could, in any particular year, disallow the recovery of a portion of the electricity or natural gas default supply costs if it makes a determination that we acted imprudently with respect to the open market purchase strategies or that the approved supply contracts were not prudently administered. A failure to recover such costs could adversely affect our results of operations and financial condition.

We are subject to extensive governmental regulations that affect our industry and our operations. Existing and changed regulations and possible deregulation have the potential to impose significant costs, increase competition and change rates which could have a material adverse effect on our results of operations and financial condition.

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

Our utility businesses are regulated by certain state commissions. As a result, these commissions have the ability to review the regulated utility’s books and records. This ability to review our books and records could result in prospective negative adjustments to our rates.

The United States electric utility and natural gas industries are currently experiencing increasing competitive pressures as a result of consumer demands, technological advances, deregulation, greater availability of natural gas-fired generation and other factors. Competition for various aspects of electric and natural gas services is being introduced throughout the country that will open these markets to new providers of some or all of traditional electric utility and natural gas services. Competition is likely to result in the further unbundling of electric utility and natural gas services as has occurred in Montana for electricity and Montana, South Dakota and Nebraska for natural gas. Separate markets may emerge for generation, transmission, distribution, meter reading, billing and other services currently provided by electric utility and natural gas providers as a bundled service. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry.

We are currently subject to limited regulation under the Public Utility Holding Company Act of 1935, as amended (PUHCA); however, we may become subject to additional PUHCA requirements if certain of our 10% shareholders or other shareholders are not deemed to be “exempt” holding companies under the Act. Complying with additional PUHCA requirements could make it more difficult for us to enter into financing arrangements, conduct nonutilty lines of business or acquire other businesses or assets.

We are subject to limited regulation under PUHCA, because more than 20% of our voting stock (following the distribution under the approved bankruptcy plan) is currently held by Harbert Distressed Investment Master Fund Ltd. or affiliates of Harbert. Harbert has applied for status as an “exempt” holding company, under Section 3(a)(4) of PUHCA, on the basis that it is only temporarily a holding company. Harbert has represented that it will reduce its holdings below 10% within 3 years from its initial filing in November 2004 and it will not take an active role in our management. Pending action by the SEC on its application (and assuming that the application was filed in good faith and the relevant facts have not changed), Harbert is entitled to exempt status upon its filing pending SEC action on the application. As a result of Harbert’s holdings, we are a “subsidiary” of an “exempt holding company”, and are subject to Section 9 of PUHCA, but are not otherwise subject to the Act. The Company is itself not a utility holding company, because all of its utility operations are conducted at the parent level.

Under PUHCA the SEC does not regulate rates and charges for the sale or distribution of gas or electricity, but it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. If Harbert were denied an exemption, or if other entities became holders of more than 10% of our voting stock either individually or as a group acting together, and were not otherwise exempt from the Act, we would be subject to additional requirements under PUHCA, including requirements for SEC approval before issuing securities, entering into financing arrangements, entering or continuing lines of business not necessary or appropriate to our utility businesses, or acquiring other utility assets or businesses.

There are proposals to repeal PUHCA pending before Congress. Such proposals have been made in the last several years, and while each house has passed a bill to repeal PUHCA (usually as part of broader energy legislation), final agreement on a single bill has not occurred. We believe that each house will consider action on such bills in the current session, but we cannot predict when or whether any such legislation might pass.

We will not be able to fully recover transition costs, which could adversely affect our results of operations and financial condition.

Montana law required the MPSC to determine the value of net unrecovered transition costs associated with the transformation of the former utility business of The Montana Power Company from a vertically integrated electric service company to a utility providing only default supply and transmission and distribution services. The MPSC was also obligated to set a competitive transition charge, or CTC, to be included in distribution rates to collect those net transition costs. The majority of these transition costs relate to out-of-market power purchase contracts, which run through 2032, that the former owner of our Montana transmission and distribution business was required to enter into with certain “qualifying facilities” (QF) as established under the Public Utility Regulatory Policies Act of 1978. Based on results of an MPSC order and a FERC determination, we will not be able to fully recover all of the transition costs. As of December 31, 2004, we estimated that we will fail to collect approximately $143.4 million on a net present value basis over the remaining terms of the QF power supply contracts. While the CTC is designed to adjust and compensate for future changes in sales volumes or other factors affecting actual cost recoveries, the CTC runs through the year 2029, and therefore, we cannot predict with certainty the actual recovery of transition costs. Changes in the recovery of transition costs could adversely affect our results of operations and financial condition by increasing the current under collection amount.

Our obligation to supply a minimum annual quantity of QF power to the Montana default supply could expose us to material commodity price risk if we are required to supply any quantity deficiency during a time of commodity price volatility.

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the default supply with a certain minimum amount of QF power at an agreed upon price per megawatt. To the extent the supplied QF power for any year did not reach the minimum quantity set forth in the settlement, we are obligated to secure the quantity deficiency from other sources. Since we own no material generation in Montana, the anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility. Our understanding of the Stipulation and Settlement was that the quantity deficiency could be filled by us at any time during the measurement year. To the extent this interpretation is not supported by a regulatory ruling or we experience commodity price volatility during the period we replenish the quantity deficiency, our results of operations could be adversely affected.

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

The government of each of the municipalities in which we provide electric or natural gas service has the right to condemn our facilities in that community and to establish a municipal utility distribution system to serve customers by use of such facilities, subject to the approval of the voters of the community and the payment to NorthWestern of fair market value for our facilities, including compensation for the cancellation of our service rights. If we lose a material portion of our distribution systems to municipal condemnation, our results of operations and financial condition could be harmed because we may not be able to replace or repurchase income generating assets in a timely manner, if at all.

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

The cost of repairing damage to our facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of reserves established for such repairs or insurance recoveries, may adversely impact our results of operations, financial condition and cash flows. Generation and transmission facilities, in general, have been identified as potential terrorist targets. The occurrence or risk of occurrence of future terrorist activity may impact our results of operations, financial condition and cash

flows in unpredictable ways. These actions could also result in adverse changes in the insurance markets and disruptions of power and fuel markets. The availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. In addition, our electric transmission and distribution, electric generation, natural gas distribution and pipeline and gathering facilities could be directly or indirectly harmed by future terrorist activity.

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

Seasonal and quarterly fluctuations of our business could adversely affect our results of operations and financial condition.

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

To the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we could under-recover our costs, which would adversely impact our results of operations.

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

We do not own any natural gas reserves and do not own a material amount of electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, we might be required to purchase gas and electricity supply requirements in the energy markets, which may not be on commercially reasonable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under-recovery that would reduce our liquidity.

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

Our utility business is subject to extensive regulations imposed by federal, state and local government authorities in the ordinary course of operations with regard to the environment, including environmental regulations relating to air and water quality, solid waste disposal and other environmental considerations. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures. There is no assurance that we would be able to recover these increased costs from our customers or that our business, financial condition and results of operations would not be materially adversely affected.

Many of these environmental laws and regulations create permit and license requirements and provide for substantial civil and criminal fines which, if imposed, could result in material costs or liabilities. We cannot predict with certainty the occurrence of a private tort allegation or government claim for damages associated with specific environmental conditions. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair and upgrade of our facilities in order to meet future requirements and obligations under environmental laws.

Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for environmental remediation obligations is estimated to be $45.3 million to $84.1 million. We had an environmental reserve of $45.3 million at December 31, 2004. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from private tort actions or government claims for damages allegedly associated with specific environmental conditions. These environmental liabilities will continue and any claims with respect to environmental liabilities will not be extinguished pursuant to our plan of reorganization. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

The loss of our investment grade credit ratings has impacted our borrowing costs and liquidity, and we expect that our non-investment grade status will continue to affect our cash flows.

Upon emergence from bankruptcy, we were assigned a non-investment grade credit rating. Our current non-investment grade ratings have impacted our borrowing costs. In addition, we continue to either prepay or post collateral in the form of cash and letters of credit to support our operations. In addition, our stated intention to resume the payment of quarterly dividends on our common stock upon demonstrating the financial ability to do so may delay our ability to achieve an investment grade rating for our debt securities. While we are working to resolve many of the concerns cited by the credit rating agencies, we cannot assure you that our credit ratings will improve in the foreseeable future.

We have recently experienced net losses and losses may occur in the future.

We have incurred significant net losses in prior periods. Our results of operations will continue to be affected by events and conditions both within and beyond our control, including competition, economic, financial, business and other conditions. Therefore, we cannot assure you that we will not incur net losses in the future.

Our ability to access the capital markets is dependent on our ability to obtain certain regulatory approvals and the covenants contained in our debt instruments.

We may need to continue to support working capital and capital expenditures, and to refinance maturing debt, through external financing. Often, we must obtain federal and certain state regulatory approvals in order to borrow money or to issue securities and therefore will be dependent on the federal and state regulatory authorities to issue favorable orders in a timely manner to permit us to finance our operations. We cannot assure you that these regulatory entities will issue such orders or that such orders will be issued on a timely basis. In addition, our new credit facility and the indenture governing the notes limit us from incurring additional indebtedness.

If we are unable to successfully sell our noncore assets or wind-down operations of certain subsidiaries, then the amount of proceeds we receive from such sales could be significantly less than anticipated.

As part of our efforts to restructure our business, we are attempting to divest our Montana First Megawatts (MMI) generation project in Montana and wind-down operations of Netexit and Blue Dot. If the sales prices for such assets are less than anticipated, or we encounter unexpected liabilities, such as costs relating to the wind-down of operations, including termination of benefit plans and payment of other liabilities, then our liquidity could be adversely affected. Further, we cannot assure you that we will be able to consummate such asset sales or that any asset sales will be at or greater than the current net book value of such assets.

Our subsidiary, Netexit, sold substantially all of its assets to Avaya, Inc. In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. Pending the resolution of open claims to Netexit creditors, the proceeds from the sale remain at Netexit and distributions to NorthWestern could be delayed until the ultimate effective date of the liquidating plan of reorganization. There are many factors beyond our control including our ability to obtain the support of the Netexit official committee of unsecured creditors and potential additional losses related to the resolution of filed claims, which could affect the amount of proceeds we receive as distributions from Netexit. Additionally, Netexit’s creditors committee has indicated that NorthWestern’s claims against Netexit may be subject to avoidance under operative provisions of the Bankruptcy Code. We intend to vigorously defend against any efforts to invalidate or subordinate our claims against Netexit, but we cannot currently predict the resolution of any litigation with respect to the validity of NorthWestern’s claims against Netexit.

Our pension and other post-retirement benefit costs are subject to fluctuation based on the performance of the financial markets.

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

Part III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

Executive Officer	Current Title and Prior Employment	Age on March 1, 2005
Gary G. Drook	Chief Executive Officer since January 2003 and President since August 2003; and member of the Board of Directors since February 1998; formerly Chairman of the Board (2003-2004) and President and Chief Executive Officer and Director (1997-2003) of AFFINA, Inc. (formerly called Ruppman Marketing Technologies, Inc.), a provider of customer services programs; President of Network Services (1994-1995) for Ameritech Corporation, a communications services provider. Mr. Drook also serves as Chairman of Netexit, Inc. and Blue Dot Services Inc. (each of which are NorthWestern subsidiaries) and as a member of the board of directors of Central Indiana Ethanol, LLC, an Indiana ethanol plant developer.	60
Michael J. Hanson	Chief Operating Officer since August 2003; formerly President and Chief Executive Officer of NorthWestern Energy division (1998-2003). Prior to joining NorthWestern, Mr. Hanson was General Manager and Chief Executive of Northern States Power Company South Dakota and North Dakota in Sioux Falls, South Dakota (1994-1998). Mr. Hanson serves as Chairman and Chief Executive Officer of NorthWestern Services Corporation, a NorthWestern subsidiary.	46
Brian B. Bird	Chief Financial Officer since December 2003. Prior to joining the Company, Mr. Bird was Chief Financial Officer and Principal of Insight Energy, Inc., a Chicago-based independent power generation development company (2002-2003). Previously, he was Vice President and Treasurer of NRG Energy, Inc., in Minneapolis (1997-2002). Mr. Bird also serves as a member on the board of directors of Netexit, Inc. and NorthWestern Services Corporation, subsidiaries of NorthWestern.	42
Thomas J. Knapp	General Counsel since November 2004; formerly Vice President and Deputy General Counsel since March 2003. Prior to joining the Company, Mr. Knapp was Of Counsel at Paul, Hastings, Janofsky & Walker (1996-1998 and 2000-2003). Previously, he was Assistant General Counsel at The Boeing Company (1998-2000).	52
Roger P. Schrum	Vice President—Human Resources and Communications since December 2003; formerly Vice President—External Communications (2001-2003). Prior to joining NorthWestern, Mr. Schrum was General Manager, Marketing Communications and Public Affairs of SCANA Corporation, a Columbia, South Carolina-based utility company (1993-2001).	49

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

Board of Directors. In addition, Mr. Drook and Mr. Hanson were serving as executive officers at the time NorthWestern Corporation filed for bankruptcy. Mr. Drook was the Chairman of the Board of Netexit, Inc., and Mr. Bird was serving as an executive officer at the time Netexit, Inc. filed for bankruptcy.

The following information is furnished with respect to the directors of NorthWestern Corporation. All directors are elected annually.

Director	Principal Occupation or Employment	Director Since	Age on March 1, 2005
Stephen P. Adik	Member of the Board of Directors and formerly Vice Chairman (2001-2003), Senior Executive Vice President, Chief Financial Officer and Treasurer (1998-2001), Executive Vice President, Chief Financial Officer and Treasurer (1996 to 1998), and Vice President and General Manager—Corporate Support Group (1987-1996) of NiSource Inc. (NYSE: NI), an electric and natural gas production, transmission and distribution company. Mr. Adik serves on the board of Beacon Power (NASDAQ: BCON) a development stage technology company providing frequency and voltage regulation equipment to the electric power industry; and Chicago SouthShore and SouthBend Railroad, a privately held regional carrier serving northwest Indiana.	2004	61
Dr. E. Linn Draper, Jr.	Retired Chairman, President and Chief Executive Officer of American Electric Power Company (NYSE: AEP), a public utility holding company (1992-2004); formerly AEP President and Chief Operating Officer (1992-1993), Chairman, President and Chief Executive Officer (1987-1992) of Gulf States Utilities Company, a natural gas and electric utility. Dr. Draper serves on the boards of directors of Sprint Corporation (NYSE: FON), a telecommunications services company; Temple-Inland Inc. (NYSE: TIN), a corrugated packing, forest products and financial services business; Alliance Data Systems Corporation (NYSE: ADS), a provider of transaction services, credit services and marketing services; and Alpha Natural Resources Inc. (NYSE: ANR), a coal producer.	2004	63
Gary G. Drook	Chief Executive Officer since January 2003 and President since August 2003; formerly Chairman of the Board (2003-2004) and President and Chief Executive Officer and Director (1997-2003) of AFFINA, Inc. (formerly called Ruppman Marketing Technologies, Inc.), a provider of customer services programs; President of Network Services (1994-1995) for Ameritech Corporation, a communications services provider. Mr. Drook also serves as Chairman of Netexit, Inc. and Blue Dot Services Inc. (each of which are NorthWestern subsidiaries) and as a member of the board of directors of Central Indiana Ethanol, LLC, an Indiana ethanol plant developer.	1998	60

Jon S. Fossel	Retired Chairman, President and Chief Executive Officer of Oppenheimer Management Corporation, a mutual fund investment company (“Oppenheimer”) (1989-1996), formerly President and Chief Information Officer (1989) and Executive Vice President, Chief Operating Officer and Chief Information Officer (1987-1988) of Oppenheimer. Mr. Fossel serves on the board of directors of UnumProvident Corporation (NYSE: UNM), a disability and life insurance provider, and serves as a trustee of 41 of Oppenheimer Funds’ mutual funds.	2004	63
Julia L. Johnson	President and Founder of NetCommunications, LLC, a strategy consulting firm specializing in the energy, telecommunications and information technology public policy arenas, since 2000. Formerly Vice President—Communications & Marketing for Military Commercial Technologies, Inc.; Commission Chairman (1997-1999) and Commissioner (1992-1997) for the Florida Public Service Commission, the state agency responsible for the economic regulation of Florida’s utility companies, including the intrastate operations of telecommunications, electric, gas, water and wastewater. Ms. Johnson serves on the boards of directors of Allegheny Energy Inc. (NYSE: AYE), an electric utility holding company, and MasTec, Inc. (NYSE: MTZ), a company which designs, constructs and maintains telecommunications and cable television networks.	2004	42
Philip L. Maslowe	Formerly non-executive Chairman of the Board (2002-2004) for AMF Bowling Worldwide, Inc., operators of bowling centers and providers of sporting goods; Executive Vice President and Chief Financial Officer (1997-2002) of The Wackenhut Corporation, a security, staffing and privatized prisons corporation; and Executive Vice President and Chief Financial Officer (1993-1997) of Kindercare Learning Centers, a provider of learning programs for pre-schoolers.	2004	58
Corbin A. McNeill, Jr.	Retired Chairman and Co-Chief Executive Officer (2000-2002) of Exelon Corporation, a natural gas and electric utility company (formed in the October 2000 merger of Peco Energy Company and Unicom Corporation); formerly Chairman, President and Chief Executive Officer (1997-1999), Director, President and Chief Executive Officer (1990-1995) and Executive Vice President—Nuclear (1988-1990) of Peco Energy Company. Mr. McNeill serves on the boards of directors of Ontario Power Generation, an Ontario, Canada-based company whose principal business is the generation and sale of electricity in Ontario and to interconnected markets; Associated Electric & Gas Insurance Services Ltd. (AEGIS), an insurance and risk management service provider to utilities; and as Non-Executive Chairman of the Board of Directors of Portland General Electric, an electric utility.	2004	65

Audit Committee

The Audit Committee is composed of three nonemployee directors who are financially literate in financial and auditing matters and are “independent” as defined by the SEC and the NASDAQ. The members of the Audit Committee are Chairman Stephen P. Adik, Corbin A. McNeill, Jr. and Jon S. Fossel. The Company’s Board of Directors has determined that the Company has at least one audit committee financial expert, as defined in Item 401(h)(2) of Regulation S-K, and NASDAQ rule 4350(d0(2)(A), serving on its Audit Committee, namely, Stephen P. Adik. Mr. Adik is independent as that term is used in Item 7(d)(3)(iv) of Schedule 14A under the 1934 Act and NASDAQ rule 4200. The Audit Committee comprised of these members held two meetings during 2004. The Audit Committee composed of former nonemployee directors held nine meetings during 2004. The functions of the Audit Committee are to oversee the integrity of NorthWestern’s financial statements, NorthWestern’s compliance with legal and regulatory requirements, the independent public accountant’s qualifications and independence, the performance of NorthWestern’s internal audit function and independent auditors, and preparation of this report and the financial statement and notes included herein, and all other reports required under the Securities Exchange Act.

Section 16(a) Beneficial Ownership Reporting Compliance

Based solely upon a review of reports on Forms 3, 4 and 5 and any amendments thereto furnished to NorthWestern pursuant to Section 16 of the Securities Exchange Act of 1934, as amended, and written representations from the executive officers and directors that no other reports were required, NorthWestern believes that all of such reports were filed on a timely basis by executive officers and directors during 2004.

Code of Ethics

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

ITEM 11. EXECUTIVE COMPENSATION

Compensation of Directors and Executive Officers

We are required to disclose compensation earned during fiscal years 2004, 2003 and 2002 for our Chief Executive Officer and each of the four most highly compensated persons who were executive officers as of December 31, 2004. In addition, we are required to disclose compensation for up to two additional individuals that we would have provided information on if not for the fact that they no longer were serving as an executive officer at the end of fiscal 2004. All of these officers are referred to in this Form 10-K as the “Named Executive Officers.”

Summary Compensation Table

The following table sets forth the compensation earned during the fiscal years indicated for services in all capacities by the Named Executive Officers in 2004:

Name and Principal Position	Year	Salary $		Bonus $(1)		Restricted Stock Awards (2)($)			Awards (Securities Underlying Options)(2)(#)		LTIP Payouts ($)		All Other Compensation(3) ($)
Gary G. Drook	2004	$	565,000	$	565,000		$	2,059,200		—	$	—		$	98,189
President and Chief	2003	544,355		600,000			1,143,332			335,643	—			216,744
Officer	2002	N/A		N/A			N/A			N/A	N/A			N/A
Michael J. Hanson	2004	350,000		233,334			714,400			—	—			31,539
Chief Operating Officer	2003	355,609		—			—			—	—			27,916
	2002	345,833		540,000			—			29,000	—			25,817
Brian B. Bird	2004	275,000		350,000			428,800			—	—			43,081
Chief Financial Officer	2003	15,865		75,000			—			—	—			37
	2002	N/A		N/A			N/A			N/A	N/A			N/A
Roger P. Schrum	2004	175,000		93,334			216,000			—	—			26,711
Vice President-Human	2003	160,980		33,000			—			—	—			11,423
Resources and	2002	152,375		—			—			3,500	—			7,443
Communications
Thomas J. Knapp	2004	224,038		66,000			106,000			—	—			23,526
General Counse	2003	177,692		35,000			—			15,000	—			5,751
	2002	N/A		N/A			N/A			N/A	N/A			N/A
William M. Austin(4)	2004	284,615		1,200,000			—			—	—			43,474
Former Chief	2003	284,615		—			102,500			119,980	—			16,280
Restructuring Officer	2002	N/A		N/A			N/A			N/A	N/A			N/A
Eric R. Jacobsen(5)	2004	310,000		302,400			—			—	—			368,612
Former Senior Vice	2003	314,967		—			—			—	41,960			31,261
President, General	2002	304,791		400,000			—			44,000	—			28,829
Counsel and Chief
Legal Officer

(1) Bonuses for 2004 were paid in accordance with the court-approved Incentive Compensation and Severance Plan and, unless noted, were earned and paid in the year shown. Bonuses for 2003 were related to a bonus at the start of employment (Mr. Drook), an employment agreement (Mr. Bird) and retention agreements (Mr. Schrum and Mr. Knapp), which were earned and paid in the year shown. Bonuses for 2002 were earned in the year shown and paid in the following year.

(2) All options and restricted stock granted prior to October 31, 2004, were cancelled upon emergence from bankruptcy. Restricted stock was awarded November 1, 2004, as part of a bankruptcy emergence Special Recognition Grant. The amounts listed above represent the value at the date of issuance. Mr. Drook was awarded 102,960 shares, which had a market value of $2,882,880 at December 31, 2004. Mr. Hanson was awarded 35,720 shares, which had a market value $1,000,160 at December 31, 2004. Mr. Bird was awarded 21,440 shares, which had a market value of $600,320 at December 31, 2004. Mr. Schrum was awarded 10,800 shares, which had a market value of $302,400 at December 31, 2004. Mr. Knapp was awarded 5,300 shares, which had a market value of $148,400 at December 31, 2004. Pursuant to the plan of reorganization, 50% of the Grants vested on November 1, 2004, and the remaining restricted stock will vest over a three-year period based upon a vesting scheduled approved by the Board. The remaining 50% of the Grants vest for Named Executive Officers according to the following schedule: 10% on November 1, 2005; 20% on November 1, 2006; and 20% on November 1, 2007.

(3) The amounts include employer contributions, as applicable, for medical, dental, vision, employee assistance program (EAP), term life, group term life, 401(k), supplemental 401(k), and employer contributions to other postretirement plans, vehicle lease or car allowance, relocation expenses, and tax gross up payments (where provided) as well as an airplane allowance (available to all executives pursuant to the board approved guidelines) for Mr. Drook ($60,950) and Mr. Hanson ($7,533). Mr. Austin and Mr. Jacobsen were the only executives to receive country club dues, which policy was terminated in February 2004.

(4) Mr. Austin served as Chief Restructuring Officer for NorthWestern until September 4, 2004. His 2004 bonus amount includes a $133,333 incentive earned in 2004, to be paid March 15, 2005, as part of the Bankruptcy Court approved incentive payments.

(5) Mr. Jacobsen served as Chief Legal Counsel for NorthWestern until November 1, 2004, at which time he served as Director—Strategic Development until January 3, 2005. Mr. Jacobsen’s 2004 bonus includes a $100,800 incentive payment made on January 31, 2005. His other compensation includes a severance payment of $350,000 paid on January 7, 2005. The severance includes a $10,000 benefit offset and $20,000 consideration for a convenience claim related to a supplemental executive retirement plan. Both the incentive and severance payments were required as part of a November 1, 2004, agreement with Mr. Jacobsen and are in accordance with the Bankruptcy Court approved Incentive Compensation and Severance Plan. Mr. Jacobsen will continue to provide services to us under an hourly consulting agreement, including transition of duties, continued involvement in administration of certain litigation and in strategic development activities involving our emergence from bankruptcy, for a period of six months from his termination, unless extended by mutual agreement.

Information on Options

All options and restricted stock awards granted to Named Executive Officers prior to October 31, 2004, were cancelled upon emergence from bankruptcy.

Employment Contract

We have an Employment Agreement with Chief Financial Officer Brian B. Bird, which, as amended and approved by the Bankruptcy Court in its Order dated January 13, 2004, provides for him to serve as Chief Financial Officer, commencing December 1, 2003, and extends until the earlier of his termination of employment or December 1, 2005. For the first year of Mr. Bird’s compensation package, he received a sign-on bonus, a base salary of $275,000, performance-based incentive of up to 100% of his annual salary, and a housing and commuting allowance. Mr. Bird’s future incentive compensation is to be determined by the Board. Mr. Bird is also entitled to participate in our benefit plans available to executives, including, among other things, health, retirement, disability and life insurance benefits. The agreement also provides for severance if Mr. Bird is terminated for any reason other than Cause.

No other Named Executive Officers have employment agreements.

Retirement Plans

NorthWestern has two retirement plans, with one applicable to its Montana employees and one applicable to its South Dakota and Nebraska employees. As of December 31, 2004, Mr. Drook, Mr. Hanson, Mr. Bird, Mr. Schrum, Mr. Knapp and Mr. Jacobsen were participants in the retirement plan applicable to South Dakota and Nebraska employees. Mr. Austin terminated his employment with the Company on September 4, 2004, and is no longer a participant in the retirement plan. For that plan, effective January 1, 2000, NorthWestern offered its employees two alternatives with regard to its retirement plan. An employee could convert his or her existing accrued benefit from the existing plan into an opening balance in a hypothetical account under a new cash balance formula, or that employee could continue under the existing defined benefit formula. All employees hired after January 1, 2000, participate in the cash balance formula. The beginning balance in the cash balance account for a converting employee was determined based upon the employee’s accrued benefit, age and years of service as of January 1, 2000, eligible pay for the year 2000, and a conversion interest rate of 6%. Under the cash balance formula, a participant’s account grows based upon (1) contributions by NorthWestern made once per year, and (2) by annual interest credits based on the average Federal 30-year Treasury bill rate for November of the preceding year. Contribution rates were determined on January 1, 2000, based on the participant’s age and years of service on that date. They range from 3% to 7.5% (3% for all new employees) for compensation below the taxable wage base and are doubled for compensation above the taxable wage base. Upon termination of employment with NorthWestern, an employee, or if deceased, his or her beneficiary, receives the cash balance in the account paid in a lump sum or in other permitted annuity forms of payment.

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

All Other Fees

Consists of fees for products and services other than the services reported above. In fiscal 2004 and 2003, there were no other fees.

Preapproval Policies and Procedures

Pursuant to the provisions of the Audit Committee Charter, before Deloitte is engaged to render audit or nonaudit services, the Audit Committee must preapprove such engagement. In 2004, the Audit Committee approved all such services undertaken by Deloitte before engagement for such services.

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENTS

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

(1) Financial Statements.

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

FINANCIAL STATEMENTS:

	Page
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Statements of Income (Loss) for the Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 and Years Ended December 31, 2003, and 2002 (Predecessor Company)	F-6
Consolidated Statements of Cash Flows for the Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 and Years Ended December 31, 2003 and 2002 (Predecessor Company)	F-7
Consolidated Balance Sheets as of December 31, 2004 (Successor Company), October 31, 2004 (Successor Company) and December 31, 2003 (Predecessor Company)	F-8
Consolidated Statement of Shareholders’ Equity (Deficit) for the Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 (Successor Company) and Years Ended December 31, 2003 and 2002 (Predecessor Company)	F-9
Notes to Consolidated Financial Statements	F-11
Quarterly Unaudited Financial Data for the Two Years Ended December 31, 2004	F-59

(2) Financial Statement Schedules

Schedule II. Valuation and Qualifying Accounts

F-60

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

(3) Exhibits.

The exhibits listed below are hereby filed with the SEC, as part of this annual report on Form 10-K. Certain of the following exhibits have been previously filed with the SEC pursuant to the requirements of the Securities Act of 1933 or the Securities Exchange Act of 1934. Such exhibits are identified by the

parenthetical references following the listing of each such exhibit and are incorporated by reference. We will furnish a copy of any exhibit upon request, but a reasonable fee will be charged to cover our expenses in furnishing such exhibit.

Exhibit Number				Description of Document
2.1(a)*				Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, Commission File No. 0-692).
2.1(b)*				Order Confirming the Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, Commission File No. 0-692).
3.1*				Amended and Restated Certificate of Incorporation of NorthWestern Corporation, dated November 1, 2004(incorporated by reference to Exhibit 3.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, Commission File No. 0-692).
3.2*				Amended and Restated By-Laws of NorthWestern Corporation, dated November 1, 2004, (incorporated by reference to Exhibit 3.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, 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(e)*				Supplemental Indenture, dated as of November 1, 2004, by and between NorthWestern Corporation (formerly known as Northwestern Public Service Company) and JPMorgan Chase Bank (successor by merger to The Chase Manhattan Bank (National Association)), as Trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.5 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
10.2(a)*				Credit Agreement among NorthWestern Corporation, as borrower, the several lenders from time to time parties thereto, Lehman Brothers Inc. and Deutsche Bank Securities Inc., as joint lead arrangers, Deutsche Bank Securities Inc., as syndication agent, Union Bank of California, N.A. and KeyBank National Association, s co-documentation agents, and Lehman Commercial Paper Inc., as administrative agent and collateral agent (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.2(a)*				Indenture, dated as of November 1, 2004, between NorthWestern Corporation and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).

4.2(b)*		Supplemental Indenture No. 1, dated as of November 1, 2004, by and between NorthWestern Corporation and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.2(c)*		Registration Rights Agreement, dated as of November 1, 2004, between NorthWestern Corporation, as issuer, and Credit Suisse First Boston LLC and Lehman Brothers Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.3(a)*		Sale Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Mercer County, North Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993 (incorporated by reference to Exhibit 4(b)(1) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(b)*		Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Grant County, South Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993A (incorporated by reference to Exhibit 4(b)(2) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(c)*		Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Grant County, South Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993B (incorporated by reference to Exhibit 4(b)(3) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(d)*		Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and the City of Salix, Iowa, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993 (incorporated by reference to Exhibit 4(b)(4) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(e)*		Loan Agreement, dated as of May 1, 1993, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(e) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.3(f)*		1993A First Supplemental Loan Agreement, dated as of September 21, 2001, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(f) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.3(g)*		Assumption Agreement of The Montana Power, LLC to Bank One, as Trustee, dated as of February 13, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(g) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).

4.3(h)*		Assignment and Assumption Agreement (PCRB 1993A Loan Agreement), between NorthWestern Energy, LLC, as Assignor, and NorthWestern Corporation, as Assignee, dated as of November 15, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(h) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692.
4.3(i)*		Loan Agreement, dated as of December 1, 1993, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993B due 2023 (incorporated by reference to Exhibit 4.4(i) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.3(j)*		1993B First Supplemental Loan Agreement, dated as of September 21, 2001, between The Montana Power Company and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(j) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.3(k)*		Assumption Agreement of The Montana Power, LLC to Bank One, as Trustee, dated as of February 13, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993B due 2023 (incorporated by reference to Exhibit 4.4(k) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.3(l)*		Assignment and Assumption Agreement (PCRB 1993B Loan Agreement), between NorthWestern Energy, LLC, as Assignor, and NorthWestern Corporation, as Assignee, dated as of November 15, 2002, related to the City of Forsyth Pollution Control Revenue Bonds Series 1993A due 2023 (incorporated by reference to Exhibit 4.4(l) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.4(a)*		First Mortgage and Deed of Trust, dated as of October 1, 1945, by The Montana Power Company in favor of Guaranty Trust Company of New York and Arthur E. Burke, as trustees (incorporated by reference to Exhibit 7(e) of The Montana Power Company’s Registration Statement, Commission File No. 002-05927).
4.4(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).
4.4(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).
4.4(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).
4.4(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).

4.4(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).
4.4(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).
4.4(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).
4.4(i)*		Twentieth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of November 1, 2001 (incorporated by reference to Exhibit 4(u) of NorthWestern Energy, LLC’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 001-31276).
4.4(j)*		Twenty-first Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 13, 2002 (incorporated by reference to Exhibit 4(v) of NorthWestern Energy, LLC’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 001-31276).
4.4(k)*		Twenty-second Supplemental Indenture to the Mortgage and Deed of Trust, dated as of November 15, 2002 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
4.4(l)*		Twenty-third Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 1, 2002 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
4.4(m)*		Twenty-Fourth Supplemental Indenture, dated as of November 1, 2004, between NorthWestern Corporation and The Bank of New York and MaryBeth Lewicki, (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.6(a)*		Natural Gas Funding Trust Indenture, dated as of December 22, 1998, between MPC Natural Gas Funding Trust, as Issuer, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.7(a) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(b)*		Natural Gas Funding Trust Agreement, dated as of December 11, 1998, among The Montana Power Company, Wilmington Trust Company, as trustee, and the Beneficiary Trustees party thereto (incorporated by reference to Exhibit 4.7(b) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(c)*		Transition Property Purchase and Sale Agreement, dated as of December 22, 1998, between MPC Natural Gas Funding Trust and The Montana Power Company (incorporated by reference to Exhibit 4.7(c) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(d)*		Transition Property Servicing Agreement, dated as of December 22, 1998, between MPC Natural Gas Funding Trust and The Montana Power Company (incorporated by reference to Exhibit 4.7(d) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).

4.6(e)*		Assumption Agreement regarding the Transition Property Purchase Agreement and the Transition Property Servicing Agreement, dated as of February 13, 2002, by The Montana Power, LLC to MPC Natural Gas Funding Trust (incorporated by reference to Exhibit 4.7(e) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(f)*		Assignment and Assumption Agreement (Natural Gas Transition Documents), dated as of November 15, 2002, by and between NorthWestern Energy, LLC, as assignor, and NorthWestern Corporation, as assignee (incorporated by reference to Exhibit 4.7(f) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
10.1(a) †**		NorthWestern Energy 2005 Employee Incentive Plan.
10.1(b) †*		NorthWestern Corporation 2004 Special Recognition Grant Restricted Stock Plan (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation’s registration statement on Form S-8, dated January 31, 2005, Commission File No. 333-122428).
10.1(c) †**		NorthWestern Corporation 2005 Deferred Compensation Plan for Non-Employee Directors.
10.1(d) †**		NorthWestern Corporation Incentive Compensation and Severance Plan.
10.1(e) †*		Employment Agreement with Brian B. Bird as Chief Financial Officer, as amended and approved by the Bankruptcy Court in its Order dated January 13, 2004 (incorporated by reference to Exhibit 10.1(p) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, Commission File No. 0-692).
12.1**		Statement Regarding Computation of Earnings to Fixed Charges.
21**		Subsidiaries of NorthWestern Corporation.
23.1**		Consent of Independent Registered Public Accounting Firm
24**		Power of Attorney (included on the signature page of this Annual Report on Form 10-K)
31.1**		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2**		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32.1**		Certification of Gary G. Drook pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Brian B. Bird pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

† Management contract or compensatory plan or arrangement.

* Incorporated by reference.

** Filed herewith.

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

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(in thousands, except per share amounts)

	Successor
	Company				Predecessor Company
	November 1-				January 1-			Year Ended
	December 31,				October 31,			December 31,			December 31,
	2004				2004			2003			2002
OPERATING REVENUES		$	205,952		$	833,037		$	1,012,515			$	783,744
COST OF SALES		116,775			447,054			535,667				341,526
GROSS MARGIN		89,177			385,983			476,848				442,218
OPERATING EXPENSES
Operating, general and administrative		35,958			185,782			239,716				213,309
Property and other taxes		10,766			54,369			67,542				54,909
Depreciation		12,174			60,674			70,252				63,240
Amortization of intangibles		—			—			—				19
Reorganization items		437			(533,063		)	8,266				—
Impairment on assets held for sale		10,000			—			12,399				35,729
TOTAL OPERATING EXPENSES		69,335			(232,238		)	398,175				367,206
OPERATING INCOME		19,842			618,221			78,673				75,012
Interest Expense (contractual interest of $157,887 for the ten-months ended 10/31/04 and $176,926 for the year ended 12/31/03)		(11,021		)	(72,822		)	(147,626		)		(98,010		)
Gain (Loss) on Debt Extinguishment		(21,310		)	—			3,300				(20,688		)
Investment Income and Other		1,039			2,121			(5,977		)		(5,481		)
Income (Loss) From Continuing Operations Before Income Taxes		(11,450		)	547,520			(71,630		)		(49,167		)
Benefit for Income Taxes		4,930			1,369			48				39,811
Income (Loss) From Continuing Operations		(6,520		)	548,889			(71,582		)		(9,356		)
Discontinued Operations, Net of Taxes and Minority Interests		(424		)	2,488			(42,143		)		(854,586		)
Net Income (Loss)		(6,944		)	551,377			(113,725		)		(863,942		)
Minority Interests on Preferred Securities of Subsidiary Trusts		—			—			(14,945		)		(28,610		)
Dividends and Redemption Premium on Preferred Stock		—			—			—				(391		)
Earnings (Loss) on Common Stock		$	(6,944	)	$	551,377		$	(128,670	)		$	(892,943	)
Average Common Shares Outstanding		35,614
Basic Loss per Average Common Share
Continuing operations		$	(0.18	)
Discontinued operations		(0.01		)
Basic		$	(0.19	)
Diluted Loss per Average Common Share
Continuing operations		$	(0.18	)
Discontinued operations		(0.01		)
Diluted		$	(0.19	)
Dividends Declared per Average Common Share		$	—

See Notes to Consolidated Financial Statements

F-6

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

	Successor Company				Predecessor Company
	November 1- December 31,				January 1- October 31,				Year Ended December 31,
	2004				2004				2003				2002
Operating Activities:
Net Income (Loss)		$	(6,944	)		$	551,377			$	(113,725	)		$	(863,942	)
Items not affecting cash:
Depreciation and amortization		12,174				60,674				70,252				63,259
Amortization of debt issue costs		282				9,584				13,935				6,655
Amortization of restricted stock		190				2,639				266				455
(Gain) Loss on debt extinguishment		21,310				—				(3,300		)		20,688
Impairment on assets held for sale		10,000				—				12,399				35,729
(Income) Loss on discontinued operations, net of taxes		424				(2,488		)		42,143				854,586
Cancellation of indebtedness income		—				(558,053		)		—				—
(Gain) Loss on reorganization items		—				(13,900		)		—				—
Impairment of note receivable		—				—				9,073				—
Deferred income taxes		(3,938		)		—				—				—
(Gain) Loss on property, plant and equipment and investments		127				962				(1,468		)		13,984
Changes in current assets and liabilities, net of acquisitions:
Restricted cash		21,779				(12,851		)		996				4,330
Accounts receivable		(46,387		)		11,663				(14,819		)		4,864
Inventories		3,830				(5,342		)		(614		)		12,545
Prepaid energy supply costs		(1,230		)		25,006				(53,391		)		—
Other current assets		7,416				14,267				(1,250		)		19,233
Accounts payable		(1,260		)		14,454				22,626				6,384
Accrued expenses		(27,885		)		45,584				(303		)		(1,816		)
Changes in regulatory assets		5,225				23,638				(17,158		)		(74,095		)
Changes in regulatory liabilities		995				3,472				(10,451		)		(32,227		)
Other noncurrent liabilities		(1,817		)		(14,093		)		(45,030		)		25,947
Other, net		(3,976		)		3,953				(15,854		)		28,978
Cash flows provided by (used in) continuing operations		(9,685		)		160,546				(105,673		)		125,557
Change in net assets of discontinued operations		(80		)		(158		)		11,813				(195,421		)
Cash flows provided by (used in) operating activities		(9,765		)		160,388				(93,860		)		(69,864		)
Investing Activities:
Property, plant, and equipment additions		(17,723		)		(62,391		)		(70,737		)		(147,847		)
Proceeds from sale of assets		15,261				193				2,743				8,579
Proceeds from sale of investments		75				90				—				—
Sale of noncurrent investments and assets		—				—				72,926				899
Dividends from Blue Dot		10,000				—				—				—
Acquisitions, net of cash received		—				—				—				(502,765		)
Cash flows provided by (used in) investing activities		7,613				(62,108		)		4,932				(641,134		)
Financing Activities:
Dividends on common and preferred stock		—				—				—				(38,081		)
Minority interest on preferred securities of subsidiary trusts		—				—				(9,720		)		(28,610		)
Redemption of preferred stock		—				—				—				(4,028		)
Proceeds from issuance of common stock		—				—				—				81,031
Issuance of long term debt		325,009				680				397,200				721,970
Issuance of preferred securities of subsidiary trust, net		—				—				—				117,750
Repayment of long-term debt		(398,283		)		(10,107		)		(26,979		)		(213,587		)
Line of credit borrowings, net		—				—				(255,000		)		123,000
Repayment of discontinued operations debt		—				—				—				(26,059		)
Treasury stock activity		—				—				—				121
Financing costs		(11,345		)		(207		)		(27,944		)		(25,813		)
Proceeds from termination of hedge		—				—				—				24,898
Cash flows provided by (used in) financing activities		(84,619		)		(9,634		)		77,557				732,592
Increase (Decrease) in Cash and Cash Equivalents		(86,771		)		88,646				(11,371		)		21,594
Cash and Cash Equivalents, beginning of period		103,829				15,183				26,554				4,960
Cash and Cash Equivalents, end of period		$	17,058			$	103,829			$	15,183			$	26,554

See Notes to Consolidated Financial Statements

F-7

NORTHWESTERN CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)

	Successor Company								Predecessor Company
	December 31, 2004				October 31, 2004				December 31, 2003
ASSETS
Current Assets:
Cash and cash equivalents		$	17,058			$	103,829			$	15,183
Restricted cash		18,115				39,894				27,043
Accounts receivable, net		141,350				94,963				106,626
Inventories		28,033				31,863				26,521
Regulatory assets		13,152				17,336				37,234
Prepaid energy supply		30,278				29,048				54,054
Other		8,601				31,094				41,892
Assets held for sale		20,000				30,000				30,000
Current assets of discontinued operations		71,091				81,617				106,197
Total current assets		347,678				459,644				444,750
Property, Plant, and Equipment, Net		1,379,060				1,371,622				1,360,815
Goodwill		435,076				435,076				375,798
Other:
Investments		8,876				8,971				11,027
Regulatory assets		224,192				225,233				202,174
Other		18,597				24,379				61,979
Noncurrent assets of discontinued operations		37				39				306
Total assets		$	2,413,516			$	2,524,964			$	2,456,849
LIABILITIES AND SHAREHOLDERS’ EQUITY (DEFICIT)
Current Liabilities:
Current maturities of long-term debt		$	73,380			$	76,520			$	919,393
Unsecured Debt and Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts		—				—				1,230,394
Accounts payable		85,120				86,380				72,332
Accrued expenses		131,852				159,737				166,146
Regulatory liabilities		19,342				18,830				14,791
Current liabilities of discontinued operations		18,374				18,539				44,496
Total current liabilities		328,068				360,006				2,447,552
Long-term Debt		763,566				833,634				—

Deferred Income Taxes		41,354				45,292				—
Noncurrent Regulatory Liabilities		160,750				158,694				150,917
Other Noncurrent Liabilities		410,000				410,810				442,333
Noncurrent Liabilities and Minority Interests of Discontinued Operations		443				462				1,998
Total liabilities		1,704,181				1,808,898				3,042,800
Shareholders’ Equity (Deficit):
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 35,728,315 and 35,614,158, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		355				355				—
Common stock, par value $1.75; authorized 50,000,000 shares; issued and outstanding 37,680,095 and 37,396,792, respectively		—				—				65,940
Paid-in capital		717,994				717,994				302,316
Unearned restricted stock		(2,093		)		(2,283		)		(861		)
Retained deficit		(6,944		)		—				(947,274		)
Accumulated other comprehensive income (loss)		23				—				(6,072		)
Total shareholders’ equity (deficit)		709,335				716,066				(585,951		)
Total liabilities and shareholders’ equity (deficit)		$	2,413,516			$	2,524,964			$	2,456,849

See Notes to Consolidated Financial Statements

F-8

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY (DEFICIT)
(in thousands)

	Number of Common Shares		Number of Treasury Shares			Common Stock			Paid in Capital			Unearned Restricted Stock				Treasury Stock				Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)				Total Shareholders’ Equity (Deficit)
Balance at December 31, 2001 (Predecessor Company)		27,397		156			$	47,942	$	241,382			$	(585	)		$	(3,681	)	$	112,307			$	(787	)		$	396,578
Net income		—		—			$	—	$	—			$	—			$	—		$	(863,942	)		$	—			$	(863,942	)
Other comprehensive income (loss), net of tax:
Unrealized gain on marketable securities net of reclassification adjustment		—		—			—		—				—				—			—				1,139				1,139
Foreign currency translation adjustments		—		—			—		—				—				—			—				5				5
Gain on hedge termination		—		—			—		—				—				—			—				5,072				5,072
Amortization of hedge gain		—		—			—		—				—				—			—				(807		)		(807		)
Minimum pension liability		—		—			—		—				—				—			—				(8,759		)		(8,759		)
Issuances of common stock		10,000		—			17,502		63,529				—				—			—				—				81,031
Amortization of unearned restricted stock compensation		—		—			—						455				—			—				—				455
Treasury stock activity		—		18			—		—				—				121			—				—				121
Distributions on minority interests in preferred securities of subsidiary trusts		—		—			—		—				—				—			(28,610		)		—				(28,610		)
Dividends on preferred stock		—		—			—		—				—				—			(112		)		—				(112		)
Redemption premium on preferred stock		—		—			—		—				—				—			(278		)		—				(278		)
Dividends on common stock		—		—			—		—				—				—			(37,969		)		—				(37,969		)
Balance at December 31, 2002 (Predecessor Company)		37,397		174			$	65,444	$	304,911			$	(130	)		$	(3,560	)	$	(818,604	)		$	(4,137	)		$	(456,076	)
Net loss		—		—			$	—	$	—			$	—			$	—		$	(113,725	)		$	—			$	(113,725	)
Other comprehensive income (loss), net of tax:
Unrealized loss on marketable securities net of reclassification adjustment		—		—			—		—				—				—			—				(352		)		(352		)
Foreign currency translation adjustments		—		—			—		—				—				—			—				298				298
Amortization of hedge gain		—		—			—		—				—				—			—				(416		)		(416		)
Minimum pension liability		—		—			—		—															(1,465		)		(1,465		)
Issuances of restricted stock		283		—			496		501				(997		)		—			—				—				—
Amortization of unearned restricted stock compensation		—		—			—		—				266				—			—				—				266
Treasury stock activity		—		(174	)		—		(3,096		)		—				3,560			—				—				464
Distributions on minority interests in preferred securities of subsidiary trusts		—		—			—		—				—				—			(14,945		)		—				(14,945		)
Balance at December 31, 2003 (Predecessor Company)		37,680		—			$	65,940	$	302,316			$	(861	)		$	—		$	(947,274	)		$	(6,072	)		$	(585,951	)

See Notes to Consolidated Financial Statements

F-9

NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY (DEFICIT) (Continued)
(in thousands)

	Number of Common Shares			Number of Treasury Shares		Common Stock			Paid in Capital			Unearned Restricted Stock				Treasury Stock			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)				Total Shareholders’ Equity (Deficit)
Balance at December 31, 2003 (Predecessor Company)		37,680			—	$	65,940		$	302,316			$	(861	)		$	—	$	(947,274	)		$	(6,072	)		$	(585,951	)
Net income		—			—	$	—		$	—			$	—			$	—	$	551,377			$	—			$	551,377
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments		—			—	—			—				—				—		—				90				90
Amortization of unearned restricted stock compensation		—			—	—			—				356				—		—				—				356
Effects of reorganization and fresh-start reporting		(37,680	)		—	(65,940		)	(302,315		)		505				—		395,897				5,982				34,129
Issuance of common stock		35,500			—	355			709,645								—		—				—				710,000
Issuance of restricted stock		228			—	—			4,566				(2,283		)		—		—				—				2,283
Issuance of warrants					—	—			3,782								—		—				—				3,782
Balance at October 31, 2004 (Successor Company)		35,728			—	$	355		$	717,994			$	(2,283	)		$	—	$	—			$	—			$	716,066
Net loss		—			—	$	—		$	—			$	—			$	—	$	(6,944	)		$	—			$	(6,944	)
Other comprehensive income, net of tax:
Foreign currency translation adjustments		—			—	—			—				—				—		—				23				23
Amortization of unearned restricted stock compensation		—			—	—			—				190				—		—				—				190
Balance at December 31, 2004 (Successor Company)		35,728			—	$	355		$	717,994			$	(2,093	)		$	—	$	(6,944	)		$	23			$	709,335

See Notes to Consolidated Financial Statements

F-10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Management’s Statement

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

(2) Nature of Operations and Basis of Consolidation

We are one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 617,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have distributed electricity and natural gas in Montana since 2002 under the trade name “NorthWestern Energy.”

The accompanying consolidated financial statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. The financial statements of Netexit and Blue Dot Services, Inc. (Blue Dot) are included in the accompanying consolidated financial statements by virtue of the voting and control rights, and therefore included in references to “subsidiaries.” Netexit and Blue Dot were not party to our recently concluded Chapter 11 case. However on May 4, 2004, Netexit filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. All significant intercompany balances and transactions have been eliminated from the consolidated financial statements. The operations of Netexit and Blue Dot and our interest in these subsidiaries have been reflected in the consolidated financial statements as Discontinued Operations (see Note 9 for further discussion). We continue to consolidate the operations and financial position of Netexit in our financial statements as we believe that the continued consolidation results in a more meaningful presentation due to our negative investment, our expectation that the bankruptcy will be brief and we will control Netexit upon its emergence from bankruptcy.

F-11

In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R. FIN 46R was issued to replace FIN 46 and clarify the accounting for interests in variable interest entities. FIN 46R requires the consolidation of entities which are determined to be variable interest entities (VIEs) when the reporting company determines that it will absorb a majority of the VIE’s expected losses, receive a majority of the VIE’s residual returns, or both. The company that is required to consolidate the VIE is called the primary beneficiary. Conversely, the reporting company would be required to deconsolidate VIEs that are currently consolidated when the company is not considered to be the primary beneficiary. Variable interests are contractual, ownership or other monetary interests in an entity that change as the fair value of the entity’s net assets exclusive of variable interests change. An entity is considered to be a VIE when its capital is insufficient to permit it to finance its activities without additional subordinated financial support or its equity investors, as a group, lack the characteristics of having a controlling financial interest. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility, and while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We will continue to make appropriate efforts to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. We continue to account for this qualifying facility contract as an executory contract. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $592.6 million through 2025.

(3) Emergence from Bankruptcy and Fresh-Start Reporting

Plan of Reorganization

The Bankruptcy Court entered a written order confirming our Plan on October 19, 2004, and the Plan became effective on November 1, 2004. The consummation of the Plan resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors. In general, the terms of our Plan provided for the following:

· Holders of our senior unsecured notes (Class 7 claimants) received 28.3 million shares of new common stock in exchange for $898.3 million in allowed claims;

· Holders of TOPrS (Class 8a claimants) received 2.3 million shares of new common stock and warrants for an additional 4.4 million shares of common stock in exchange for $321.1 million in allowed claims. The warrants may be exercised for a period of three years from the effective date;

· Holders of QUIPs (Class 8b claimants), were allowed to select either of the following: (i) receive a pro rata share of 0.5 million shares of new common stock, plus warrants with the same terms as the warrants distributed to the TOPrS, in exchange for their claims, including any litigation claims, or (ii) continue the litigation against us generally referred to as the QUIPs Litigation and will receive a distribution based on a Class 9 claim, if any, based only upon final resolution of the QUIPs Litigation;

F-12

· Secured debt was not impaired and has been assumed; and

· Common stock existing prior to November 1, 2004 was cancelled and there were no distributions to prior shareholders.

Under Chapter 11, certain claims against us in existence prior to the filing of the petition for relief under the Bankruptcy Code were stayed while we continued operations as a debtor-in-possession. Those claims were reflected in the December 31, 2003 consolidated balance sheet as liabilities subject to compromise. Prior to the application of fresh-start reporting, the Predecessor Company’s October 31, 2004 consolidated balance sheet included related balances subject to compromise (refer to table below). However, the adoption of fresh-start reporting results in the settlement of such balances based on the estimated payment amounts pursuant to the Plan with the difference recorded as a reorganization gain in the consolidated statement of income (loss) for the 10-months ended October 31, 2004. Determination by the Bankruptcy Court (or agreed to by parties in interest) of remaining disputed unsecured prepetition claims as allowed claims for contingencies and other disputed amounts may impact these results. Remaining disputed unsecured claims, when allowed, will receive shares out of the reserve set aside upon emergence.

Reorganization Items

The results of operations of the Predecessor and Successor Company have been impacted by Reorganization Items, including continued costs incurred related to our reorganization since we filed for protection under Chapter 11 and the impact of fresh-start reporting. The following table provides detail of the charges incurred (in thousands):

	Successor Company			Predecessor Company
	Period Ended						Year Ended December 31,
	December 31, 2004			October 31, 2004			2003			2002
Reorganization Items
Professional fees		$	437	$	39,271		$	8,280		$	—
Interest earned on accumulated cash				(381		)	(14		)	—
Effects of the Plan and fresh-start reporting adjustments				(571,953		)	—			—
Total Reorganization Items		$	437	$	(533,063	)	$	8,266		$	—

F-13

Included in Reorganization Items for the period ended October 31, 2004 was the Predecessor Company’s gain recognized from the effects of the Plan and fresh-start reporting. The gain results from the difference between the Predecessor Company’s carrying value of unsecured debt and the issuance of new common stock and the discharge of liabilities subject to compromise pursuant to the Plan. The gain from the effects of the Plan and the application of fresh-start reporting is comprised of the following (in thousands):

	Predecessor Company
	10-Months Ended October 31, 2004
Effects of the Plan and fresh-start reporting
Issuance of new common stock and warrants	$	713,782
Discharge of financing debt subject to compromise	(904,809		)
Discharge of company obligated mandatorily redeemable preferred securities subject to compromise	(367,026		)
Cancellation of indebtedness income	(558,053		)
Discharge of other liabilities subject to compromise	(13,900		)
	$	(571,953	)

Fresh-Start Reporting

In connection with our emergence from Chapter 11, we reflected the terms of the Plan in our consolidated financial statements as of the close of business on October 31, 2004, applying fresh-start reporting under SOP 90-7. Fresh-start reporting is required if (1) the reorganization value of the emerging entity’s assets immediately before the date of confirmation is less than the total of all postpetition liabilities and allowed claims, and (2) holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. Upon applying fresh-start reporting, a new reporting entity (the Successor Company) is deemed to be created and the recorded amounts of assets and liabilities are adjusted to reflect their estimated fair values. The reported historical financial statements of the Predecessor Company for periods ended prior to November 1, 2004 generally are not comparable to those of the Successor Company.

To facilitate the calculation of the enterprise value of the Successor Company as defined in SOP 90-7, we developed a set of financial projections and engaged an independent financial advisor to assist in the determination. The enterprise value was determined using various valuation methods including, (i) reviewing historical financial information (ii) comparing the company and its projected performance to the market values of comparable companies, (iii) performing industry precedent transaction analysis, and (iv) considering certain economic and industry information relevant to the operating business. The resulting enterprise value was calculated using a 7% discount rate to be within an approximate range of $1.415 billion to $1.585 billion. We selected the midpoint value of the range, $1.5 billion, as the reorganization value. This value is consistent with the Voting Creditors and Bankruptcy Court approval of our Plan.

In applying fresh-start reporting, we followed these principles:

· The reorganization value was allocated to the assets in conformity with the procedures specified by Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. The enterprise value exceeded the sum of the amounts assigned to assets and liabilities, with the excess allocated to goodwill.

F-14

· Deferred taxes were reported in conformity with applicable income tax accounting standards, principally SFAS No. 109, Accounting for Income Taxes. Deferred taxes assets and liabilities have been recognized for differences between the assigned values and the tax basis of the recognized assets and liabilities (see Note 13).

· Adjustment of our qualified pension and other postretirement benefit plans to their projected benefit obligation by recognition of all previously unamortized actuarial gains and losses.

· Reversal of all items included in other comprehensive loss, including recognition of the Predecessor Company’s minimum pension liability, recognition of all previously unrecognized cumulative translation adjustments and removal of a hedge gain associated with unsecured debt.

· Changes in existing accounting principles that otherwise would have been required in the consolidated financial statements of the emerging entity within the 12 months following the adoption of fresh-start reporting were adopted at the fresh-start reporting date.

· Each liability existing as of the Plan confirmation date, other than deferred taxes, was recorded at the present value of amounts to be paid determined at our computed incremental borrowing rate.

F-15

The following table identifies the adjustments recorded to the Predecessor Company’s October 31, 2004 consolidated balance sheet as a result of implementing the Plan and applying fresh-start reporting (in thousands):

	Predecessor			Effects of					Successor
	Company			Plan and					Company
	October 31,			Fresh-Start					October 31,
	2004			Reporting					2004
Assets
Current Assets:
Cash and cash equivalents	$	103,829		$			—		$		103,829
Restricted cash	39,894			—					39,894
Accounts receivable, net	94,963			—					94,963
Inventories	31,863			—					31,863
Regulatory assets	15,465			1,871				(1)	17,336
Prepaid energy supply	29,048			—					29,048
Other	27,625			3,469				(1)	31,094
Assets held for sale	30,000			—					30,000
Current assets of discontinued operations	81,617			—					81,617
Total current assets	454,304			5,340					459,644
Property, plant and equipment, net	1,371,622			—					1,371,622
Goodwill	375,798			59,278				(2)	435,076
Other:
Investments	8,971			—					8,971
Regulatory assets	200,305			24,928				(3)	225,233
Other	51,814			(27,435				)(4)	24,379
Noncurrent assets of discontinued operations	39			—					39
Total assets	$	2,462,853		$			62,111		$		2,524,964
Liabilities and Shareholders’ Equity (Deficit)
Current Liabilities:
Current maturities of long-term debt	$	910,154		$		(833,634		)(5)	$		76,520
Accounts payable	79,960			6,420				(5)	86,380
Accrued liabilities	149,264			10,473				(1)(5)	159,737
Regulatory liabilities	18,830			—					18,830
Current liabilities of discontinued operations	18,539			—					18,539
Total current liabilities	1,176,747			(816,741				)	360,006
Long-term debt	—			833,634				(5)	833,634
Deferred income taxes	—			45,292				(6)	45,292
Noncurrent regulatory liabilities	158,694			—					158,694
Other noncurrent liabilities	207,409			203,401				(1)(3)(4)	410,810
Noncurrent liabilities and minority interests of discontinued operations	462			—					462
Total liabilities not subject to compromise	1,543,312			265,586					1,808,898
Liabilities subject to compromise:
Financing debt	864,114			(864,114				)(7)	—
Trade creditors	312,555			(312,555				)(4)	—
Company obligated mandatorily redeemable preferred securities of subsidiary trusts	365,550			(365,550				)(7)	—
Total liabilities subject to compromise	1,542,219			(1,542,219				)	—
Total liabilities	3,085,531			(1,276,633				)	1,808,898
Shareholders’ equity (deficit)	(622,678		)	1,338,744				(7)(8)	716,066
Total liabilities and shareholders’ equity (deficit)	$	2,462,853		$	62,111				$	2,524,964

(1) Represents adjustments to assets and liabilities resulting from the fair value provisions of fresh-start reporting.

(2) Reflects the excess reorganization value pursuant to the valuation under our Plan and in accordance with fresh-start reporting. Based on certain regulatory considerations, our property, plant and

F-16

equipment should be kept at historical book value less adjustments which reduce these assets to the amount included in the utility rate base, therefore management has applied the entire excess reorganization value to goodwill.

(3) Reflects the adjustment of our pension and other postretirement benefit obligations to fair value based on independent actuarial reports.

(4) Reflects the removal of unamortized deferred financing costs and accrued interest related to debt extinguished upon emergence.

(5) Reflects the reclassification of secured debt from current to long-term and other trade claims from subject to compromise to not subject to compromise, which pursuant to the Plan were unimpaired and reinstated.

(6) Reflects the adjustment of deferred tax assets and liabilities as a result of the impact of the gain related to cancellation of indebtedness, the removal of certain liabilities subject to compromise, and the fair value adjustments in accordance with the Plan.

(7) Reflects the conversion of our unsecured debt and company obligated mandatorily redeemable preferred securities into equity pursuant to the Plan.

(8) Represents the elimination of historical shareholders’ deficit and issuance of new common stock pursuant to the Plan.

Liabilities Subject to Compromise

Liabilities subject to compromise represent the liabilities of the Debtor prior to the Petition Date, and consisted of the following trade creditor liabilities (in thousands):

	Predecessor Company
	October 31, 2004			December 31, 2003
Pension and other postretirement benefit liability	$	23,437			$	23,168
Future QF obligation, net	143,826				142,815
Environmental liability	45,318				43,927
Accrued interest and preferred dividends	46,869				46,869
Hedge gain	13,247				13,247
Accounts payable and other	39,858				17,777
	312,555				$	287,803
Application of fresh-start reporting	(312,555		)
Liabilities subject to compromise (Successor Company)	$	—

For the amounts reported as liabilities subject to compromise in the table above, the Predecessor Company analyzed pre-petition liabilities against actual claims by creditors and recorded an estimate of allowed claims. In addition, the contracts representing these liabilities were reviewed and accepted or rejected by the Predecessor Company as applicable.

(4) Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

F-17

Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncollectible accounts, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better information or when we can determine actual amounts. Those revisions can affect operating results.

Revenue Recognition

For our South Dakota and Nebraska operations, as prescribed by the respective regulatory authorities, electric and natural gas utility revenues are based on billings rendered to customers. For our Montana operations, as prescribed by the MPSC, operating revenues are recorded monthly on the basis of consumption or services rendered. Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electrical and natural gas services delivered to the customers but not yet billed at month-end.

Cash Equivalents

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

Restricted Cash

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

Accounts Receivable, Net

Accounts receivable are net of $2.1 million, $2.1 million and $2.0 million of allowances for uncollectible accounts at December 31, 2004, October 31, 2004 and December 31, 2003, respectively. Receivables include unbilled revenues of $58.1 million, $43.1 million and $40.7 million at December 31, 2004, October 31, 2004 and December 31, 2003, respectively.

Inventories

Inventories are stated at average cost. Inventory consisted of the following (in thousands):

	Successor Company						Predecessor Company
	December 31, 2004			October 31, 2004			December 31, 2003
Materials and supplies		$	13,653		$	13,854		$	12,810
Storage gas		14,380			18,009			13,711
		$	28,033		$	31,863		$	26,521

Regulation of Utility Operations

Our regulated operations are subject to the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). Our financial statements reflect the effects of the different rate making principles followed by the jurisdiction regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are expected to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated

F-18

company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).

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

Investments

Investments consist primarily of life insurance contracts and money market accounts. Life insurance contracts are carried at their cash surrender value. Investments in life insurance contracts of $3.7 million, $3.7 million and $3.6 million are held in trust and restricted for postretirement benefits as of December 31, 2004, October 31, 2004 and December 31, 2003, respectively. Investments in money market accounts of $3.3 million, $3.3 million and $3.6 million are restricted to satisfy certain debt requirements as of December 31, 2004, October 31, 2004 and December 31, 2003, respectively.

We use the specific identification method for determining the cost basis of our investments in available-for-sale securities. Realized gains and (losses) on our available-for-sale securities were $0.4 million and $(7.5) million in 2003 and 2002, respectively. There were no realized gains and losses during 2004.

Derivative Financial Instruments

In the past, we have managed risk using derivative financial instruments for changes in electric and natural gas supply prices and interest rate fluctuations. We have also periodically used commodity futures contracts to reduce the risk of future price fluctuations for electric and natural gas contracts. Increases or decreases in contract values are reported as gains and losses in our Consolidated Statements of Income (Loss) unless the commodities are specifically subject to supply tracking mechanisms within the regulatory environment.

In December 2004, we adopted a formal energy risk management policy to govern our electricity and natural gas commodity purchases and sales. Under the language of the policy, we are precluded from using derivative financial instruments to manage our commodity price volatility risk unless specifically authorized by our internal energy supply board. The policy, however, does not preclude the use of derivative financial instruments to mitigate interest rate fluctuations.

The fair value of fixed-price commodity contracts is estimated based on prevailing market prices of commodities covered by the contracts. As of December 31, 2004 and October 31, 2004 we had three outstanding fixed price sales contracts that were not hedged. As of December 31, 2004 and October 31, 2004 we have a liability related to these obligations of $2.6 million and $2.3 million, respectively. As of December 31, 2003, we had outstanding call obligations for physical delivery of 3.3 million MMBTU of natural gas during February and March of 2004. We had a liability related to these obligations of $1.8 million based on the market value of natural gas as of December 31, 2003. We settled these calls during January and February 2004, resulting in a gain of approximately $526,000.

Property, Plant and Equipment

Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility

F-19

plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under capital lease, which are stated at the present value of minimum lease payments. Plant and equipment under capital lease were $10.9 million, $10.5 million and $12.6 million as of December 31, 2004, October 31, 2004 and December 31, 2003, respectively.

AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. We determine the rate used to compute AFUDC in accordance with a formula established by the FERC. This rate averaged 9.0%, 8.9% and 8.7% for Montana for 2004, 2003 and 2002, and 7.9%, 10.7%, and 6.6% for South Dakota for 2004, 2003 and 2002, respectively. Interest capitalized totaled $0.2 million for the two-months ended December 31, 2004, $1.0 million for the 10-months ended October 31, 2004, and $0.9 million and $1.1 million for the years ended December 31, 2003 and 2002, respectively for Montana and South Dakota combined.

We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from three to forty years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 3.5%, 3.5%, and 3.4% for 2004, 2003 and 2002, respectively.

Internal labor and overhead costs capitalized for other property, plant and equipment were $6.0 million for the two-months ended December 31, 2004, $24.6 million for the 10-months ended October 31, 2004, and $29.2 million and $33.6 million for the years ended December 31, 2003 and 2002, respectively.

Depreciation rates include a provision for our share of the estimated costs to decommission three coal-fired generating plants at the end of the useful life of each plant. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities.

Other Noncurrent Liabilities

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

	Successor Company						Predecessor Company
	December 31, 2004			October 31, 2004(1)			December 31, 2003
Pension and other postretirement benefit liability		$	173,166		$	173,634		$	155,238
Future QF obligation, net(2)		143,381			143,826			142,815
Environmental liability(2)		45,317			45,318			43,927
Deferred revenue		—			—			14,317
Customer advances		25,269			24,524			22,841
Other		22,867			23,508			63,195
		$	410,000		$	410,810		$	442,333

(1) Reflects the application of fresh-start reporting.

(2) These amounts were previously classified as liabilities subject to compromise as of December 31, 2003.

F-20

Stock-based Compensation

The Successor Company prospectively adopted SFAS No. 123-R, Share-Based Payment, upon emergence, with no impact to the financial statements or disclosure required as stock-based compensation consists of restricted shares of common stock. The Predecessor Company had a nonqualified stock option plan to provide for the granting of stock-based compensation to certain employees and directors, which was terminated upon our emergence from bankruptcy. The Predecessor Company accounted for this plan in accordance with the intrinsic value based method of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting. No compensation cost is recognized as the option exercise price is equal to the market price of the underlying stock on the date of grant.

If compensation costs had been recognized based on the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, the pro forma net loss of the Predecessor Company would have been as indicated below (in thousands):

	Predecessor Company
	Period Ended			Year Ended December 31,
	January 1- October 31, 2004			2003			2002
Earnings (losses) on common stock
As reported		$	551,377	$	(128,670	)	$	(892,943	)
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		—		—			(409		)
Pro forma		$	551,377	$	(128,670	)	$	(893,352	)

Historical earnings per share information for the Predecessor Company has not been presented as all shares were cancelled upon emergence from bankruptcy.

Insurance Subsidiary

Risk Partners Assurance, Ltd is a wholly owned non-United States insurance subsidiary established in 2001 to insure worker’s compensation, general liability and automobile liability risks. Blue Dot purchased insurance through Risk Partners from February 16, 2002 through August 31, 2003. Claims that were incurred during that time period continue to be paid and managed by Risk Partners. On September 1, 2003, Blue Dot purchased insurance from a third party insurance carrier. Netexit (f/k/a Expanets) was insured through Risk Partners from November 15, 2001 through November 15, 2002. Claims that were incurred during that time period continue to be paid and managed by Risk Partners. Reserve requirements are established based on actuarial projections of ultimate losses. Any losses estimated to be paid within one year from the balance sheet date are classified as accrued expenses, while losses expected to be payable in later periods are included in other long-term liabilities. Risk Partners has purchased reinsurance policies through a third-party reinsurance company to transfer a portion of the insurance risk. Restricted cash held by this subsidiary was $10.0 million at December 31, 2004 and $10.2 million at October 31, 2004.

Income Taxes

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

F-21

Environmental Costs

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

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

New Accounting Standards

In December 2004, the FASB issued a revision to SFAS No. 123, Accounting for Stock-Based Compensation, SFAS No. 123-R. SFAS No. 123-R requires companies to record compensation expense for all share-based awards granted subsequent to the adoption of the statement. In addition, SFAS 123-R requires the recording of compensation expense for the unvested portion of previously granted awards that remain outstanding at the date of adoption. In accordance with SOP 90-7 and the provisions of fresh-start reporting, we early adopted the provisions of SFAS 123-R prospectively as of October 31, 2004. As all stock-based compensation of the Predecessor Company was cancelled upon emergence, adoption of the statement did not impact our financial condition or results of operations.

Reclassifications

Certain 2002 and 2003 amounts have been reclassified to conform to the 2004 presentation. Such reclassifications had no impact on net income (loss) or shareholders’ equity (deficit) as previously reported.

F-22

Supplemental Cash Flow Information

	Successor Company			Predecessor Company
	November 1- December 31,			January 1- October 31,			Year Ended December 31,
	2004			2004			2003			2002
Cash paid (received) for
Income taxes		$	203	$	(4,637	)	$	(13,038	)	$	(17,572	)
Interest		16,192		47,364			101,778			163,045
Reorganization interest income		—		(381		)	(14		)	—
Reorganization professional fees and expenses		4,760		34,090			1,371			—
Noncash transactions for
Fair value of notes receivable received in exchange for sales of discontinued operations		$	—	$	—		$	1,600		$	—
Debt instruments exchanged for stock		—		558,053			—			—
Liabilities exchanged for stock		—		13,900			—			—
Assets acquired in exchange for debt		—		—			193			—
Investments utilized for debt repayment		—		1,474			—			—
Debt and preferred securities assumed in acquisitions		—		—			—			511,100

(5) Assets Held for Sale

We are attempting to sell our interest in Montana Megawatts I, LLC, or MMI, our indirect wholly-owned subsidiary that owns the Montana First Megawatts generation project, a partially constructed, 260 megawatt, natural gas-fired, combined-cycle electric generation facility located in Great Falls, Montana. Based upon an evaluation of the generation equipment market by our equipment broker, we recorded a $10 million impairment charge to reduce the assets to their estimated realizable value in December 2004. We have previously recorded impairment charges of $12.4 million and $35.7 million for the years ended December 31, 2003 and 2002, respectively, in our All Other segment based upon the estimated realizable value of our investment at that time. The remaining assets of this project continue to be classified as Assets Held For Sale on the Consolidated Balance Sheets as we are actively trying to sell these assets.

(6) Property, Plant and Equipment

The following table presents the major classifications of our property, plant and equipment (in thousands):

	Successor Company							Predecessor Company
	December 31,				October 31,			December 31,
	2004				2004			2003
Land and improvements		$	38,383		$	38,190			$	37,912
Building and improvements		110,626			112,076				110,117
Storage, distribution, transmission and generation		1,801,368			1,772,939				1,727,111
Construction work in process		13,565			31,355				19,989
Other equipment		199,971			197,575				199,362
		2,163,913			2,152,135				2,094,491
Less accumulated depreciation		(784,853		)	(780,513		)		(733,676		)
		$	1,379,060		$	1,371,622			$	1,360,815

F-23

(7) Asset Retirement Obligations

We have identified, but have not recognized, asset retirement obligation, or ARO, liabilities related to our electric and natural gas transmission and distribution assets. Many of these assets are installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.

Our regulated utility operations have, however, previously recognized removal costs of transmission and distribution assets as a component of depreciation in accordance with regulatory treatment. These amounts do not represent Statement of Financial Accounting Standards (SFAS) No. 143 legal retirement obligations. As of December 31, 2004, October 31, 2004 and December 31, 2003, we have recognized accrued removal costs of $132.9 million, $131.3 million and $123.0 million, respectively, which are included in noncurrent regulatory liabilities. In addition, related to our nonregulated operations, we have recognized accrued removal costs of $2.0 million, $2.0 million and $1.9 million as of December 31, 2004, October 31, 2004 and December 31, 2003.

For our generation properties, we have accrued decommissioning costs since the generating units were first put into service in the amount of $12.3 million, $12.3 and $11.9 million as of December 31, 2004, October 31, 2004 and December 31, 2003, respectively, which is classified as a noncurrent regulatory liability. These amounts also do not represent SFAS No. 143 legal retirement obligations.

(8) Goodwill

Effective January 1, 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 changed the accounting for goodwill from a model that required amortization of goodwill, supplemented by impairment tests, to an accounting model that is based solely upon impairment tests. We review goodwill for impairment annually during the fourth quarter, or more frequently if changes in circumstances or the occurrence of events suggest an impairment exists.

We retained a third party to conduct a valuation analysis in connection with our fresh-start reporting. Our consolidated enterprise value was estimated at $1.5 billion, providing for an equity value of $710 million. Upon the adoption of fresh-start reporting on October 31, 2004, we adjusted our assets and liabilities to their fair values and valued our equity to $710 million. Since we are a regulated utility, our regulated property, plant and equipment is kept at values included in utility rate base, and the excess of reorganization value over the fair value of assets and liabilities on the date of our emergence of $435.1 million has been recorded as goodwill.

Goodwill by segment as of December 31, 2004 and October 31, 2004 is as follows (in thousands):

Regulated electric	$	295,377
Regulated natural gas	139,699
Unregulated electric	—
Unregulated natural gas	—
	435,076

F-24

(9) Discontinued Operations

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

As of December 31, 2004, October 31, 2004 and December 31, 2003, Netexit had current assets of $66.3 million, $66.6 million and $59.9 million and current liabilities of $15.6 million, $15.9 million and $11.8 million, respectively.

F-25

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

	Successor Company				Predecessor Company
	Period Ended								Year Ended December 31,
	November 1-				January 1-
	December 31,				October 31,
	2004				2004				2003			2002
Revenues		$	—			$	—		$	541,211		$	710,452
Income (Loss) before income taxes and minority interests		$	(78	)		$	(8,893	)	$	1,360		$	(422,802	)
Gain (loss) on disposal		—				11,500			(49,250		)	—
Minority interests		—				—			—			11,152
Income tax provision		—				—			—			(22,780		)
Income (Loss) from discontinued operations, net of income taxes and minority interests		$	(78	)		$	2,607		$	(47,890	)	$	(434,430	)

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

As of December 31, 2004, Blue Dot had one remaining business. In December 2004, Blue Dot paid us $10 million in cash, in partial satisfaction of its dividends payable on preferred stock.

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

	Successor Company			Predecessor Company
	December 31, 2004			October 31, 2004			December 31, 2003
Accounts receivable, net		$	112		$	153		$	27,588
Other current assets		4,699			14,832			18,660
Current assets of discontinued operations		$	4,811		$	14,985		$	46,248
Other noncurrent assets of discontinued operations		$	37		$	39		$	306
Accounts payable		$	291		$	280		$	11,486
Other current liabilities		2,478			2,376			21,215
Current liabilities of discontinued operations		$	2,769		$	2,656		$	32,701
Other noncurrent liabilities of discontinued operations		$	443		$	462		$	1,998

	Successor Company				Predecessor Company
	Period Ended
	November 1-				January 1-
	December 31,				October 31,				Year Ended December 31,
	2004				2004				2003			2002
Revenues		$	724			$	28,209		$	400,679		$	471,824
Loss before income taxes and minority interests		$	(248	)		$	(4,282	)	$	(3,356	)	$	(311,674	)
Gain (Loss) on disposal		(98		)		4,163			14,352			—
Minority interests		—				—			—			3,762
Income tax provision		—				—			—			(9,071		)
Income (Loss) from discontinued operations, net of income taxes and minority interests		$	(346	)		$	(119	)	$	10,996		$	(316,983	)

F-26

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

	2003			2002
Revenues	$	19,493		$	422,816
Income (Loss) before income taxes, net of minority interests	$	456		$	(21,584	)
Loss on disposal	(5,705		)	(97,055		)
Income tax benefit	—			15,466
Loss from discontinued operations, net of income taxes and minority interests	$	(5,249	)	$	(103,173	)

Effective November 1, 2002, we relinquished our direct and indirect equity interests in CornerStone Propane Partners, LP and CornerStone Propane, LP (collectively, CornerStone). The results for CornerStone’s operations and impairments related to our investments in and advances to CornerStone for the year ended December 31, 2002, have been presented as discontinued operations in the Consolidated Statements of Income (Loss). CornerStone filed proofs of claims against us aggregating approximately $310 million asserting that we owed them for capital account contribution obligations and obligations related to requirements to transfer title of certain real property. We filed an objection disputing these claims on July 13, 2004, as we did not believe they were valid. On June 3, 2004, CornerStone filed petitions for relief under Chapter 11 of the Bankruptcy Code. We filed a proof of claim against CornerStone for a $29.5 million secured claim, which arose due to our August 2002 purchase of a lenders’ interest in CornerStone’s credit facility. We filed additional proofs of claim against CornerStone totaling $23.2 million related to previous intercompany obligations and payments on letters of credit on behalf of CornerStone. In previous years, we took impairment charges to reduce our note receivable and other advances to an estimated recoverable amount. Under the terms of a settlement agreement reached with CornerStone, we received a $15 million allowed secured claim in CornerStone’s bankruptcy proceedings and we allowed CornerStone a $19.5 million general unsecured, or Class 9, claim under our plan of reorganization. During the third quarter of 2004, we recorded a loss of $19.5 million based on the settlement. CornerStone received 614,125 shares of our newly issued common stock in satisfaction of their allowed claim. While we recorded a loss of $19.5 million during the third quarter of 2004, this allowed claim had no cash impact. As a Class 9 claim it diluted the distribution to other general unsecured creditors, therefore we recognized a gain upon emergence from bankruptcy of an additional $19.5 million. In December 2004, we sold our secured claim against CornerStone and received $15 million in cash. As of December 31, 2004, we have no remaining interest in or receivables from CornerStone.

F-27

(10) Long-Term Debt

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

		Successor Company							Predecessor Company
	Due	December 31, 2004				October 31, 2004			December 31, 2003
Secured Debt:
Senior Secured Term Loan	2006		$	—		$	383,175		$	386,100
Senior Secured Term Loan B	2011		100,000			—			—
Mortgage bonds—
South Dakota—7.10%	2005		60,000			60,000			60,000
South Dakota—7.00%	2023		55,000			55,000			55,000
Montana—7.30%	2006		150,000			150,000			150,000
Montana—8.25%	2007		365			365			365
Montana—8.95%	2022		—			1,446			1,446
Montana—7.00%	2005		5,386			5,386			5,386
South Dakota & Montana—5.875%	2014		225,000			—			—
Pollution control obligations—
South Dakota—5.85%	2023		7,550			7,550			7,550
South Dakota—5.90%	2023		13,800			13,800			13,800
Montana—6.125%	2023		90,205			90,205			90,205
Montana—5.90%	2023		80,000			80,000			80,000
Secured medium term notes—
7.25%	2008		—			13,000			13,000
Montana Natural Gas Transition Bonds	2012		42,450			42,450			46,502
Capital leases	Various		9,623			10,269			12,399
Other term debt	Various		—			—			1,122
Discount on Notes and Bonds	—		(2,433		)	(2,492		)	(2,752		)
Unsecured Debt Subject to Compromise:
Senior Unsecured Notes—7.875%	2007		$	—		$	—		$	250,000
Senior Unsecured Notes—8.75%	2012		—			—			470,000
Senior Unsecured debt—6.95%	2028		—			—			105,000
Unsecured medium term notes—
7.07%	2006		—			—			15,000
7.875%	2026		—			—			20,000
7.96%	2026		—			—			5,000
Discount on Notes and Bonds	—		—			—			(886		)
			836,946			910,154			1,784,237
Less current maturities			(73,380		)	(76,520		)	(1,784,237		)
			$	763,566		$	833,634		$	—

F-28

The Predecessor Company’s bankruptcy filing caused the Predecessor Company to breach certain covenants on pre-petition debt and accordingly all debt was classified as current as of December 31, 2003.

Long-Term Debt Subject to Compromise

Pre-petition unsecured debt was classified as subject to compromise as of December 31, 2003. In connection with our emergence from bankruptcy the unsecured debt holders were issued shares in satisfaction of their claim, including principal and interest through the petition date, and we have no further obligation. All deferred financing costs and original issue discounts related to unsecured debt were written-off upon emergence in accordance with SOP 90-7 (see Note 3).

Successor Company Long-Term Debt

On November 1, 2004 in connection with our emergence from bankruptcy, we entered into a new $225 million credit facility secured by our utility assets. The credit facility consists of a $125 million, five-year revolving tranche and a $100 million, seven-year term tranche (Senior Secured Term Loan B), which bears interest at a variable rate tied to the London Interbank Offered Rate (approximately 4% as of December 31, 2004). The revolving tranche replaced our DIP Facility and is available to us for general corporate purposes and for the issuance of letters of credit. Concurrently with the establishment of the new credit facility, we issued $225 million of our 5.875% senior secured notes due November 1, 2014. Borrowings under the term portion of the new credit facility, together with the net proceeds of the notes offering and available cash, were used to repay our $390 million senior secured term loan facility. As of December 31, 2004 we had $26.0 million in letters of credit outstanding and no borrowings under the revolving tranche of the facility. Commitment fees for the revolving tranche were approximately $63,000 for the two-months ended December 31, 2004. Commitment fees for the DIP facility were approximately $218,000 for the 10-months ended October 31, 2004 and $102,000 for the year ended December 31, 2003.

The new credit facility includes covenants, which require us to meet certain financial tests, including a minimum interest coverage ratio and a maximum debt to capitalization ratio. The facility also contains covenants which, among other things, limit our ability to incur additional indebtedness, create liens, engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, make restricted payments, make loans or advances, enter into transactions with affiliates, engage in business activities other than specified activities, and engage in other matters customarily restricted in such agreements. As of December 31, 2004 we are in compliance with these covenants.

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

The Montana First Mortgage Bonds, Montana Pollution Control Obligations, and Montana Natural Gas Transition Bonds are secured by substantially all of our Montana electric and natural gas assets.

The aggregate minimum principal maturities of long-term debt, during the next five years are $73.4 million in 2005, $157.6 million in 2006, $7.9 million in 2007, $7.4 million in 2008 and $7.0 million in 2009.

(11) Comprehensive Income (Loss)

The Financial Accounting Standards Board defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are excepted. Comprehensive income consists of net income and other comprehensive income (OCI). Net income may include such items as income from continuing operations,

F-29

discontinued operations, extraordinary items, and cumulative effects of changes in accounting principles. OCI may include foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities. Due to our emergence from bankruptcy we made adjustments for fresh-start reporting in accordance with SOP 90-7 as discussed in Note 3. These adjustments resulted in removal of items recorded in accumulated OCI of $6.0 million. Comprehensive income (loss) is calculated as follows (in thousands):

	Successor Company				Predecessor Company
	Period Ended						Year Ended December 31,
	December 31, 2004				October 31, 2004		2003			2002
Net income (loss)		$	(6,944	)	$	551,377	$	(113,725	)	$	(863,942	)
Other comprehensive income:
Net unrealized gain (loss) on available-for-sale securities, net of tax of $(188) and $713 in 2003 and 2002, respectively		—			—		(352		)	1,139
Net unrealized gain on derivative instruments qualifying as hedges, net of tax of $(224) and $2,757 in 2003 and 2002, respectively		—			—		(416		)	4,265
Minimum pension liability adjustment		—			—		(1,465		)	(8,759		)
Foreign currency translation adjustment		23			—		298			5
Total other comprehensive income (loss)		23			—		(1,935		)	(3,350		)
Total comprehensive income (loss)		$	(6,921	)	$	551,377	$	(115,660	)	$	(867,292	)

The after tax components of accumulated other comprehensive loss for the periods ended December 31, 2004, October 31, 2004 and year ended December 31, 2003, were as follows (in thousands):

	Successor Company						Predecessor Company
	December 31,			October 31,			December 31,
	2004			2004			2003
Balance at end of period,
Unrealized gain on derivative instruments qualifying as hedges		$	—		$	—		$	3,849
Minimum pension liability adjustment		—			—			(10,224		)
Foreign currency translation adjustment		23			—			303
Accumulated other comprehensive income (loss)		$	23		$	—		$	(6,072	)

(12) Financial Instruments

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

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

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

F-30

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

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

· The fair-value estimates presented herein are based on pertinent information available to us as of December 31, 2004, October 31, 2004 and December 31, 2003. Although we are not aware of any factors that would significantly affect the estimated fair-value amounts, such amounts have not been comprehensively revalued for purposes of these financial statements since that date, and current estimates of fair value may differ significantly from the amounts presented herein.

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

	Successor Company								Predecessor Company
	December 31, 2004				October 31, 2004				December 31, 2003
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Cash and cash equivalents	$	17,058	$	17,058	$	103,829	$	103,829	$	15,183	$	15,183
Restricted cash	18,115		18,115		39,894		39,894		27,043		27,043
Investments	8,876		8,876		8,971		8,971		11,027		11,027
Liabilities:
Long-term debt (including current portion)	836,946		843,207		910,154		911,149		1,784,237		1,704,392
Company obligated mandatorily redeemable preferred securities of subsidiary trusts	—		—		—		—		365,550		130,682

(13) Income Taxes

Income tax benefit applicable to continuing operations is comprised of the following (in thousands):

	Successor
	Company				Predecessor Company
	Period Ended								Year Ended December 31,
	November 1- December 31, 2004				January 1- October 31, 2004				2003				2002
Federal
Current		$	25			$	(810	)		$	(9,838	)	$	(30,333	)
Deferred		(4,232		)		(106		)		10,334			(8,761		)
Investment tax credits		(89		)		(453		)		(544		)	(535		)
State		(634		)		—				—			(182		)
		$	(4,930	)		$	(1,369	)		$	(48	)	$	(39,811	)

F-31

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

	Successor
	Company			Predecessor Company
	Period Ended						Year Ended December 31,
	November 1- December 31, 2004			January 1- October 31, 2004			2003			2002
Federal statutory rate		(35.0	)%		35.0	%		(35.0	)%		(35.0	)%
State income, net of federal provisions		(3.3	)		2.6			(3.9	)		(0.4	)
Amortization of investment tax credit		(0.8	)		(0.1	)		(0.8	)		(1.1	)
Depreciation of flow through items		(6.1	)		(0.5	)		1.3			—
Affiliated stock loss on disposition		—			—			(163.2	)		(60.6	)
Minority interest preferred stock		—			—			(7.3	)		(20.2	)
Dividends received deduction and other investments		—			—			(0.1	)		(1.2	)
Prior year tax return refund		—			(0.1	)		(8.5	)		—
Valuation allowance		—			(30.6	)		221.8			36.1
Prior year permanent return to accrual adjustments		—			(8.4	)		(7.3	)		—
Prior year permanent IRS examination adjustments		—			—			2.0			—
Other, net		2.1			1.8			0.9			1.4
		(43.1)	%		(0.3	)%		(0.1	)%		(81.0	)%

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

	Successor Company							Predecessor Company
	December 31,				October 31,			December 31,
	2004				2004			2003
Excess tax depreciation		$	(94,766	)	$	(90,818	)		$	(80,784	)
Regulatory assets		(30,195		)	(29,311		)		(6,867		)
Regulatory liabilities		169			171				4,040
Unbilled revenue		4,300			2,938				1,276
Unamortized investment tax credit		2,746			2,794				2,751
Compensation accruals		2,950			3,674				(3,790		)
Reserves and accruals		50,815			49,632				37,494
Goodwill impairment/amortization		(24,635		)	(24,696		)		(11,071		)
Net operating loss carryforward (NOL)		259,433			252,511				210,382
AMT credit carryforward		3,186			3,186				228
Deferred revenue		—			—				25,534
Capital loss carryforward		6,406			6,406				—
Deferred tax liability due to future attribute reduction		(207,029		)	(207,029		)		—
Valuation allowance		(12,758		)	(12,758		)		(181,587		)
Other, net		(1,976		)	(1,992		)		2,394
		$	(41,354	)	$	(45,292	)		$	—

A valuation allowance is recorded when a company believes that it will not generate sufficient taxable income of the appropriate character to realize the value of their deferred tax assets. We have a valuation allowance of $12.8 million as of December 31, 2004 and October 31, 2004 against capital loss carryforwards

F-32

and certain state NOL carryforwards as we do not believe these assets will be realized. The Predecessor Company recorded a valuation allowance of $181.6 million as of December 31, 2003, because prior to our emergence from bankruptcy it was considered more likely than not that all deferred tax assets would not be realized.

At December 31, 2004 we have a total NOL carryforward of $683.7 million. We expect to utilize approximately $583 million of these NOLs to offset cancellation of indebtedness income. If unused, $87.9 million of the NOL will expire in the year 2022, $490.5 million will expire in the year 2023 and $105.3 million will expire in the year 2024. Management believes it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards except as noted above.

We have elected under Internal Revenue Code 46(f)(2) to defer investment tax credit benefits and amortize them against expense and customer billing rates over the book life of the underlying plant.

An IRS audit of our federal income tax returns for the years 2000 through 2003 is currently in process. Management believes that the final results of these audits will not have a material adverse effect on our financial position or results of operations.

(14) Jointly Owned Plants

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

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

	Big Stone (S.D.)				Neal #4 (Iowa)				Coyote I (N.D.)
*Successor Company*
December 31, 2004
Ownership percentages		23.4		%		8.7		%		10.0		%
Plant in service		$	49,700			$	28,106			$	42,494
Accumulated depreciation		32,370				17,697				22,479
October 31, 2004
Ownership percentages		23.4		%		8.7		%		10.0		%
Plant in service		$	49,700			$	28,106			$	42,479
Accumulated depreciation		32,119				17,556				22,324

*Predecessor Company*
December 31, 2003
Ownership percentages	23.4		%	8.7		%	10.0		%
Plant in service	$	49,619		$	28,037		$	42,441
Accumulated depreciation	30,916			16,858			21,354

F-33

(15) Operating Leases

We have six years remaining under an operating lease agreement for a generation facility, which requires lease payments of $32.2 million annually. We also lease vehicles, office equipment, an airplane and office and warehouse facilities under various long-term operating leases. At December 31, 2004, future minimum lease payments under non-cancelable lease agreements are as follows (in thousands):

2005	$	33,303
2006	32,995
2007	32,638
2008	32,279
2009	32,235

Lease and rental expense incurred was $6.8 million, $32.5 million, $40.1 million and $39.9 million for the two-month period ended December 31, 2004, 10-month period ended October 31, 2004, and the years ended December 31, 2003 and December 31, 2002, respectively.

In January 2005, we exercised an option to extend the term of our Colstrip Unit 4 generation facility lease an additional eight years. By extending the lease term, our annual lease payment remains at $32.2 million through 2010 and decreases to $14.5 million for the remainder of the lease. Beginning in 2005 our lease expense will be reduced to $22.1 million annually based on a straight-line calculation over the full term of the lease.

(16) Employee Benefit Plans

Pension and Other Postretirement Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for employees. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. (See Note 18, Regulatory Assets and Liabilities, for the regulatory assets related to our pension and other postretirement benefit plans.) 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. As a result of fresh-start reporting (see Note 3), we adjusted our qualified pension and other postretirement benefit plans to their projected benefit obligation by recognition of all previously unamortized actuarial gains and losses upon emergence. The generation of any future amounts subsequent to emergence will be amortized under the same method as discussed above.

F-34

Benefit Obligations

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

	Pension Benefits											Other Postretirement Benefits
	Successor Company							Predecessor Company				Successor Company								Predecessor Company
	December 31, 2004				October 31, 2004			December 31, 2003				December 31, 2004				October 31, 2004				December 31, 2003
Reconciliation of Benefit Obligation
Obligation at beginning of period		$	372,485		$	356,373			$	329,980			$	53,015			$	66,948			$	103,352
Service cost		1,363			6,188				5,165				146				677				1,350
Interest cost		3,391			16,909				21,080				481				2,844				5,455
Actuarial (gain) loss		(71		)	14,116				23,446				(274		)		(2,189		)		(387		)
Plan amendments		—			—				—				—				—				(4,164		)
Curtailments		—			—				—				—				—				(3,077		)
Settlement cost		—			—				—				—				—				(16,566		)
Special termination benefits		—			—				785				—				—				—
Fresh-start reporting adjustments		—			(4,727		)		—				—				(11,354		)		—
Gross benefits paid		(3,189		)	(16,374		)		(24,083		)		(977		)		(3,911		)		(19,015		)
Benefit obligation at end of period		$	373,979		$	372,485			$	356,373			$	52,391			$	53,015			$	66,948

The total projected benefit obligation and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $374.0 million and $244.6 million, respectively, as of December 31, 2004. The total accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $371.8 million and $244.6 million, respectively, as of December 31, 2004.

The total projected benefit obligation and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $372.5 million and $233.9 million, respectively, as of October 31, 2004. The total accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $370.3 million and $233.9 million, respectively, as of October 31, 2004.

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

F-35

Balance Sheet Recognition

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

	Pension Benefits											Other Postretirement Benefits
	Successor Company							Predecessor Company				Successor Company								Predecessor Company
	December 31, 2004				October 31, 2004			December 31, 2003				December 31, 2004				October 31, 2004				December 31, 2003
Prepaid benefit cost		$	—		$	—			$	2,683			$	—			$	—			$	—
Accrued benefit cost		(140,097		)	(138,620		)		(66,880		)		(44,714		)		(45,171		)		(43,965		)
Additional minimum liability		—			—				(52,055		)		—				—				—
Intangible asset		—			—				1,597				—				—				—
Regulatory asset		—			—				40,234				—				—				—
Accumulated other comprehensive income		—			—				10,224				—				—				—
Net amount recognized		$	(140,097	)	$	(138,620	)		$	(64,197	)		$	(44,714	)		$	(45,171	)		$	(43,965	)

Amounts previously recorded in accumulated other comprehensive income, regulatory assets and intangible assets were reclassified to long-term liabilities to reflect the adoption of fresh-start reporting as of October 31, 2004 (see Note 3).

Plan Assets and Funded Status

	Pension Benefits											Other Postretirement Benefits
	Successor Company							Predecessor Company				Successor Company								Predecessor Company
	December 31, 2004				October 31, 2004			December 31, 2003				December 31, 2004				October 31, 2004				December 31, 2003
Reconciliation of Fair Value of Plan Assets
Fair value of plan assets at beginning of period		$	233,865		$	229,771			$	201,202			$	7,844			$	5,434			$	4,794
Actual return on plan assets		13,967			10,254				41,727				489				87				385
Employer contributions		—			10,214				10,925				977				6,234				35,836
Settlements		—			—				—				—				—				(16,566		)
Gross benefits paid		(3,189		)	(16,374		)		(24,083		)		(977		)		(3,911		)		(19,015		)
Fair value of plan assets at end of period		$	244,643		$	233,865			$	229,771			$	8,333			$	7,844			$	5,434
Funded Status		$	(129,335	)	$	(138,620	)		$	(126,602	)		$	(44,058	)		$	(45,171	)		$	(61,514	)
Unrecognized transition amount		—			—				309				—				—				—
Unrecognized net actuarial (gain) loss		(10,762		)	—				60,808				(656		)		—				17,549
Unrecognized prior service cost		—			—				1,288				—				—				—
Accrued benefit cost		$	(140,097	)	$	(138,620	)		$	(64,197	)		$	(44,714	)		$	(45,171	)		$	(43,965	)

Our investment goals with respect to managing the pension and other postretirement assets is to achieve and maintain a fully funded status for the pension plans, improve the status of the health and

F-36

welfare plan, minimize contribution requirements, and seek long-term growth by placing primary emphasis on capital appreciation and secondary emphasis on income, while minimizing risk.

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

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

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

The current investment strategy provides for the following asset allocation policies, within an allowable range of plus or minus 5%:

	Pension Benefits			Other Benefits
Debt securities		30.0	%		30.0	%
Domestic equity securities		60.0			60.0
International equity securities		10.0			10.0

The percentage of fair value of plan assets held in the following investment types by the NorthWestern Energy pension plan, NorthWestern Corporation pension plan and NorthWestern Energy Health and Welfare Plan as of December 31, 2004, October 31, 2004 and December 31, 2003, are as follows:

	NorthWestern Energy Pension									NorthWestern Corporation Pension									NorthWestern Energy Health and Welfare
	December 31, 2004			October 31, 2004			December 31, 2003			December 31, 2004			October 31, 2004			December 31, 2003			December 31, 2004			October 31, 2004			December 31, 2003
Cash and cash equivalents		2.0	%		2.4	%		1.4	%		0.9	%		2.0	%		0.6	%		—	%		0.1	%		2.8	%
Debt securities		31.6			33.2			28.5			—			—			11.6			27.5			29.2			27.5
Domestic equity securities		55.8			54.2			58.9			50.4			46.9			38.7			71.9			70.2			68.3
International equity securities		10.6			10.2			11.2			9.5			8.9			4.5			0.6			0.5			1.4
Participating group annuity contracts		—			—			—			39.2			42.2			44.6			—			—			—
		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

We review the asset mix of the funds on a quarterly basis. Generally, the fund’s asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels.

We are still evaluating the potential for liquidating and reinvesting the assets held in participating group annuity contracts as rebalancing and diversification opportunities are currently limited with respect to this portion of plan assets.

F-37

Actuarial Assumptions

The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2004, October 31, 2004, December 31, 2003 and 2002. The actuarial assumptions used to compute the net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management’s best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these items generally have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets.

Annually, we set the discount rate based upon our review of the Citigroup Pension Index and Moody’s Aa bond rate index. The expected long-term rate of return assumption on plan assets for both the NorthWestern Energy and NorthWestern Corporation pension and postretirement plans was determined based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension and postretirement portfolios. Over the 15-year period ending December 31, 2004, the returns on these portfolios, assuming they were invested at the current target asset allocation in prior periods, would have been a compound annual average of approximately 10.5%. Considering this information and the potential for lower future returns due to a generally lower interest rate environment, we selected an 8.5% long-term rate of return on assets assumption.

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

	Pension Benefits												Other Postretirement Benefits
	Successor Company			Predecessor Company									Successor Company			Predecessor Company
	Period Ended						Year ended						Period Ended						Year Ended
	November 1-			January 1-									November 1-			January 1-
	December 31,			October 31,			December 31,						December 31,			October 31,			December 31,
	2004			2004			2003			2002			2004			2004			2003		2002
Discount rate		5.50	%		5.50	%		6.00	%		6.50	%		5.50	%		5.50	%	6.0-6.75	%	6.0-6.75	%
Expected rate of return on assets		8.50	%		8.50	%		8.50	%		8.50	%		8.50	%		8.50	%	8.50	%	8.50	%
Long-term rate of increase in compensation levels (nonunion)		3.37	%		3.37	%		3.97	%		4.00	%		3.37	%		3.37	%	4.00	%	4.00	%
Long-term rate of increase in compensation levels (union)		3.30	%		3.30	%		3.50	%		3.50	%		3.30	%		3.30	%	4.00	%	3.50	%

The postretirement benefit obligation is calculated assuming that health care costs increased by 11% in 2004 and the rate of increase in the per capita cost of covered health care benefits thereafter was assumed to decrease gradually to 5% by the year 2009.

F-38

Net Periodic Cost

The components of the net costs for our pension and other postretirement plans are as follows (in thousands):

	Pension Benefits														Other Postretirement Benefits
	Successor Company				Predecessor Company										Successor Company				Predecessor Company
	Period Ended								Year Ended						Period Ended								Year Ended
	November 1-				January 1-										November 1-				January 1-
	December 31,				October 31,				December 31,						December 31,				October 31,				December 31,
	2004				2004				2003			2002			2004				2004				2003			2002
Components of Net Periodic Benefit Cost
Service cost		$	1,363			$	6,188		$	5,165		$	4,821			$	146			$	677		$	1,350		$	3,068
Interest cost		3,391				16,909			21,080			19,315				481				2,844			5,455			10,044
Expected return on plan assets		(3,277		)		(15,711		)	(16,329		)	(18,737		)		(107		)		(262		)	(261		)	(405		)
Amortization of transitional obligation		—				129			155			155				—				—			675			1,350
Amortization of prior service cost		—				311			505			626				—				—			—			—
Recognized actuarial (gain) loss		—				1,068			2,724			28				—				467			467			161
		1,477				8,894			13,300			6,208				520				3,726			7,686			14,218
Additional (income) or loss recognized:
Curtailment		—				—			—			833				—				—			13,511			—
Special termination benefits		—				—			785			5,858				—				—			—			168
Settlement cost		—				—			—			—				—				—			(13,586		)	—
Net Periodic Benefit Cost		$	1,477			$	8,894		$	14,085		$	12,899			$	520			$	3,726		$	7,611		$	14,386

Assumed health care cost trend rates have a significant effect on the amounts reported for the costs each year as well as on the accumulated postretirement benefit obligation. The following table sets forth the sensitivity of retiree welfare results (in thousands):

Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components	$	36
on postretirement benefit obligation	2,142
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components	$	(31	)
on postretirement benefit obligation	(1,930		)

In May 2004, the FASB issued Staff Position No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The impact of this Medicare prescription legislation has been analyzed and determined to have minimal impact due to the limited post-age 65 liability under the post-retirement benefit plan.

Cash Flows

We anticipate making contributions of approximately $25.7 million to our pension and other benefit plans in 2005. Pension funding is based upon annual actuarial studies prepared for each plan. For our postretirement welfare benefits, our policy is to contribute an amount equal to the annual actuarially determined cost that is also recoverable in rates. We generally fund our 401(h) and VEBA trusts monthly, subject to our liquidity needs and the maximum deductible amounts allowed for income tax purposes.

F-39

We estimate the plans will make future benefit payments to participants as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits
2005	$	19,961		$	4,093
2006	19,770			4,082
2007	19,902			4,055
2008	20,276			3,965
2009	20,426			3,990
2010-2014	116,081			17,996

Predecessor Company

The Predecessor Company sponsored two nonqualified, unfunded defined benefit pension plans, and three other postretirement benefit plans for certain officers and other employees. We have filed motions with the Bankruptcy Court to terminate these plans. Upon the determination of the motions, assuming the Bankruptcy Court permits termination, participants in these plans will receive allowed claims that will be paid in shares from the claims reserve. In accordance with SOP 90-7 and fresh-start reporting, these liabilities were removed from the balance sheet upon emergence and the impact of the termination is reflected in the tables above.

In May 2003, the Predecessor Company terminated or amended various employee benefit plans. The nonqualified supplemental 401(k) plan was terminated effective May 6, 2003. Any investment elections in our common stock were presented as Treasury Stock, other investments as part of Investments, and an offsetting liability for both as part of Other Noncurrent Liabilities in the Consolidated Balance Sheets. In June 2003, plan assets were distributed to participants and no further liability remains. The Predecessor Company’s contributions to the plan were $11,000 and $713,000 in 2003 and 2002, respectively. The Predecessor Company’s employee stock purchase plan was also terminated, with no impact to operating results. In addition, two nonqualified postretirement defined benefit plans were amended effective May 6, 2003 to permit vested participants the option of continuing the current benefits level or take a present value lump sum distribution. A third nonqualified postretirement defined benefit plan was terminated effective May 6, 2003. The impact of the amendments and termination are presented in the tables above.

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

Defined Contribution Plans

Through December 31, 2004 we sponsored two employee savings plans, which permit employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plans, the employees may elect to direct a percentage of their gross compensation to be contributed to the plans. We contribute various percentage amounts of the employee’s gross compensation contributed to the plan. Costs incurred under these plans were $0.6 million for the two-month period ended December 31, 2004, $2.7 million for the 10-month period ended October 31, 2004 and $3.1 million and $3.4 million in 2003 and 2002, respectively. On December 31, 2004, the NorthWestern Corporation savings plan was merged into the NorthWestern Energy savings plan.

F-40

(17) Employee Incentive Plans

Successor Company

In connection with the confirmation of our plan of reorganization, the Bankruptcy Court and Creditors Committee approved a New Incentive Plan to be established and administered by the new Board of Directors. The plan of reorganization reserved 2,265,957 shares of new common stock for the New Incentive Plan. In addition, upon emergence 228,315 restricted shares were issued (Special Recognition Grants) under the New Incentive Plan to certain officers and key employees. The fair value at the date of issuance for these Special Recognition Grants was $4.6 million. Fifty percent, or 114,158 shares of the Special Recognition Grants vested upon emergence. The remaining shares vest on November 1, 2005 for non-officers. For officers, the remaining shares vest 10% on November 1, 2005, 20% on November 1, 2006 and 20% on November 1, 2007. Compensation expense recognized for these Special Recognition Grants was $2.3 million for the 10-months ended October 31, 2004 and $0.2 million for the two months ended December 31, 2004.

Predecessor Company Stock Option and Incentive Plan

All common stock options under the NorthWestern Stock Option and Incentive Plan (Option Plan) were cancelled upon emergence from bankruptcy. Under the Option Plan, the Predecessor Company had reserved 3,424,595 shares for issuance to officers, key employees and directors as either incentive-based options or nonqualified options. The Compensation Committee (Committee) of our Board of Directors administered the Option Plan.

Information regarding the Predecessor Company’s options granted and outstanding is summarized below:

	Shares		Option Price Per Share		Weighted Average Option Price
Balance December 31, 2001	1,884,492		$	21.19-26.13		$	23.26
Issued	786,200		15.26-20.70			20.61
Canceled	(1,132,527	)	20.30-26.13			22.45
Balance December 31, 2002	1,538,165		15.26-26.13			22.49
Issued	500,623		2.05-4.90			3.97
Canceled	(679,600	)	20.30-26.13			22.23
Balance December 31, 2003	1,359,188					15.81
Application of fresh-start reporting (Note 3)	(1,359,188	)
Balance October 31, 2004 (Successor Company)	—

The Predecessor Company had also issued 283,333 shares of common stock in 2003 under a restricted stock plan with a fair value at date of issuance of $1.2 million. These shares were also cancelled upon emergence. The Predecessor Company had previously issued 33,480 shares of common stock in 2001 under this restricted stock plan with a fair value at date of issuance of $0.7 million. Compensation expense recognized was $0.4 million for the 10-months ended October 31, 2004 and $0.3 million and $0.5 million for the years ended December 31, 2003 and 2002, respectively. The Predecessor Company’s Employee Stock Ownership Plan (ESOP) was terminated effective July 19, 2003, and the shares were distributed to participants during 2003.

(18) Regulatory Assets and Liabilities

We prepare our financial statements in accordance with the provisions of SFAS No. 71, as discussed in Note 4 to the Financial Statements. Pursuant to this pronouncement, certain expenses and credits,

F-41

normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to the customers. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. We have specific orders to cover approximately 98% of our regulatory assets and approximately 96% of our regulatory liabilities.

			Remaining	Successor Company					Predecessor Company
	Note Ref.		Amortization Period	December 31, 2004			October 31, 2004		December 31, 2003
Pension		16	Undetermined		$	135,358	$	135,468		$	95,260
Competitive transition charges			9 Years		36,148		36,920			40,921
SFAS No. 106		16	Undetermined		35,567		35,947			27,150
Income taxes		13	Plant Lives		7,642		6,713			28,832
Supply costs			1-4 Years		9,557		13,184			32,579
Other			Various		13,072		14,337			14,666
Total regulatory assets					$	237,344	$	242,569		$	239,408
Removal cost			Various		$	145,257	$	143,603		$	134,857
Gas storage sales			35 Years		14,615		14,685			15,036
Supply costs			1 Year		17,968		17,222			13,542
Other			Various		2,252		2,014			2,273
Total regulatory liabilities					$	180,092	$	177,524		$	165,708

Through fresh-start reporting we adjusted our qualified pension and other postretirement benefit plans to their projected benefit obligation by recognition of all previously unamortized actuarial gains and losses. See Note 3 for further information regarding the impacts of fresh-start reporting. A pension regulatory asset has been recognized for the obligation that will be included in future cost of service. Historically, the MPSC rates have allowed recovery of pension costs on a cash basis. The SDPUC allows recovery of pension costs on an accrual basis. A regulatory asset has been recognized for the SFAS No. 106 fair value adjustments resulting from fresh-start reporting. The MPSC allows recovery of SFAS No. 106 costs on an accrual basis. Competitive transition charges relate to natural gas properties and earn a rate of return sufficient to meet the debt service requirements of the Montana natural gas transition bonds. A regulatory asset and liability has been recorded to reflect the future recovery of energy supply costs through the ratemaking process. Tax assets and liabilities primarily reflect the effects of plant related temporary differences such as removal costs, capitalized interest and contributions in aid of construction that we will recover or refund in future rates.

A regulatory liability has been recognized to reflect payments our customers have prepaid for future plant removal costs. A gas storage sales regulatory liability (cushion gas) was established in 2000 and 2001 based on gains on natural gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas and was fully amortized through rates in 2003.

(19) Deregulation and Regulatory Matters

Deregulation

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

F-42

Long Term Supply and Capacity Purchase Obligations

We have entered into various commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 30 years. Costs incurred under these contracts were approximately $72.1 million for the two-months ended December 31, 2004, $259.4 million for the 10-months ended October 31, 2004 and $281.6 million for the year ended December 31, 2003. As of December 31, 2004 our commitments under these contracts are $341.2 million in 2005, $228.7 million in 2006, $154.7 million in 2007, $96.2 million in 2008, $89.0 million in 2009 and $271.1 million thereafter. These commitments are not reflected in our Consolidated Financial Statements.

Employment Contracts

We have an Employment Agreement with Chief Financial Officer Brian B. Bird, which, as amended and approved by the Bankruptcy Court in its Order dated January 13, 2004, provides for him to serve as Chief Financial Officer, commencing December 1, 2003, and extends until the earlier of his termination of employment or December 1, 2005. For the first year of Mr. Bird’s compensation package, he received a sign-on bonus, a base salary, performance-based incentive of up to 100% of his annual salary and a housing and commuting allowance. Mr. Bird’s future incentive compensation is to be determined by the Board. Mr. Bird is also entitled to participate in our benefit plans available to executives, including, among other things, health, retirement, disability and life insurance benefits. The agreement also provides for severance if Mr. Bird is terminated for any reason other than Cause.

Environmental Liabilities

We are subject to numerous state and federal environmental regulations. Because laws and regulations applicable to our businesses are continually developing and are subject to amendment, reinterpretation and varying degrees of enforcement, we may be subject to, but can not predict with certainty the nature and amount of future environmental liabilities. The Clean Air Act Amendments of 1990 (the Act) stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We believe we can comply with such sulfur dioxide emission requirements at the generating plants serving our South Dakota operations and that we are in compliance with all presently applicable environmental protection requirements and regulations with respect to these plants. We also are subject to other environmental statutes and regulations including those that relate to former manufactured gas plant sites and other past and present operations and facilities. In addition, we may be subject to financial liabilities related to the investigation and remediation from activities of previous owners or operators of our industrial and generating facilities. The range of exposure for environmental remediation obligations at present is estimated to range between $45.3 million to $84.1 million. Our environmental reserve accrual is $45.3 million as of December 31, 2004 and October 31, 2004.

Our subsidiary, CFB owns the Milltown Dam hydroelectric facility, a two megawatt generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’s formal Record of Decision issued on December 20, 2004). In light of this announcement, we commenced negotiations with the Atlantic Richfield Company or Atlantic Richfield, to prevent a challenge from Atlantic Richfield to our statutorily exempt status under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) as a potentially responsible party. On September 10, 2003, we executed a confidential settlement agreement with Atlantic Richfield which, among other things, capped our maximum contribution towards remediation of the Milltown Reservoir superfund site. A motion to approve the settlement agreement with Atlantic Richfield was filed with the Bankruptcy Court on October 17, 2003. On April 7, 2004 we entered into a stipulation

F-46

(Stipulation) with Atlantic Richfield, the EPA, the Department of the Interior, the State of Montana and the Confederated Salish and Kootenai Tribes (collectively the Government Parties), which is intended to resolve both our liability with Atlantic Richfield in general accordance with the previously negotiated settlement agreement and establish a framework to resolve our liability with the Government Parties for their claims, including natural resource restoration claims, against NorthWestern as they relate to remediation of the Milltown Site. The Stipulation caps NorthWestern’s and CFB’s collective liability to Atlantic Richfield and the Government Parties at $11.4 million. On June 22, 2004 the Bankruptcy Court approved the Stipulation and the funding of the Atlantic Richfield settlement, as modified by the Stipulation. The amount of the stipulated liability has been fully accrued in the accompanying financial statements. Pursuant to the Stipulation, commencing in August 2004 and each month thereafter, we pay $500,000 alternately into two escrow accounts, one for the State of Montana and one for Atlantic Richfield, until the total agreed amount is funded. No interest will accrue on the unpaid balance due, and the escrow accounts will remain funded until a final, nonappealable consent decree is entered by the United States District Court. If, however, a consent decree (i) is not executed by the relevant parties, (ii) is not approved by the United States District Court, or (iii) does not become fully effective, then all funds in the escrow accounts will continue to be held in trust pending further court order. The Stipulation incorporates appropriate releases and indemnifications from Atlantic Richfield under the previously negotiated settlement agreement. There can be no assurance that the settlement set forth in the Stipulation will become effective, as the parties to this matter continue to negotiate the terms and conditions of the consent decree.

Legal Proceedings

F-47

F-48

Arthur Laufer v. Merle Lewis, et al. was transferred to the District of South Dakota and consolidated with the consolidated actions pending in that court. In September 2003, Sanford & Beatrice Golman Family Trust, et al. v. NorthWestern Corp., et al. was also transferred to the District of South Dakota and consolidated with the consolidated actions. In February 2004, the Golman Family Trust action was also consolidated with the actions pending in that court. The actions have been stayed as to NorthWestern Corporation due to its bankruptcy filing. In October 2003, Expanets, Blue Dot, and certain of NorthWestern’s present and former officers and directors filed motions to dismiss the consolidated amended class action complaint for failure to state a claim, which are currently pending in the District of South Dakota.

F-49

predict the impact or resolution of the appeals and our motion to dismiss, we intend to vigorously prosecute our dismissal motion and defend against the appeals as noted.

F-50

plaintiffs in the class action lawsuit entitled McGreevey, et al v. Montana Power Company, et al received approval in our bankruptcy case to initiate similar adversary proceedings. Under the terms of the settlement with the plaintiffs in the McGreevey case discussed below, they would not file such proceeding.) On April 19, 2004, Magten also filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for breaches of fiduciary duties by such officers. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. On February 9, 2005 we agreed to settlement terms with Magten and Law Debenture to release all claims, including Magten and Law Debenture’s fraudulent conveyance action pending against each other for Magten and Law Debenture receiving the distribution of new common stock and warrants from Class 8(b) in the same amounts as if they had voted to accept the Plan and a distribution from Class 9 of new common stock in the amount of approximately $17.4 million. Prior to seeking approval from the Bankruptcy Court, certain major shareholders and the Plan Committee objected to the settlement on both its economic terms and asserting that the structure of the settlement violated the Plan. After reviewing the objections and undertaking our own analysis of the potential Plan violation, we informed Magten and Law Debenture as well as the Plan Committee and the objecting major shareholders that we would not proceed with the settlement. Magten and Law Debenture have filed a motion with our Bankruptcy Court seeking approval of the settlement. A hearing was held on such motion on March 8, 2005. The Bankruptcy Court took this matter under advisement and entered an order denying the motion filed by Magten and Law Debenture on March 10, 2005. At this time, we cannot predict the impact of the resolution of any of these lawsuits or reasonably estimate a range of possible loss, which could be material. The resolution of these lawsuits could harm our business and have a material adverse impact on our financial condition. We intend to vigorously defend against the adversary proceeding and any subsequently filed similar litigation. The plaintiffs’ claims with respect to the QUIPs Litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we established with respect to the Class 9 disputed claims reserve under the plan of reorganization.

F-51

several conditions, including approval of the proposed settlement by the Bankruptcy Court in our bankruptcy proceeding, and approval of the proposed settlement by the Federal District Court for the District of Montana, where the class actions are pending. We cannot predict the ultimate outcome of this litigation in the event that the settlement is not approved, or does not take effect for any other reason. If for any reason the settlement is not approved, then we intend to vigorously defend against this lawsuit. If we are unsuccessful in defending against this class action lawsuit, the plaintiffs’ litigation claims would be subordinated to our other debt under our Plan, and such claims would be treated as securities, or Class 14, claims under our plan of reorganization, and would be entitled to no recovery against NorthWestern under our Plan. Claims by our current and former officers and directors (and the former officers and directors of The Montana Power Company) for indemnification for these proceedings would be channeled into the Directors and Officers Trust established by the Plan. The plaintiffs could elect to proceed directly against CFB and the assets owned by such entity, which as of December 31, 2004 were not material to our operations or financial position. We cannot currently predict the impact or resolution of this litigation or reasonably estimate a range of possible loss, which could be material, and the resolution of this lawsuit may harm our business and have a material adverse impact on our financial condition.

In NorthWestern Corporation vs. PPL Montana, LLC vs. NorthWestern Corporation and Clark Fork and Blackfoot, LLC, No. CV-02-94-BU-SHE, (D. MT), we are pursuing claims against PPL Montana, LLC (PPL) due to its refusal to purchase the Colstrip transmission assets under the Asset Purchase Agreement (APA) executed by and between The Montana Power Company (MPC) and PP&L Global, Inc. (PPL Global). NorthWestern claims PPL (PPL Global’s successor-in-interest under the APA) is required to purchase the Colstrip transmission assets for $97.1 million. PPL has also asserted a number of counterclaims against NorthWestern and CFB based in large part upon PPL’s claim that MPC and/or NorthWestern Energy breached two Wholesale Transition Service Agreements and certain indemnification obligations under the APA in the approximate amount of $120 million. PPL also filed a proof of claim and an amended proof of claim against NorthWestern’s bankruptcy estate which asserts substantially the same claims as the PPL counterclaim. PPL moved the Bankruptcy Court for relief from the automatic stay to pursue its counterclaims. NorthWestern objected to PPL’s motion to lift the automatic stay and has also filed a motion to transfer the venue of the entire litigation to the United States District Court for the District of Delaware. On March 19, 2004 the federal court in Montana denied our motion to transfer the entire case. Thereafter, our Bankruptcy Court transferred all the claims for resolution to the federal court in Montana. We intend to vigorously defend against the PPL claims in federal court as well as vigorously prosecute our claims against PPL. We cannot currently predict the impact or resolution of the claims or this litigation or reasonably estimate a range of possible loss on the counterclaims, which could be material to the disputed claims reserve. PPL’s counterclaims with respect to this litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the share reserve that we established with respect to the Class 9 disputed claims reserve under the plan of reorganization.

F-52

We, and certain of our former officers and directors, were named as defendants in certain complaints filed against CornerStone Propane Partners, LP and other defendants purporting to be class actions filed in the United States District Court for the Northern District of California by purchasers of units of CornerStone Propane Partners alleging violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. Through November 1, 2002, we held an economic equity interest in a subsidiary that serves as the managing general partner of CornerStone Propane Partners, LP. Certain former officers and directors of NorthWestern who are named as defendants in certain of these actions have also been sued in their capacities as directors of the managing general partner. These complaints allege that defendants sold units of CornerStone Propane Partners based upon false and misleading statements and failed to disclose material information about CornerStone Propane Partners’ financial condition and future prospects, including overpayment for acquisitions, overstating earnings and net income, and that it lacked adequate internal controls. All of the lawsuits have now been consolidated and Gilbert H. Lamphere has been named as lead plaintiff. The actions have been stayed as to NorthWestern due to its bankruptcy filing. On October 27, 2003, the plaintiffs filed an amended consolidated class action complaint. The new complaint does not name NorthWestern as a defendant, although it alleges facts relating to NorthWestern’s conduct. Certain of our former officers and directors are named as defendants in the amended consolidated complaint. The plaintiffs seek compensatory damages, prejudgment and postjudgment interest and costs, injunctive relief, and other relief. On November 6, 2003, the Bankruptcy Court entered an order approving a stipulation between NorthWestern and plaintiffs in this litigation. The stipulation provides that litigation as against NorthWestern shall be temporarily stayed for 180 days from the date of the stipulation. The stay has been extended. Pursuant to the stipulation and after providing notice to NorthWestern, the plaintiffs may move the Bankruptcy Court for termination of the temporary stay. On March 2, 2004, the plaintiffs filed a corrected consolidated amended complaint against CornerStone and the individual defendants, which also did not name NorthWestern. In June 2004, CornerStone Propane Partners, LP along with its subsidiaries and affiliates filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. As a result of that filing this case is now stayed against CornerStone Propane Partners and other named subsidiaries and affiliates. If we are named in the lawsuit, we intend to vigorously defend any claims asserted against us by these lawsuits. To the extent such claims are prepetition claims, such claims would be extinguished under the confirmation order. If the claims are not extinguished, the plaintiffs’ claims with respect to this litigation would be treated as securities, or Class 14, claims and would be entitled to no recovery under the plan of reorganization. Any claims in this litigation for indemnification from our officers and directors, would be channeled into the Directors and Officers Trust to the extent that they are indemnification claims.

F-53

On April 30, 2003, Mr. Richard Hylland, our former President and Chief Operating Officer, filed a demand for arbitration of contract claims under his employment agreement, as well as tort claims for defamation, infliction of emotional distress and tortious interference and a claim for punitive damages. Mr. Hylland is seeking relief in the amount of $25 million, plus interest, attorney’s fees, costs, and punitive damages. Mr. Hylland has also filed claims in our bankruptcy case similar to the claims in his arbitration demand. We dispute Mr. Hylland’s claims and intend to vigorously defend the arbitration and object to Mr. Hylland’s claims in our bankruptcy case. On May 6, 2003, based on the recommendations of the Special Committee of the NorthWestern Board of Directors formed to evaluate Mr. Hylland’s performance and conduct in connection with the management of NorthWestern and its subsidiaries, the Board determined that Mr. Hylland’s performance and conduct as President and Chief Operating Officer warranted termination under his employment contract. This arbitration will proceed under the terms of the order confirming the Plan, and we have obtained a timetable from the arbitrator. Mr. Hylland’s claims with respect to this proceeding would be treated as unsecured general, or Class 9, claims and would be satisfied out of the share reserve that we have established.

F-54

Wayne Belnavis and David Daniels v. Avaya, Expanets, NorthWestern et al., Supreme Court of the State of New York, Bronx County, Index No. 8729-04, two former employees of Expanets seek damages in the amount of $12,500,000, plus interest, penalties, punitive damages, costs, and attorney’s fees. Avaya Inc. has sent NorthWestern and subsidiaries a notice seeking indemnification and defense for these lawsuits under the asset purchase agreement. We have responded by accepting in part and rejecting in part the indemnification request. As a result of the Netexit bankruptcy, the cases were removed to federal court in New York and Netexit was dismissed from the lawsuit. NorthWestern and Avaya were dismissed as defendants by the plaintiffs. These claims against Netexit will be subject to the claims process of the Netexit bankruptcy proceeding. We intend to vigorously defend against the allegations made in these claims. We cannot currently predict the impact or resolution of these claims or reasonably estimate a range of possible loss.

F-55

monitoring the process. WECO has asserted that any potential judgment would be considered a pass-through cost under the coal supply agreement. Based on our review, we do not believe any potential judgment would qualify as a pass-through cost under the terms of the coal supply agreement. Neither the outcome of this matter nor the associated costs can be predicted at this time.

Each year we submit a natural gas tracker filing for recovery of natural gas costs. The MPSC reviews such filings and makes a determination as to whether or not our natural gas procurement activities were prudent. If the MPSC finds that we have not exercised prudence, it can disallow such costs. For the tracker period ending June 30, 2003, the MPSC issued a final order relating to that period, which included a disallowance of $6.2 million of natural gas costs. We filed a motion for reconsideration regarding the disallowance of purchased natural gas cost with the MPSC on July 14, 2003, which was denied. Since we believe that the natural gas procurement activities in question were not imprudent we filed suit in district court on July 28, 2003, seeking to overturn the MPSC’s decision to disallow recovery of these costs. At this time, this matter has been suspended pending settlement discussions with the MPSC.

Disputed Claims Reserve

Upon consummation of our plan of reorganization, we established a reserve of approximately 4.4 million shares of common stock from the shares allocated to holders of our trade vendor claims in excess of $20,000 and holders of Class 9 unsecured claims. The shares held in this reserve may be used to resolve various outstanding unsecured claims and unliquidated litigation claims, as these claims were not resolved or deemed allowed upon consummation of our plan of reorganization. If these claims ultimately exceed the reserve, then such claimants could request the bankruptcy court to amend our plan of reorganization to allow for payment of the claims in excess of the reserve. We have surrendered control over the common stock provided and the shares reserve is administered by our transfer agent; therefore we recognized the issuance of the common stock upon emergence. If excess shares remain in the reserve after satisfaction of all obligations, such amounts would be reallocated pro rata to the allowed Class 7 and 9 claimants.

(22) Capital Stock

The Predecessor Company’s Plan became effective and the Predecessor Company emerged from bankruptcy on November 1, 2004. The Predecessor Company applied fresh-start reporting effective October 31, 2004 and, as a result, reflected all shares of NorthWestern Corporation common stock as cancelled in accordance with the Plan.

Successor Company

The Successor Company is a Delaware corporation and filed a new certificate of incorporation (New Articles). The New Articles authorized 250,000,000 shares consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. As a result of the Predecessor Company’s emergence from bankruptcy, the Successor Company issued 35,500,000 shares of common stock in settlement of claims. Pursuant to the Plan, such stock had an agreed value of $710.0 million. Accordingly, the Successor Company recorded common stock and additional paid-in capital of $355,000 and $709.6 million, respectively, in the Consolidated Balance Sheet as of October 31, 2004. In addition, the Plan reserved 2,265,957 shares of new common stock for the New Incentive Plan, of which 228,315 shares were issued for Special Recognition Grants (see Note 17).

In addition, concurrent with our emergence from bankruptcy we issued 4,620,333 warrants, each entitling the holder thereof to purchase one share of common stock, to certain holders of class 8(a) and 8(b) claims in settlement of their allowed claim. These warrants are exercisable from November 1, 2004

F-56

through November 1, 2007 at a strike price of $28.48. We recognized $3.8 million of expense associated with these warrants as a reduction of cancellation of indebtedness income.

(23) Segment and Related Information

We currently operate our business in five reporting segments: (i) electric utility operations, (ii) natural gas utility operations, (iii) unregulated electric, (iv) unregulated natural gas, and (v) all other, which primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments. Items below operating income are not allocated between our electric and natural gas segments.

The results of operations of our electric and natural gas utility segments and all other operations for the year ended December 31, 2002, include the results of our Montana operations since February 1, 2002, the effective date of our acquisition. The operations of Expanets, Blue Dot and CornerStone, which were formerly additional reporting segments, and our interest in these subsidiaries has been reflected in the consolidated financial statements as Discontinued Operations (see Note 9 for further discussion).

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

Successor Company
Two-month period ended	Utility				Unregulated
December 31, 2004	Electric		Gas		Electric		Gas		Other			Eliminations				Total
Operating revenues	$	99,564	$	76,185	$	16,148	$	30,401	$	346			$	(16,692	)	$	205,952
Cost of sales	48,378		51,450		4,561		28,513		265				(16,392		)	116,775
Gross margin	51,186		24,735		11,587		1,888		81				(300		)	89,177
Operating, general and administrative	17,550		8,917		8,030		302		1,459				(300		)	35,958
Property and other taxes	7,453		2,755		543		12		3				—			10,766
Depreciation	9,274		2,422		203		67		208				—			12,174
Reorganization items	—		—		—		—		437				—			437
Impairment on assets held for sale	—		—		—		—		10,000				—			10,000
Operating income (loss)	16,909		10,641		2,811		1,507		(12,026		)		—			19,842
Total assets	$	1,488,329	$	700,491	$30,080		$	76,101	$	47,387			$	—		$2,342,388
Capital expenditures	$	14,493	$	2,935	$	264	$	28	$	3			$	—		$	17,723

Predecessor Company
10-month period ended	Utility				Unregulated
October 31, 2004	Electric		Gas		Electric		Gas		Other			Eliminations				Total
Operating revenues	$	472,359	$	235,506	$	72,546	$	106,604	$	1,910			$	(55,888	)	$	833,037
Cost of sales	224,243		153,754		22,380		99,734		1,367				(54,424		)	447,054
Gross margin	248,116		81,752		50,166		6,870		543				(1,464		)	385,983
Operating, general and administrative	95,389		43,990		42,797		2,490		2,580				(1,464		)	185,782
Property and other taxes	38,832		13,440		2,000		57		40				—			54,369
Depreciation	46,186		11,916		1,015		313		1,244				—			60,674
Reorganization items	—		—		—		—		(533,063		)		—			(533,063		)
Operating income	67,709		12,406		4,354		4,010		529,742				—			618,221
Total assets	$	1,540,923	$	725,245	$	36,959	$	68,816	$	71,365			$	—		$	2,443,308
Capital expenditures	$	40,884	$	17,183	$	4,020	$	288	$	16			$	—		$	62,391

F-57

Predecessor Company	Utility				Unregulated
2003	Electric		Gas		Electric			Gas		Other			Eliminations				Total
Operating revenues	$	601,646	$	279,062	$	69,858		$	100,757	$	3,034			$	(41,842	)	$	1,012,515
Cost of sales	287,137		175,011		22,767			88,631		2,337				(40,216		)	535,667
Gross margin	314,509		104,051		47,091			12,126		697				(1,626		)	476,848
Operating, general and administrative	83,786		55,822		53,865			3,055		44,814				(1,626		)	239,716
Property and other taxes	47,186		17,041		3,050			47		218				—			67,542
Depreciation	53,841		13,909		614			161		1,727				—			70,252
Reorganization items	—		—		—			—		8,266				—			8,266
Impairment on assets held for sale	—		—		—			—		12,399				—			12,399
Operating income (loss)	129,696		17,279		(10,438		)	8,863		(66,727		)		—			78,673
Total assets	$	1,477,661	$	695,470	$	14,577		$	73,275	$	89,363			$	—		$	2,350,346
Capital expenditures	$	36,413	$	21,235	$	4,146		$	8,859	$	84			$	—		$	70,737

Predecessor Company	Utility				Unregulated
2002	Electric		Gas		Electric			Gas		Other			Eliminations				Total
Operating revenues	$	476,611	$	201,935	$	62,720		$	71,325	$	3,144			$	(31,991	)	$	783,744
Cost of sales	189,836		99,777		19,730			60,292		2,564				(30,673		)	341,526
Gross margin	286,775		102,158		42,990			11,033		580				(1,318		)	442,218
Operating, general and administrative	90,137		45,379		41,170			3,051		34,890				(1,318		)	213,309
Property and other taxes	36,633		15,045		3,073			29		129				—			54,909
Depreciation	48,255		12,533		633			90		1,729				—			63,240
Amortization of intangibles	—		—		—			—		19				—			19
Impairment on assets held for sale	—		—		—			—		35,729				—			35,729
Operating income (loss)	111,750		29,201		(1,886		)	7,863		(71,916		)		—			75,012
Total assets	$	1,456,721	$	685,516	$	44,580		$	61,608	$	96,117			$	—		$	2,344,542
Capital expenditures	$	95,623	$	22,007	$	1,706		$	264	$	28,247			$	—		$	147,847

F-58

(24) Quarterly Financial Data (Unaudited)

The following table sets forth certain unaudited financial data for each of the quarters within fiscal 2004 and 2003. During the second quarter of 2003 we committed to a plan to sell or liquidate our interest in Netexit and Blue Dot and accounted for our interest in these subsidiaries as discontinued operations. Accordingly, the amounts below have been restated to reflect these subsidiaries as discontinued operations. The operating results for any quarter are not necessarily indicative of results for any future period. Amounts presented are in thousands, except per share data:

	Predecessor Company															Successor Company
	Quarter Ended 2004											One-Month Ended October 1- October 31,		Total through October 31,		Two-Months Ended November 1- December 31,
2004	March 31(1)				June 30(1)			September 30(1)				2004(2)		2004		2004
	(in thousands except per share amounts)
Operating revenues, as previously reported		$	339,611		$232,961				$	248,922
Less: adjustments to revenues		(33,984		)	(15,134		)		(19,492		)
Operating revenues, as revised		$	305,627		$	217,827			$229,430			$	80,153	$	833,037		$	205,952
Gross margin		132,709			103,333				112,765			37,176		385,983			89,177
Operating income (loss)		32,995			7,146				(4,974		)	583,054		618,221			19,842
Net income (loss)		$	16,981		$	(4,800	)		$	(29,567	)	$	568,763	$	551,377		$	(6,944	)
Average common shares outstanding																	35,614
Loss per average common share (basic and diluted):
Net loss from continuing operations																	$	(0.18	)
Discontinued operations																	(0.01		)
Net loss																	(0.19		)
Loss on common stock																	(0.19		)
Dividends per share
Stock price:
High																	$	28.00
Low																	24.82
Quarter-end close																	28.00

2003 Predecessor Company	First			Second			Third			Fourth(1)
	(in thousands)
Operating revenues, as previously reported		$	288,723	$	235,529		$	235,388		$267,797
Less: adjustments to revenues										(14,922		)
Operating revenues, as revised										$	252,875
Gross margin		133,564		106,231			114,302			122,751
Operating income		43,026		1,342			17,527			16,778
Net income (loss)		$	17,392	$	(50,337	)	$	(52,740	)	$	(28,040	)

(1) In accordance with EITF 03-11 “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and not “Held for Trading Purposes” as defined in Issue No. 02-3”, which was effective beginning with the 4th quarter of 2003, the Predecessor Company has revised revenues downward from amounts previously reported for the first three quarters of 2004 and the fourth quarter of 2003, to report revenue net versus gross for certain regulated electric and gas

F-59

contracts that did not physically deliver. These revenue revisions did not impact gross margin, operating income (loss) or net income (loss) as previously reported. These revenue revisions were determined to not be material to the predecessor financial statements for 2003 and the first three quarters of 2004.

(2) The month ended October 31, 2004 includes a cumulative loss of $2.8 million ($1.7 million after tax) related to unregulated natural gas operations on three long-term fixed price contracts. Of the $1.7 million loss recorded, $0.8 million relates to the first three quarters of 2004, $0.4 million relates to 2003 and the balance of the adjustment relates to 2002. Prior periods have not been restated because the amount of the loss was immaterial to any respective prior period and the period in which the correction was made.

F-60

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
NORTHWESTERN CORPORATION AND SUBSIDIARIES

Column A	Column B			Column C				Column D			Column E
Description	Balance at Beginning of Period			Charged to Costs and Expenses		Charged to Other Accounts(1)		Deductions(2)			Balance End of Period
FOR THE TWO-MONTHS ENDED DECEMBER 31, 2004 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts		$	2,073		138		—		(107	)		2,104
FOR THE 10-MONTHS ENDED OCTOBER 31, 2004 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts		$	1,976		2,163		—		(2,066	)		$	2,073
FOR THE YEAR ENDED DECEMBER 31, 2003 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts		$	1,837		5,010		—		(4,871	)		$	1,976
ACCRUED EXPENSES
Restructuring liability		$	1,783		—		—		(1,783	)		—
FOR THE YEAR ENDED DECEMBER 31, 2002 (in thousands)
RESERVES DEDUCTED FROM APPLICABLE ASSETS
Uncollectible accounts		$	444		3,883		1,675		(4,165	)		$	1,837
ACCRUED EXPENSES
Restructuring liability		$	10,401		—		—		(8,618	)		$	1,783

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

(2) Utilization of previously recorded balances.

F-61

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

		Page
Part I.
Item 1.	Business	6
Item 2.	Properties	28
Item 3.	Legal Proceedings	28
Item 4.	Submission of Matters to a Vote of Security Holders	37
Part II.
Item 5.	Market for Registrant’s Common Equity and Related Shareholder Matters	38
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	76
Item 8.	Financial Statements and Supplementary Data	77
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	77
Item 9A.	Controls and Procedures	77
Part III.
Item 10.	Directors and Executive Officers of the Registrant	80
Item 11.	Executive Compensation	83
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	90
Item 13.	Certain Relationships and Related Transactions	91
Item 14.	Principal Accountants Fees and Services	91
Part IV.
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	92
Signatures		98
Index to Financial Statements		F-1

Fee Category	Fiscal 2004 Fees		Fiscal 2003 Fees
Audit fees	$	2,736,000	$	2,300,000
Audit-related fees	101,000		101,000
Tax fees	2,216,000		1,987,000
All other fees	—		—
Total fees	$	5,053,000	$4,388,000

	NORTHWESTERN CORPORATION
Dated: March 14, 2005	By:	/s/ GARY G. DROOK
		Gary G. Drook
		President and Chief Executive Officer

	Signature		Title		Date
/s/ DR. E. LINN DRAPER JR.		Chairman of the Board		March 14, 2005
Dr. E. Linn Draper, Jr.
/s/ GARY G. DROOK		President and Chief Executive Officer and Director		March 14, 2005
Gary G. Drook		(Principal Executive Officer)
/s/ BRIAN B. BIRD		Chief Financial Officer		March 14, 2005
Brian B. Bird		(Principal Financial Officer)
/s/ KENDALL G. KLIEWER		Controller		March 14, 2005
Kendall G. Kliewer		(Principal Accounting Officer)
/s/ CORBIN A. MCNEILL, JR.		Director		March 14, 2005
Corbin A. McNeill, Jr.
/s/ STEPHEN P. ADIK		Director		March 14, 2005
Stephen P. Adik

	(Title of each class)			(Name of each exchange on which registered)
None			None

	Amount and Nature of Beneficial Ownership(1)		Percent of
Name of Beneficial Owner	Shares of Common Stock Beneficially Owned		Common Stock
Harbert Distressed Investment Master Fund Ltd. c/o International Fund Services Third Fl Bishop Square Redmonds Hill Dublin, Ireland		8,743,790		20.9	%
Fortress Investments Group LLC 1251 Avenue of the Americas, Suite 1600 New York, NY 10020		1,902,280		5.3
Franklin Mutual Advisors, LLC 51 John F. Kennedy Parkway Short Hills, NJ 07078		1,883,043		5.3
MSD Capital Management LLC 645 Fifth Avenue, 21^st Floor New York, NY 10022		1,849,054		5.2
Stephen P. Adik		—		—
Dr. E. Linn Draper, Jr.		—		—
Jon S. Fossel		—		—
Julia L. Johnson		—		—
Philip L. Maslowe		—		—
Corbin A. McNeill, Jr.		—		—
Gary G. Drook		51,480			*
Michael J. Hanson		17,860			*
Brian B. Bird		10,720			*
Roger P. Schrum		5,400			*
Thomas J. Knapp		2,650			*
All directors and executive officers		88,110			*

/s/ JULIA L. JOHNSON	Director	March 14, 2005
Julia L. Johnson
/s/ JON S. FOSSEL	Director	March 14, 2005
Jon S. Fossel
/s/ PHILIP L. MASLOWE	Director	March 14, 2005
Philip L. Maslowe

		Page
Financial Statements
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated statements of income (loss) for the two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 and years ended December 31, 2003, and 2002 (Predecessor Company)		F-6
Consolidated statements of cash flows for the two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 and years ended December 31, 2003, and 2002 (Predecessor Company)		F-7
Consolidated balance sheets as of December 31, 2004 (Successor Company), October 31, 2004 (Successor Company) and December 31, 2003 (Predecessor Company)		F-8
Consolidated statements of common shareholders’ equity (deficit) for the two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 (Successor Company) and years ended December 31, 2003, and 2002 (Predecessor Company)		F-9
Notes to consolidated financial statements		F-11
Financial Statement Schedules
Schedule II. Valuation and Qualifying Accounts		F-61

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 11, 2005

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota March 11, 2005

	Successor Company December 31, 2004
Basic computation		35,614,158
Dilutive effect of
Restricted shares		114,157
Stock warrants		—
Diluted computation		35,728,315

	Gross obligation		Recoverable amounts		Net
2005	$	54,347	(52,061	)	$	2,286
2006	56,175		(52,061	)	4,114
2007	58,284		(52,567	)	5,717
2008	60,537		(53,060	)	7,477
2009	62,656		(53,583	)	9,073
Thereafter	1,406,260		(1,067,032	)	339,228
Total	$	1,698,259	$(1,330,364	)	$	367,895

Part III.